Pacific Gas & Electric (PCG+A) 10-K 28 Feb 19 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 30, 2018
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Trading Symbol	PCG
Entity Registrant Name	PG&E CORP
Entity Central Index Key	1,004,980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		527,561,429
Entity Public Float			$ 22,620
Pacific Gas & Electric Co
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Trading Symbol	PCG
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	75,488
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		264,374,809

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues
Total operating revenues	$ 16,759	$ 17,135	$ 17,666
Operating Expenses
Operating and maintenance	7,153	6,321	7,326
Wildfire-related claims, net of insurance recoveries	11,771	0	125
Depreciation, amortization, and decommissioning	3,036	2,854	2,755
Total operating expenses	26,459	14,230	15,586
Operating Income (Loss)	(9,700)	2,905	2,080
Interest income	76	31	23
Interest expense	(929)	(888)	(829)
Other income, net	424	123	188
Income (Loss) Before Income Taxes	(10,129)	2,171	1,462
Income tax provision (benefit)	(3,292)	511	55
Net Income (Loss)	(6,837)	1,660	1,407
Preferred stock dividend requirement of subsidiary	14	14	14
Income (Loss) Available for Common Shareholders	$ (6,851)	$ 1,646	$ 1,393
Weighted Average Common Shares Outstanding, Basic (in shares)	517	512	499
Weighted Average Common Shares Outstanding, Diluted (in shares)	517	513	501
Net Earnings (Loss) Per Common Share, Basic (in dollars per share)	$ (13.25)	$ 3.21	$ 2.79
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share)	$ (13.25)	$ 3.21	$ 2.78
Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	$ 16,760	$ 17,138	$ 17,667
Operating Expenses
Operating and maintenance	7,153	6,383	7,327
Wildfire-related claims, net of insurance recoveries	11,771	0	125
Depreciation, amortization, and decommissioning	3,036	2,854	2,754
Total operating expenses	26,459	14,292	15,586
Operating Income (Loss)	(9,699)	2,846	2,081
Interest income	74	30	22
Interest expense	(914)	(877)	(819)
Other income, net	426	119	188
Income (Loss) Before Income Taxes	(10,113)	2,118	1,472
Income tax provision (benefit)	(3,295)	427	70
Net Income (Loss)	(6,818)	1,691	1,402
Preferred stock dividend requirement	14	14	14
Income (Loss) Available for Common Shareholders	(6,832)	1,677	1,388
Electric
Operating Revenues
Total operating revenues	12,713	13,124	13,864
Operating Expenses
Cost of goods	3,828	4,309	4,765
Electric | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	12,713	13,127	13,865
Operating Expenses
Cost of goods	3,828	4,309	4,765
Natural gas
Operating Revenues
Total operating revenues	4,046	4,011	3,802
Operating Expenses
Cost of goods	671	746	615
Natural gas | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	4,047	4,011	3,802
Operating Expenses
Cost of goods	$ 671	$ 746	$ 615

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net Income (Loss)	$ (6,837)	$ 1,660	$ 1,407
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes)	4	1	(2)
Total other comprehensive income (loss)	4	1	(2)
Comprehensive Income (Loss)	(6,833)	1,661	1,405
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income (Loss) Attributable to Common Shareholders	(6,847)	1,647	1,391
Pacific Gas & Electric Co
Net Income (Loss)	(6,818)	1,691	1,402
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes)	(5)	4	(1)
Total other comprehensive income (loss)	(5)	4	(1)
Comprehensive Income (Loss)	$ (6,823)	$ 1,695	$ 1,401

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension and other postretirement benefit plans obligations, tax	$ 2	$ 0	$ 1
Net change in investments, tax	0	0	0
Pacific Gas & Electric Co
Pension and other postretirement benefit plans obligations, tax	$ 2	$ 3	$ 1

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 1,668	$ 449
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $64 at respective dates)	1,148	1,243
Accrued unbilled revenue	1,000	946
Regulatory balancing accounts	1,435	1,222
Other	2,686	861
Regulatory assets	233	615
Inventories
Gas stored underground and fuel oil	111	115
Materials and supplies	443	366
Income taxes receivable	23	0
Other	448	464
Total current assets	9,195	6,281
Property, Plant, and Equipment
Electric	59,150	55,133
Gas	21,556	19,641
Construction work in progress	2,564	2,471
Other	2	3
Total property, plant, and equipment	83,272	77,248
Accumulated depreciation	(24,715)	(23,459)
Net property, plant, and equipment	58,557	53,789
Other Noncurrent Assets
Regulatory assets	4,964	3,793
Nuclear decommissioning trusts	2,730	2,863
Income taxes receivable	69	65
Other	1,480	1,221
Total other noncurrent assets	9,243	7,942
TOTAL ASSETS	76,995	68,012
Current Liabilities
Short-term borrowings	3,435	931
Long-term debt, classified as current	18,559	445
Accounts payable
Trade creditors	1,975	1,646
Regulatory balancing accounts	1,076	1,120
Other	464	517
Disputed claims and customer refunds	220	243
Interest payable	228	217
Wildfire-related claims	14,226	561
Other	1,512	1,449
Total current liabilities	41,695	7,129
Noncurrent Liabilities
Long-term debt	0	17,753
Regulatory liabilities	8,539	8,679
Pension and other postretirement benefits	2,119	2,128
Asset retirement obligations	5,994	4,899
Deferred income taxes	3,281	5,822
Other	2,464	2,130
Total noncurrent liabilities	22,397	41,411
Contingencies and Commitments (Notes 13 and 14)
Shareholders' Equity
Common stock, no par value	12,910	12,632
Reinvested earnings	(250)	6,596
Accumulated other comprehensive loss	(9)	(8)
Total shareholders' equity	12,651	19,220
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	12,903	19,472
TOTAL LIABILITIES AND EQUITY	76,995	68,012
Pacific Gas & Electric Co
Current Assets
Cash and cash equivalents	1,295	447
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $64 at respective dates)	1,148	1,243
Accrued unbilled revenue	1,000	946
Regulatory balancing accounts	1,435	1,222
Other	2,688	862
Regulatory assets	233	615
Inventories
Gas stored underground and fuel oil	111	115
Materials and supplies	443	366
Income taxes receivable	5	0
Other	448	465
Total current assets	8,806	6,281
Property, Plant, and Equipment
Electric	59,150	55,133
Gas	21,556	19,641
Construction work in progress	2,564	2,471
Total property, plant, and equipment	83,270	77,245
Accumulated depreciation	(24,713)	(23,456)
Net property, plant, and equipment	58,557	53,789
Other Noncurrent Assets
Regulatory assets	4,964	3,793
Nuclear decommissioning trusts	2,730	2,863
Income taxes receivable	66	64
Other	1,348	1,094
Total other noncurrent assets	9,108	7,814
TOTAL ASSETS	76,471	67,884
Current Liabilities
Short-term borrowings	3,135	799
Long-term debt, classified as current	18,209	445
Accounts payable
Trade creditors	1,972	1,644
Regulatory balancing accounts	1,076	1,120
Other	498	538
Disputed claims and customer refunds	220	243
Interest payable	227	214
Wildfire-related claims	14,226	561
Other	1,497	1,457
Total current liabilities	41,060	7,021
Noncurrent Liabilities
Long-term debt	0	17,403
Regulatory liabilities	8,539	8,679
Pension and other postretirement benefits	2,026	2,026
Asset retirement obligations	5,994	4,899
Deferred income taxes	3,405	5,963
Other	2,492	2,146
Total noncurrent liabilities	22,456	41,116
Contingencies and Commitments (Notes 13 and 14)
Shareholders' Equity
Preferred stock	258	258
Common stock, no par value	1,322	1,322
Additional paid-in capital	8,550	8,505
Reinvested earnings	2,826	9,656
Accumulated other comprehensive loss	(1)	6
Total shareholders' equity	12,955	19,747
TOTAL LIABILITIES AND EQUITY	$ 76,471	$ 67,884

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Allowance for doubtful accounts	$ 56	$ 64
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	520,338,710	514,755,845
Pacific Gas & Electric Co
Allowance for doubtful accounts	$ 56	$ 64
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

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net Income (Loss)	$ (6,837)	$ 1,660	$ 1,407
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,036	2,854	2,755
Allowance for equity funds used during construction	(129)	(89)	(112)
Deferred income taxes and tax credits, net	(2,532)	1,254	1,030
Disallowed capital expenditures	(45)	47	507
Other	332	307	379
Effect of changes in operating assets and liabilities:
Accounts receivable	(121)	67	(473)
Wildfire-related insurance receivable	(1,698)	(21)	(575)
Inventories	(73)	(18)	(24)
Accounts payable	409	173	180
Wildfire-related claims	13,665	(129)	690
Income taxes receivable/payable	(23)	160	(5)
Other current assets and liabilities	(281)	42	83
Regulatory assets, liabilities, and balancing accounts, net	(800)	(387)	(1,214)
Other noncurrent assets and liabilities	(151)	57	(219)
Net cash provided by operating activities	4,752	5,977	4,409
Cash Flows from Investing Activities
Capital expenditures	(6,514)	(5,641)	(5,709)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,412	1,291	1,295
Purchases of nuclear decommissioning trust investments	(1,485)	(1,323)	(1,352)
Other	23	23	13
Net cash used in investing activities	(6,564)	(5,650)	(5,753)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	3,960	0	0
Repayments under revolving credit facilities	(775)	0	0
Net issuances (repayments) of commercial paper, net of discount	(182)	(840)	(9)
Short-term debt financing	600	750	500
Short-term debt matured	(750)	(500)	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs	793	2,713	983
Long-term debt matured or repurchased	(795)	(1,445)	(160)
Common stock issued	200	395	822
Common stock dividends paid	0	(1,021)	(921)
Other	(20)	(107)	(44)
Net cash provided by (used in) financing activities	3,031	(55)	1,171
Net change in cash, cash equivalents, and restricted cash	1,219	272	(173)
Cash, cash equivalents, and restricted cash at January 1	456	184	357
Cash, cash equivalents, and restricted cash at December 31	1,675	456	184
Less: Restricted cash and restricted cash equivalents	(7)	(7)	(7)
Cash and cash equivalents at December 31	1,668	449	177
Cash received (paid) for:
Interest, net of amounts capitalized	(786)	(790)	(726)
Income taxes, net	(49)	162	231
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	0	0	248
Capital expenditures financed through accounts payable	368	501	403
Noncash common stock issuances	0	21	20
Pacific Gas & Electric Co
Cash Flows from Operating Activities
Net Income (Loss)	(6,818)	1,691	1,402
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,036	2,854	2,754
Allowance for equity funds used during construction	(129)	(89)	(112)
Deferred income taxes and tax credits, net	(2,548)	1,103	1,042
Disallowed capital expenditures	(45)	47	507
Other	258	283	306
Effect of changes in operating assets and liabilities:
Accounts receivable	(122)	66	(475)
Wildfire-related insurance receivable	(1,698)	(21)	(575)
Inventories	(73)	(18)	(24)
Accounts payable	421	173	179
Wildfire-related claims	13,665	(129)	690
Income taxes receivable/payable	(5)	159	(29)
Other current assets and liabilities	(301)	59	112
Regulatory assets, liabilities, and balancing accounts, net	(800)	(390)	(1,214)
Other noncurrent assets and liabilities	(137)	128	(219)
Net cash provided by operating activities	4,704	5,916	4,344
Cash Flows from Investing Activities
Capital expenditures	(6,514)	(5,641)	(5,709)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,412	1,291	1,295
Purchases of nuclear decommissioning trust investments	(1,485)	(1,323)	(1,352)
Other	23	23	13
Net cash used in investing activities	(6,564)	(5,650)	(5,753)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	3,535	0	0
Repayments under revolving credit facilities	(650)	0	0
Net issuances (repayments) of commercial paper, net of discount	(50)	(972)	(9)
Short-term debt financing	250	750	500
Short-term debt matured	(750)	(500)	0
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs	793	2,713	983
Long-term debt matured or repurchased	(445)	(1,445)	(160)
Preferred stock dividends paid	0	(14)	(14)
Common stock dividends paid	0	(784)	(911)
Equity contribution from PG&E Corporation	45	455	835
Other	(20)	(93)	(30)
Net cash provided by (used in) financing activities	2,708	110	1,194
Net change in cash, cash equivalents, and restricted cash	848	376	(215)
Cash, cash equivalents, and restricted cash at January 1	454	78	293
Cash, cash equivalents, and restricted cash at December 31	1,302	454	78
Less: Restricted cash and restricted cash equivalents	(7)	(7)	(7)
Cash and cash equivalents at December 31	1,295	447	71
Cash received (paid) for:
Interest, net of amounts capitalized	(773)	(781)	(717)
Income taxes, net	(59)	162	244
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$ 368	$ 501	$ 403

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Financing Activities
Discount on net issuances of commercial paper	$ 1	$ 5	$ 6
Premium, discount, and issuance costs on proceeds from long-term debt	7	32	17
Pacific Gas & Electric Co
Cash Flows from Financing Activities
Discount on net issuances of commercial paper	0	5	6
Premium, discount, and issuance costs on proceeds from long-term debt	$ 7	$ 32	$ 17

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Pacific Gas & Electric Co	Preferred StockPacific Gas & Electric Co	Common Stock	Common StockPacific Gas & Electric Co	Additional Paid-in CapitalPacific Gas & Electric Co	Reinvested Earnings	Reinvested EarningsPacific Gas & Electric Co	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss)Pacific Gas & Electric Co	Total Shareholders' Equity	Total Shareholders' EquityPacific Gas & Electric Co	Non controlling Interest - Preferred Stock of Subsidiary
Balance, beginning of period (in shares) at Dec. 31, 2015				492,025,443
Beginning balance at Dec. 31, 2015	$ 16,828		$ 258	$ 11,282	$ 1,322	$ 7,215	$ 5,301	$ 8,262	$ (7)	$ 3	$ 16,576	$ 17,060	$ 252
Net Income (Loss)	1,407	$ 1,402					1,407	1,402			1,407	1,402
Other comprehensive income (loss)	(2)	(1)					0		(2)	(1)	(2)	(1)
Equity contribution						835				0		835
Common stock issued, net (in shares)				14,866,431
Common stock issued, net	842			$ 842							842
Stock-based compensation amortization	74			$ 74							74
Common stock dividends declared	(972)						(972)	(911)			(972)	(911)
Preferred stock dividend								(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)						(14)				(14)
Balance, end of period (in shares) at Dec. 31, 2016				506,891,874
Ending balance at Dec. 31, 2016	18,192		258	$ 12,198	1,322	8,050	5,751	8,763	(9)	2	17,940	18,395	252
Net Income (Loss)	1,660	1,691					1,660	1,691			1,660	1,691
Other comprehensive income (loss)	1	$ 4					0		1	4	1	4
Equity contribution						455						455
Common stock issued, net (in shares)				7,863,971
Common stock issued, net	416			$ 416							416
Stock-based compensation amortization	18			$ 18			0				18
Common stock dividends declared	(801)						(801)	(784)			(801)	(784)
Preferred stock dividend								(14)				(14)
Preferred stock dividend requirement of subsidiary	$ (14)						(14)				(14)
Balance, end of period (in shares) at Dec. 31, 2017	514,755,845	264,374,809		514,755,845
Ending balance at Dec. 31, 2017	$ 19,472		258	$ 12,632	1,322	8,505	6,596	9,656	(8)	6	19,220	19,747	252
Net Income (Loss)	(6,837)	$ (6,818)					(6,837)	(6,818)			(6,837)	(6,818)
Other comprehensive income (loss)	4	$ (5)					5	2	(1)	(7)	4	(5)
Equity contribution						45						45
Common stock issued, net (in shares)				5,582,865
Common stock issued, net	200			$ 200							200
Stock-based compensation amortization	78			$ 78							78
Preferred stock dividend								(14)				(14)
Preferred stock dividend requirement of subsidiary	$ (14)						(14)				(14)
Balance, end of period (in shares) at Dec. 31, 2018	520,338,710	264,374,809		520,338,710
Ending balance at Dec. 31, 2018	$ 12,903		$ 258	$ 12,910	$ 1,322	$ 8,550	$ (250)	$ 2,826	$ (9)	$ (1)	$ 12,651	$ 12,955	$ 252

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Organization and Basis of Presentation PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred. Chapter 11 Filing and Going Concern The accompanying 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 13 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 have determined that commencing reorganization cases under Chapter 11 is 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. See Note 15 below. The 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 Chapter 11, 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 4 and Note 15 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Consolidated Financial Statements. Any such actions occurring during the Chapter 11 Cases confirmed 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 Consolidated Financial Statements.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Loss Contingencies 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. 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. Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off. Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of a reserve for revenues subject to refund. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years. 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 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: (in millions) Year Ended December 31, 2018 Electric Revenue from contracts with customers Residential $ 5,051 Commercial 4,908 Industrial 1,532 Agricultural 1,234 Public street and highway lighting 72 Other (1) (720 ) Total revenue from contracts with customers - electric 12,077 Regulatory balancing accounts (2) 636 Total electric operating revenue $ 12,713 Natural gas Revenue from contracts with customers Residential $ 2,042 Commercial 537 Transportation service only 1,151 Other (1) 75 Total revenue from contracts with customers - gas 3,805 Regulatory balancing accounts (2) 242 Total natural gas operating revenue 4,047 Total operating revenues $ 16,760 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Cash and Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. Allowance for Doubtful Accounts Receivable PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability. Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2018 2017 Electricity generating facilities (1) 5 to 120 $ 13,047 $ 11,843 Electricity distribution facilities 15 to 65 32,926 31,110 Electricity transmission facilities 15 to 75 13,177 12,180 Natural gas distribution facilities 20 to 60 13,296 12,312 Natural gas transmission and storage facilities 5 to 62 8,260 7,329 Construction work in progress 2,564 2,471 Total property, plant, and equipment 83,270 77,245 Accumulated depreciation (24,713 ) (23,456 ) Net property, plant, and equipment $ 58,557 $ 53,789 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 14 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.82% in 2018 , 3.83% in 2017 , and 3.73% in 2016 . The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred. AFUDC AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $ 53 million and $ 129 million during 2018 , $38 million and $89 million during 2017 , and $51 million and $112 million during 2016 . Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2018 and 2017 , including nuclear decommissioning obligations: (in millions) 2018 2017 ARO liability at beginning of year $ 4,899 $ 4,684 Revision in estimated cash flows 993 128 Accretion 211 207 Liabilities settled (109 ) (120 ) ARO liability at end of year $ 5,994 $ 4,899 The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. In December 2018, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly increased its ARO liabilities by $1.1 billion . The adjustment was a result of increased estimated costs based on a site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation accrued was $4.7 billion and $3.5 billion at December 31, 2018 and 2017 , respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion and $7.0 billion at December 31, 2018 and 2017 , respectively. 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. See “Enforcement and Litigation Matters” in Note 14 below. Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. 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 was the primary beneficiary of any of these VIEs at December 31, 2018 , it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2018 , it did not consolidate any of them. Other Accounting Policies For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Notes 13 and 14 herein. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2018 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Total Beginning balance $ (25 ) $ 17 $ (8 ) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively) (104 ) (23 ) (127 ) Regulatory account transfer (net of taxes of $41 and $9, respectively) 107 23 130 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4 ) 10 6 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1) 3 (4 ) (1 ) Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (6 ) (4 ) Net current period other comprehensive loss 4 — 4 Ending balance $ (21 ) $ 17 $ (4 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2017 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Total Beginning balance $ (25 ) $ 16 $ (9 ) Other comprehensive income before reclassifications: Unrecognized prior service cost (net of taxes of $4 and $0, respectively) (6 ) — (6 ) Unrecognized net actuarial loss (net of taxes of $229 and $97, respectively) 333 141 474 Regulatory account transfer (net of taxes of $225 and $97, respectively) (327 ) (141 ) (468 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1) (4 ) 9 5 Amortization of net actuarial loss (net of taxes of $9 and $2, respectively) (1) 13 2 15 Regulatory account transfer (net of taxes of $6 and $8, respectively) (1) (9 ) (10 ) (19 ) Net current period other comprehensive loss — 1 1 Ending balance $ (25 ) $ 17 $ (8 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) Recently Adopted Accounting Standards Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606) , which amends the previous revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. See "Revenue Recognition" above. Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows. Previously, changes in restricted cash were reported within cash flows from investing activities. PG&E Corporation and the Utility applied the requirements on a retrospective basis when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. The retrospective adjustments to the Consolidated Statements of Cash Flows for PG&E Corporation and the Utility resulted in an increase to Net cash used in investing activities of $227 million, an increase to Cash, cash equivalents and restricted cash at January 1 by $234 million, and an increase to Cash, cash equivalents and restricted cash at December 31 by $7 million for the year ended December 31, 2016. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715) , which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. As a result, the Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $51 million and $54 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2017 and $97 million and $100 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2016. On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues. The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Consolidated Financial Statements and related disclosures. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification. Accounting Standards Issued But Not Yet Adopted Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the guidance relating to the definition of a lease, recognition of ROU assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize an ROU asset and lease liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU became effective for PG&E Corporation and the Utility 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. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility will apply the requirements using the modified retrospective method. PG&E Corporation and the Utility expect this standard to increase ROU assets and liabilities by approximately $2.5 billion to $3.0 billion on the Consolidated Balance Sheets and will result in additional footnote disclosures, but do not expect the guidance will have a material impact on the Consolidated Statements of Income and Statements of Cash Flows. The majority of PG&E Corporation and the Utility's leases are power purchase agreements. 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 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 the guidance will have on their Consolidated Financial Statements and related disclosures.

REGULATORY ASSETS, LIABILITIES,

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery Period (in millions) 2018 2017 Pension benefits (1) $ 1,947 $ 1,954 Indefinitely Environmental compliance costs 1,013 837 32 years Utility retained generation (2) 274 319 8 years Price risk management 90 65 10 years Unamortized loss, net of gain, on reacquired debt 76 79 25 years Catastrophic event memorandum account (3) 790 274 TBD years Wildfire expense memorandum account (4) 94 — TBD years Fire hazard prevention memorandum account (5) 263 1 TBD years Other 417 264 Various Total long-term regulatory assets $ 4,964 $ 3,793 (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 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. In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt. Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2018 2017 Cost of removal obligations (1) $ 5,981 $ 5,547 Deferred income taxes (2) 283 1,021 Recoveries in excess of AROs (3) 356 624 Public purpose programs (4) 674 590 Retirement Plan (5) 421 418 Other 824 479 Total long-term regulatory liabilities $ 8,539 $ 8,679 (1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs. (2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.) (3) 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 10 below.) (4) 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. (5) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months , the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at December 31, (in millions) 2018 2017 Electric distribution $ 160 $ — Electric transmission 128 139 Utility generation 79 — Gas distribution and transmission 462 486 Energy procurement 168 71 Public purpose programs 111 103 Other 327 423 Total regulatory balancing accounts receivable $ 1,435 $ 1,222 Payable Balance at December 31, (in millions) 2018 2017 Electric distribution $ — $ 72 Electric transmission 134 120 Utility generation — 14 Gas distribution and transmission 9 — Energy procurement 59 149 Public purpose programs 587 452 Other 287 313 Total regulatory balancing accounts payable $ 1,076 $ 1,120 The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency.

DEBT

DEBT	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
DEBT	DEBT Debtor In Possession ("DIP") Facilities In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into a Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019 (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. 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 PG&E Corporation and the Utility. As of February 28, 2019, 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 are unavailable for borrowing and will remain unavailable until and unless the Bankruptcy Court approves the availability thereof following a final hearing. PG&E Corporation and the Utility are unable to predict the date of the final hearing, but it is currently scheduled for March 13, 2019. There can be no assurances that the Bankruptcy Court will grant final approval of the DIP Facilities at the final hearing, or at all. 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. The DIP Facilities mature on December 31, 2020, subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee equal to 0.25% of the then-outstanding loans and available commitments. Borrowings under the DIP Facilities will bear interest based, at the Utility’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. ABR will equal the highest of the following: (i) the administrative agent’s announced base rate, (ii) 0.50% above the (x) federal funds effective rate or (y) the overnight federal funds rate, whichever is higher, (iii) one-month LIBOR plus 1.00% and (iv) zero . With respect to the DIP Revolving Facility, the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, the applicable margin is 2.25% for LIBOR loans and 1.25% for ABR loans. The Utility is also required to pay unused fees of (i) 0.375% per annum in respect of the average daily unutilized commitments under the DIP Revolving Facility and (ii) 1.125% per annum, which amount shall increase to 2.25% per annum after six months, in respect of the average daily unutilized commitments under the DIP Delayed Draw Term Loan Facility. The Utility must also pay (x) a fee equal to the applicable margin with respect to LIBOR loans under the DIP Revolving Facility on the aggregate drawable amount of all outstanding letters of credit under the DIP Revolving Facility and (y) a fronting fee to the relevant issuing DIP Lender equal to 0.125% per annum of the aggregate drawable amount of outstanding letters of credit issued by such issuing DIP Lender. 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, incur additional indebtedness, create liens on assets, make investments, loans or advances, engage in mergers, consolidations, sales of assets and acquisitions, pay dividends and distributions and make payments in respect of junior or pre-petition indebtedness, in each case subject to customary exceptions for debtor in possession loan agreements of this type. The DIP Credit Agreement also includes customary and usual representations and warranties and affirmative covenants, including an obligation to deliver 13-week cash flow forecasts and reports showing variances from such forecasts, in each case on a rolling 4-week basis. PG&E Corporation’s and the Utility’s obligations under the DIP Credit Agreement may be accelerated following certain events of default, including payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to post-petition or unstayed indebtedness of PG&E Corporation and the Utility and their subsidiaries in excess of $200 million, certain events under ERISA, unstayed judgments in respect of post-petition obligations involving an aggregate liability in excess of $200 million, change of control, specified governmental actions having a material adverse effect or condemnation or damage to a material portion of the collateral. Certain bankruptcy-related events are also events of default, including, but not limited to, the dismissal by the Bankruptcy Court of any of the Chapter 11 Cases, the conversion of any of the Chapter 11 Cases to a case under chapter 7 of the Bankruptcy Code, the appointment of a trustee pursuant to Chapter 11, any order authorizing the DIP Facilities being stayed, vacated, reversed or amended in a manner adverse to the DIP Lenders, the final order approving the DIP Facilities failing to have been entered by April 15, 2019, and certain other events related to the impairment of the DIP Lenders’ rights or liens granted under the DIP Credit Agreement. The proceeds of the borrowings under the DIP Facilities will be used for working capital and general corporate purposes and to pay fees, costs and expenses incurred in connection with the transactions contemplated by the DIP Credit Agreement and professional and other fees and costs of administration incurred in connection with the Chapter 11 Cases. Long-Term Debt Debt Obligations Previously Classified as Long Term The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: December 31, (in millions) 2018 2017 PG&E Corporation Term Loan: Stated Maturity Interest Rates 2020 variable rate (2) 350 350 Less: Current Portion (1) (350 ) — Total PG&E Corporation long-term debt — 350 Utility Senior notes: Stated Maturity Interest Rates 2018 8.25% — 400 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 2.45% 400 400 2023 through 2046 2.95% to 6.35% 15,775 14,975 Unamortized discount, net of premium and debt issuance costs (178 ) (185 ) Less: current portion (1) (17,347 ) (400 ) Total senior notes, net of current portion — 16,540 Pollution control bonds: Stated Maturity Interest Rates Series 2008 G, due 2018 1.05% — 45 Series 2008 F and 2010 E, due 2026 (3) 1.75% 100 100 Series 2009 A-B, due 2026 (4) variable rate (5) 149 149 Series 1996 C, E, F, 1997 B due 2026 (4) variable rate (6) 614 614 Less: current portion (1) (863 ) (45 ) Total pollution control bonds — 863 Total Utility long-term debt, net of current portion — 17,403 Total consolidated long-term debt, net of current portion $ — $ 17,753 (1) On January 29, 2019, PG&E Corporation and the Utility commenced reorganization under Chapter 11 of the U.S. Bankruptcy Code. The commencement of the Chapter 11 Cases constituted an event of default or termination event under the above-referenced debt of PG&E Corporation and the Utility. With the exception of Pollution Control Bonds series 2008F and 2010E, where a trustee notice is required to trigger acceleration, the commencement of the Chapter 11 Cases caused an automatic and immediate acceleration of such debt, and the possibility of cure is uncertain. Therefore, all long-term debt is classified as current as of December 31, 2018 . (2) At December 31, 2018 , the interest rate on the Term Loan was 3.66% . (3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (4) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series 2009 A-B bonds have a maturity date of June 5, 2019. In December 2015, Series 1996 C, E, F, 1997 B bonds the letters of credit were extended to December 1, 2020. Although the stated maturity date 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. (5) At December 31, 2018 , the interest rate on these bonds was 2.08% . (6) At December 31, 2018 , the interest rate on these bonds ranged from 2.05% to 2.15% . Pollution Control Bonds The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities. Repayment Schedule PG&E Corporation's and the Utility's long-term debt is in default, and the Accelerated Direct Financial Obligations became immediately due and payable upon the commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2018 are reflected in the table below: (in millions, except interest rates) 2019 2020 2021 2022 2023 Thereafter Total PG&E Corporation Variable interest rate as of December 31, 2018 — % 3.51 % — % — % — % — % 3.51 % Variable rate obligations $ — $ 350 $ — $ — $ — $ — $ 350 Utility Average fixed interest rate — % 3.50 % 3.80 % 2.31 % 3.83 % 4.74 % 4.52 % Fixed rate obligations $ — $ 800 $ 550 $ 500 $ 1,175 $ 14,600 $ 17,625 Variable interest rate as of December 31, 2018 1.78 % 1.59 % — % — % — % — % 1.63 % Variable rate obligations (1) $ 149 $ 614 $ — $ — $ — $ — $ 763 Total consolidated debt $ 149 $ 1,764 $ 550 $ 500 $ 1,175 $ 14,600 $ 18,738 (1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020. Short-term Borrowings The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their revolving credit facilities and commercial paper programs at December 31, 2018 : (in millions) Termination Date Credit Facility Limit Borrowings Against Revolver Commercial Paper Outstanding Facility Availability PG&E Corporation April 2022 $ 300 (1) $ 300 $ — $ — Utility April 2022 $ 3,000 (2) $ 2,965 (3) $ — $ 35 Total revolving credit facilities $ 3,300 $ 3,265 $ — $ 35 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days . (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. (3) Includes $80 million of letters of credit. For the year ended December 31, 2018 , PG&E Corporation’s average outstanding commercial paper balance was $29 million and the maximum outstanding balance during the year was $137 million . For the year ended December 31, 2018 , the Utility’s average outstanding commercial paper balance was $9 million and the maximum outstanding balance during the year was $205 million . As of December 31, 2018 , 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. The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of 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 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. See Note 15 below for more information. Revolving Credit Facilities In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022. As previously disclosed, PG&E Corporation's and the Utility's revolving credit facilities have been subject to an automatic and immediate acceleration as a result of the Chapter 11 Cases. Prior to the Chapter 11 Cases, proceeds from the revolving credit facilities were used for working capital, the repayment of commercial paper, and other corporate purposes. Borrowings under each credit agreement (other than swingline loans) previously bore interest based on the borrower’s credit rating and on each borrower’s election of either (1) LIBOR plus an applicable margin or (2) the base rate plus an applicable margin. The base rate equaled the higher of the following: the administrative agent’s announced base rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The borrower’s credit rating at the time of borrowing determined the applicable rate within the following ranges. The applicable margin for LIBOR loans ranged between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement. The applicable margin for base rate loans ranged between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s credit agreements ranged between 0.1% and 0.275% and between 0.075% and 0.225% , respectively. PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective revolving credit facilities required that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. PG&E Corporation’s revolving credit facility agreement also required that PG&E Corporation own, directly or indirectly, at least 80% of the outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility. Commercial Paper Programs The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs were used primarily to fund temporary financing needs. PG&E Corporation and the Utility could issue commercial paper up to the maximum amounts of $300 million and $2.5 billion , respectively. PG&E Corporation and the Utility treated the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities. The commercial paper had maturities up to 365 days and ranked equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes were sold at an interest rate dictated by the market at the time of issuance. For 2018 , the average yield on outstanding PG&E Corporation and Utility commercial paper was 1.85% and 1.91% , respectively. Other Short-term Borrowings In February 2018, the Utility’s $250 million floating rate unsecured term loan, issued in February 2017, matured and was repaid. In February 2018, the Utility entered into a $250 million floating rate unsecured term loan. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. As a result of the Chapter 11 Cases, repayment of this loan, which was scheduled to mature on February 22, 2019, has been stayed. As of December 31, 2018 , PG&E Corporation and the Utility each had no commercial paper borrowings. 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. In November 2018, the Utility's $500 million floating rate unsecured term loan, issued in November 2017, matured and was repaid.

COMMON STOCK AND SHARE-BASED CO

COMMON STOCK AND SHARE-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2018
Common Stock And Share-Based Compensation [Abstract]
COMMON STOCK AND SHARE-BASED COMPENSATION	COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 520,338,710 shares of common stock outstanding at December 31, 2018 . PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2018 . During 2018 , PG&E Corporation sold no shares of common stock under the February 2017 EDA. In addition, during 2018 , PG&E Corporation sold 5.6 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $199 million. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E common stock to cash. 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 wildfires. See Wildfire-related contingencies in Note 13 below. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65% . Based on the calculation of this ratio for each company, no amount of PG&E Corporation's retained earnings and $1.4 billion of the Utility's retained earnings was subject to this restriction at December 31, 2018 . Additionally, the Utility's net assets, and therefore its ability to pay dividends, are restricted by the CPUC-authorized capital structure, which requires the Utility to maintain, on average, at least 52% equity. Based on the calculation of this ratio, none of the Utility's net assets were restricted at December 31, 2018 . Additionally, as a result of this requirement, the Utility's ability to pay dividends in the future could be impacted by future potential liabilities. PG&E Corporation does not expect to pay any cash dividends for the foreseeable future. Long-Term Incentive Plan The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 15,150,532 shares were available for future awards at December 31, 2018 . The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2018 : (in millions) 2018 2017 2016 Stock Options $ 10 $ — $ — Restricted stock units 43 40 53 Performance shares 36 45 55 Total compensation expense (pre-tax) $ 89 $ 85 $ 108 Total compensation expense (after-tax) $ 63 $ 50 $ 64 Share-based compensation costs are generally not capitalized. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Stock Options The exercise price of stock options granted under the 2014 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant. Stock options generally have a 10 -year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2018 , $1.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of a year and a half for PG&E Corporation. The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method. The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $10.24 per share in 2018 . The significant assumptions used for shares granted in 2018 were: 2018 Expected stock price volatility 23.00 % Expected annual dividend payment 3.10 % Risk-free interest rate 2.58 % Expected life (years) 6 Expected volatilities are based on historical volatility of PG&E Corporation’s common stock. The expected dividend payment is the dividend yield at the date of grant. The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant. The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior. There was no tax benefit recognized from stock options for the year ended December 31, 2018 . The following table summarizes stock option activity for PG&E Corporation and the Utility for 2018 : Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 — N/A N/A N/A Granted 1,571,876 $ 10.24 — — Vested — N/A — — Forfeited (49,739 ) 10.23 — — Outstanding at December 31 1,522,137 10.24 9.17 0 Expected to vest at December 31 1,430,407 $ 10.24 9.17 0 Exercisable at December 31 — N/A N/A N/A Restricted Stock Units Restricted stock units granted after 2014 generally vest equally over three years . Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2018 , 2017 , and 2016 was $40.92 , $66.95 , and $56.68 , respectively. The total fair value of restricted stock units that vested during 2018 , 2017 , and 2016 was $41 million, $ 57 million, and $ 36 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2018 , $43 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.79 years. The following table summarizes restricted stock unit activity for 2018 : Number of Restricted Stock Units Weighted Average Grant- Date Fair Value Nonvested at January 1 1,379,235 $ 60.93 Granted 1,415,627 40.92 Vested (691,408 ) 58.78 Forfeited (123,642 ) 56.38 Nonvested at December 31 1,979,812 $ 47.66 Performance Shares Performance shares generally will vest three years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three -year performance period or, for a small number of awards, an internal PG&E Corporation metric. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. Compensation expense attributable to performance share is generally recognized ratably over the applicable three -year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards. The weighted average grant-date fair value for performance shares granted during 2018 , 2017 , and 2016 was $36.92 , $77.00 , and $53.61 respectively. There was no tax benefit associated with performance shares during each of these periods. In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 31, 2018 , $31 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.68 years. The following table summarizes activity for performance shares in 2018 : Number of Performance Shares Weighted Average Grant- Date Fair Value Nonvested at January 1 1,748,028 $ 63.40 Granted 763,392 36.92 Vested (156,747 ) 56.24 Forfeited (1) (916,582 ) 53.68 Nonvested at December 31 1,438,091 $ 56.32 (1) Includes performance shares that expired with zero value as performance targets were not met.

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2018
Preferred Stock [Abstract]
PREFERRED STOCK	PREFERRED STOCK PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any preferred stock outstanding. The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. At December 31, 2018 and December 31, 2017 , the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. All outstanding preferred stock has a $25 par value. At December 31, 2018 , annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2018 , annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share. Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid no dividends on preferred stock in 2018 (See "Dividends" in Note 5, above). The Utility paid $14 million of dividends on preferred stock in 2017 and 2016 .

EARNINGS PER SHARE

EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2018 , 2017 , and 2016 . Year Ended December 31, (in millions, except per share amounts) 2018 2017 2016 Income available for common shareholders $ (6,851 ) $ 1,646 $ 1,393 Weighted average common shares outstanding, basic 517 512 499 Add incremental shares from assumed conversions: Employee share-based compensation — 1 2 Weighted average common share outstanding, diluted 517 513 501 Total earnings per common share, diluted $ (13.25 ) $ 3.21 $ 2.78 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense. PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment. PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis. The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2018 2017 2016 2018 2017 2016 Current: Federal $ (5 ) $ (10 ) $ (105 ) $ 5 $ 61 $ (105 ) State (8 ) 48 (70 ) (7 ) 50 (66 ) Deferred: Federal (2,264 ) 481 218 (2,278 ) 326 229 State (1,009 ) 6 16 (1,009 ) 4 16 Tax credits (6 ) (14 ) (4 ) (6 ) (14 ) (4 ) Income tax provision (benefit) $ (3,292 ) $ 511 $ 55 $ (3,295 ) $ 427 $ 70 The following table describes net deferred income tax liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2018 2017 2018 2017 Deferred income tax assets: Tax carryforwards $ 740 $ 830 $ 650 $ 736 Compensation 173 274 121 205 Income tax regulatory liability (1) 79 286 79 286 Wildfire-related Reserve (2) 3,433 34 3,433 34 Other (3) 87 151 93 160 Total deferred income tax assets $ 4,512 $ 1,575 $ 4,376 $ 1,421 Deferred income tax liabilities: Property related basis differences 7,672 7,269 7,660 7,256 Other (4) 121 128 121 128 Total deferred income tax liabilities $ 7,793 $ 7,397 $ 7,781 $ 7,384 Total net deferred income tax liabilities $ 3,281 $ 5,822 $ 3,405 $ 5,963 (1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above). (2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire. (3) Amounts include benefits, environmental reserve, and customer advances for construction. (4) Amounts primarily relate to regulatory balancing accounts. The following table reconciles income tax expense at the federal statutory rate to the income tax provision: PG&E Corporation Utility Year Ended December 31, 2018 2017 2016 2018 2017 2016 Federal statutory income tax rate 21.0 % 35.0 % 35.0 % 21.0 % 35.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) 7.9 1.5 (2.5 ) 7.9 1.6 (2.2 ) Effect of regulatory treatment of fixed asset differences (2) 3.6 (16.5 ) (23.7 ) 3.6 (16.8 ) (23.4 ) Tax credits 0.1 (1.1 ) (0.8 ) 0.1 (1.1 ) (0.8 ) Benefit of loss carryback — — (1.1 ) — — (1.1 ) Compensation Related (3) (0.2 ) (1.0 ) (0.1 ) (0.1 ) (0.9 ) (0.2 ) Tax Reform Adjustment (4) 0.1 6.8 — 0.1 3.0 — Other, net (5) — (1.1 ) (3.0 ) — (0.7 ) (2.5 ) Effective tax rate 32.5 % 23.6 % 3.8 % 32.6 % 20.1 % 4.8 % (1) Includes the effect of state flow-through ratemaking treatment. In 2016, amounts reflect a settlement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision (impacting the twelve months ended December 31, 2017 ), the 2017 GRC decision (impacting the twelve months ended December 31, 2018 ), and by the 2015 GT&S decision which impacted all periods presented. All amounts are impacted by the level of income before income taxes. The 2014 GRC, 2017 GRC, and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2018 , the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act. (4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act. (5) These amounts primarily represents the impact of tax audit settlements. Unrecognized tax benefits The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2018 2017 2016 2018 2017 2016 Balance at beginning of year $ 349 $ 388 $ 468 $ 349 $ 382 $ 462 Reductions for tax position taken during a prior year (27 ) (71 ) (77 ) (27 ) (71 ) (77 ) Additions for tax position taken during the current year 55 48 56 55 48 56 Settlements — (14 ) (59 ) — (8 ) (59 ) Expiration of statute — (3 ) — — (3 ) — Balance at end of year $ 377 $ 349 $ 388 $ 377 $ 349 $ 382 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2018 for PG&E Corporation and the Utility was $5 million . PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits. As of December 31, 2018 , it is reasonably possible that unrecognized tax benefits will decrease by approximately $50 million within the next 12 months . Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2018 , 2017 , and 2016 , these amounts were immaterial. Tax Cuts and Jobs Act of 2017 On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. At December 31, 2017, PG&E Corporation and the Utility recorded estimated provisional amounts to reflect the effect of the Tax Act in accordance with Staff Accounting Bulletin No. 118. In 2018, PG&E Corporation and the Utility recorded an approximately $13 million tax benefit to adjust the amount recorded in 2017 for the Tax Act upon obtaining, preparing, and analyzing additional information regarding facts and circumstances that existed as of the enactment date that, if known, would have affected the income tax effects initially reported as provisional amounts. Although the accounting under ASC 740 to reflect the Tax Act is now complete, the Treasury is still issuing interpretive guidance on various aspects of the Tax Act. If future guidance requires a change in the recorded tax amounts, any necessary change will be reflected in the period such guidance is issued. In addition, the Utility filed the estimated revenue impact of the Tax Act with the CPUC and FERC in March and May of 2018, respectively. As of December 31, 2018 , the Utility still has not received final regulatory decisions. Depending on the final regulatory outcome, an adjustment may need to be made in the period the final decisions are issued. Tax settlements PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the Penalty Decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. In February 2017, the Joint Committee of Taxation approved PG&E Corporation’s settlement with the IRS related to deductible electric transmission and distribution repairs for the 2011 and 2012 tax years. The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts. In November 2017, PG&E Corporation reached an agreement with the IRS on deductible generation repairs for the 2013 and 2014 tax years. Tax years after 2007 remain subject to examination by the state of California. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, Expiration Year Federal: Net operating loss carryforward $ 3,880 2031 - 2036 Tax credit carryforward 118 2029 - 2037 Charitable contribution loss carryforward 10 2020 State: Net operating loss carryforward $ 58 2038 Tax credit carryforward 79 Various Charitable contribution loss carryforward 10 2020 - 2021 PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2018 for these tax attributes. On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status during the pendency of the Chapter 11 Cases.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s 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 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 Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated Balance Sheets at fair value. Volume of Derivative Activity At December 31, 2018 and 2017 , respectively, the volumes of the Utility’s outstanding derivatives were as follows: Contract Volume Underlying Product Instruments 2018 2017 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 177,750,349 228,768,745 Options 13,735,405 60,736,806 Electricity (Megawatt-hours) Forwards and Swaps 3,833,490 2,872,013 Congestion Revenue Rights (3) 340,783,089 312,272,177 (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 December 31, 2018 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance 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 At December 31, 2017 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance Current assets – other $ 30 $ (3 ) $ 10 $ 37 Other noncurrent assets – other 103 (1 ) — 102 Current liabilities – other (47 ) 3 13 (31 ) Noncurrent liabilities – other (66 ) 1 8 (57 ) Total commodity risk $ 20 $ — $ 31 $ 51 Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives instruments, including certain power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. In January 2019, multiple credit rating agencies downgraded the Utility below investment grade, resulting in the Utility posting $6.2 million to fully collateralize its net liability derivative positions.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2018
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 At 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 9) 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 9) 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. Fair Value Measurements At December 31, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 385 $ — $ — $ — $ 385 Nuclear decommissioning trusts Short-term investments 23 — — — 23 Global equity securities 1,967 — — — 1,967 Fixed-income securities 733 562 — — 1,295 Assets measured at NAV — — — — 18 Total nuclear decommissioning trusts (2) 2,723 562 — — 3,303 Price risk management instruments (Note 9) Electricity — 3 129 6 138 Gas — 1 — — 1 Total price risk management instruments — 4 129 6 139 Rabbi trusts Fixed-income securities — 72 — — 72 Life insurance contracts — 71 — — 71 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 8 — — — 8 Assets measured at NAV — — — — 167 Total long-term disability trust 8 — — — 175 TOTAL ASSETS $ 3,116 $ 709 $ 129 $ 6 $ 4,145 Liabilities: Price risk management instruments (Note 9) Electricity 10 15 87 (25 ) 87 Gas — 1 — — 1 TOTAL LIABILITIES $ 10 $ 16 $ 87 $ (25 ) $ 88 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $440 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 years ended December 31, 2018 and 2017 . 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 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 the 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 9 above. Fair Value at (in millions) At December 31, 2018 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities 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 Fair Value at (in millions) At December 31, 2017 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities Range (1) Congestion revenue rights $ 129 $ 24 Market approach CRR auction prices $ (16.03) - 11.99 Power purchase agreements $ — $ 63 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour Level 3 Reconciliation The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2018 and 2017 , respectively: Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of January 1 $ 42 $ 55 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 53 (13 ) Asset (liability) balance as of December 31 $ 95 $ 42 (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, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2018 and 2017 , as they are short-term in nature or have interest rates that reset daily. The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments, excluding pollution control bonds, were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2018 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation (1) $ 350 $ 350 $ 350 $ 350 Utility 17,450 14,747 17,090 19,128 (1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Notes. Also, in April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4. Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Cost Total Unrealized Gains Total Unrealized Losses Total Fair Value As of December 31, 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 As of December 31, 2017 Nuclear decommissioning trusts Short-term investments $ 23 $ — $ — $ 23 Global equity securities 524 1,463 (2 ) 1,985 Fixed-income securities 1,252 51 (8 ) 1,295 Total (1) $ 1,799 $ 1,514 $ (10 ) $ 3,303 (1) Represents amounts before deducting $408 million and $440 million at December 31, 2018 and 2017 , respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2018 Less than 1 year $ 60 1–5 years 391 5–10 years 341 More than 10 years 508 Total maturities of fixed-income securities $ 1,300 The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2018 2017 2016 Proceeds from sales and maturities of nuclear decommissioning investments $ 1,412 $ 1,291 $ 1,295 Gross realized gains on securities 54 53 18 Gross realized losses on securities (24 ) (11 ) (26 )

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2018
Employee Benefits and Share-based Compensation, Noncash [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”) PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates, $327 million for both 2018 and 2017 . PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans. On February 27, 2019, PG&E Corporation and the Utility received approval from the Bankruptcy Court to maintain existing pension and other benefit plans during the pendency of the Chapter 11 Cases. (For more information see "Chapter 11 Proceedings" in Note 15 below.) Change in Plan Assets, Benefit Obligations, and Funded Status The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2018 and 2017 : Pension Plan (in millions) 2018 2017 Change in plan assets: Fair value of plan assets at beginning of year $ 16,652 $ 14,729 Actual return on plan assets (923 ) 2,380 Company contributions 334 335 Benefits and expenses paid (751 ) (792 ) Fair value of plan assets at end of year $ 15,312 $ 16,652 Change in benefit obligation: Benefit obligation at beginning of year $ 18,757 $ 17,305 Service cost for benefits earned 514 472 Interest cost 687 714 Actuarial (gain) loss (1,800 ) 1,048 Plan amendments — 10 Benefits and expenses paid (751 ) (792 ) Benefit obligation at end of year (1) $ 17,407 $ 18,757 Funded Status: Current liability $ (8 ) $ (7 ) Noncurrent liability (2,087 ) (2,098 ) Net liability at end of year $ (2,095 ) $ (2,105 ) (1) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.8 billion at December 31, 2018 and 2017 , respectively. Postretirement Benefits Other than Pensions (in millions) 2018 2017 Change in plan assets: Fair value of plan assets at beginning of year $ 2,420 $ 2,173 Actual return on plan assets (108 ) 298 Company contributions 31 33 Plan participant contribution 81 87 Benefits and expenses paid (166 ) (171 ) Fair value of plan assets at end of year $ 2,258 $ 2,420 Change in benefit obligation: Benefit obligation at beginning of year $ 1,897 $ 1,877 Service cost for benefits earned 66 59 Interest cost 69 77 Actuarial (gain) loss (221 ) (49 ) Benefits and expenses paid (150 ) (157 ) Federal subsidy on benefits paid 3 3 Plan participant contributions 81 87 Benefit obligation at end of year $ 1,745 $ 1,897 Funded Status: (1) Noncurrent asset $ 545 $ 553 Noncurrent liability (32 ) (30 ) Net asset at end of year $ 513 $ 523 (1) At December 31, 2018 and 2017 , the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Net Periodic Benefit Cost PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan (in millions) 2018 2017 2016 Service cost for benefits earned (1) $ 514 $ 472 $ 453 Interest cost 687 714 715 Expected return on plan assets (1,021 ) (770 ) (828 ) Amortization of prior service cost (6 ) (7 ) 8 Amortization of net actuarial loss 5 22 24 Net periodic benefit cost 179 431 372 Less: transfer to regulatory account (2) 157 (92 ) (34 ) Total expense recognized $ 336 $ 339 $ 338 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions (in millions) 2018 2017 2016 Service cost for benefits earned (1) $ 66 $ 59 $ 52 Interest cost 69 77 76 Expected return on plan assets (130 ) (97 ) (107 ) Amortization of prior service cost 14 15 15 Amortization of net actuarial loss (5 ) 4 4 Net periodic benefit cost $ 14 $ 58 $ 40 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Accumulated Other Comprehensive Income PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss). The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2019 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (6 ) $ 14 Unrecognized net loss 3 (3 ) Total $ (3 ) $ 11 There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility. Valuation Assumptions The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost. Pension Plan PBOP Plans December 31, December 31, 2018 2017 2016 2018 2017 2016 Discount rate 4.35 % 3.64 % 4.11 % 4.29 - 4.37% 3.60 - 3.67 % 4.05 - 4.19 % Rate of future compensation increases 3.90 % 3.90 % 4.00 % — — — Expected return on plan assets 6.00 % 6.20 % 5.30 % 3.60 - 6.80% 3.30 - 7.10% 2.80 - 6.00% The assumed health care cost trend rate as of December 31, 2018 was 6.5% , decreasing gradually to an ultimate trend rate in 2027 and beyond of approximately 4.5% . A one-percentage-point change in assumed health care cost trend rate would have the following effects: (in millions) One-Percentage-Point Increase One-Percentage-Point Decrease Effect on postretirement benefit obligation $ 112 $ (113 ) Effect on service and interest cost 9 (10 ) Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.0% compares to a ten-year actual return of 10.0% . The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 1,101 Aa-grade non-callable bonds at December 31, 2018 . This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. Investment Policies and Strategies The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global REITS, global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios. Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments. The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2019 2018 2017 2019 2018 2017 Global equity securities 29 % 29 % 27 % 33 % 33 % 32 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 8 % 8 % 10 % 6 % 6 % 7 % Fixed-income securities 58 % 58 % 58 % 58 % 58 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 % PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments. Fair Value Measurements The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2018 and 2017 . Fair Value Measurements At December 31, 2018 2017 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 333 $ 22 $ — $ 355 $ 287 $ 424 $ — $ 711 Global equity securities 1,145 — — 1,145 1,292 — — 1,292 Real assets 461 — — 461 499 — — 499 Fixed-income securities 1,897 5,216 8 7,121 1,916 5,520 4 7,440 Assets measured at NAV — — — 6,202 — — — 6,818 Total $ 3,836 $ 5,238 $ 8 $ 15,284 $ 3,994 $ 5,944 $ 4 $ 16,760 PBOP Plans: Short-term investments $ 33 $ — $ — $ 33 $ 31 $ — $ — $ 31 Global equity securities 115 — — 115 141 — — 141 Real assets 50 — — 50 55 — — 55 Fixed-income securities 153 857 — 1,010 163 757 — 920 Assets measured at NAV — — — 1,056 — — — 1,281 Total $ 351 $ 857 $ — $ 2,264 $ 390 $ 757 $ — $ 2,428 Total plan assets at fair value $ 17,548 $ 19,188 In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $22 million and other net assets of $116 million at December 31, 2018 and 2017 , respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days. Short-Term Investments Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets. Global Equity securities The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets. Real Assets The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. Fixed-Income securities Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers Between Levels Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers between levels occurred in the years ended December 31, 2018 and 2017 . Level 3 Reconciliation The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2018 and 2017 : (in millions) For the year ended December 31, 2018 Fixed-Income Balance at beginning of year $ 4 Actual return on plan assets: Relating to assets still held at the reporting date (3 ) Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 6 Settlements 1 Balance at end of year $ 8 (in millions) For the year ended December 31, 2017 Fixed-Income Balance at beginning of year $ 5 Actual return on plan assets: Relating to assets still held at the reporting date (1 ) Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 3 Settlements (3 ) Balance at end of year $ 4 There were no material transfers out of Level 3 in 2018 and 2017 . Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $31 million to the other benefit plans in 2018 . These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2018 . The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act. PG&E Corporation and the Utility expect to make total contributions of approximately $ 327 million and $ 24 million to the pension plan and other postretirement benefit plans, respectively, for 2019 . Benefits Payments and Receipts As of December 31, 2018 , the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension Plan PBOP Plans Federal Subsidy 2019 778 88 (8 ) 2020 855 91 (9 ) 2021 891 94 (9 ) 2022 925 99 (3 ) 2023 957 102 (3 ) Thereafter in the succeeding five years 5,136 507 (12 ) There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above. Retirement Savings Plan PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $105 million , $103 million , and $97 million in 2018 , 2017 , and 2016 , respectively. There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

RELATED PARTY AGREEMENTS AND TR

RELATED PARTY AGREEMENTS AND TRANSACTIONS	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
RELATED PARTY AGREEMENTS AND TRANSACTIONS	RELATED PARTY AGREEMENTS AND TRANSACTIONS The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies. The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2018 2017 2016 Utility revenues from: Administrative services provided to PG&E Corporation $ 4 $ 8 $ 7 Utility expenses from: Administrative services received from PG&E Corporation $ 94 $ 65 $ 74 Utility employee benefit due to PG&E Corporation 76 73 91 At December 31, 2018 and 2017 , the Utility had receivables of $33 million and $20 million , respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $38 million and $22 million , respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
WILDFIRE-RELATED CONTINGENCIES	WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Wildfire-Related Claims Wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. For the years ended December 31, 2018, 2017 and 2016, the Utility’s Consolidated Income Statements include estimated losses offset by insurance recoveries as follows: Year Ended December 31, (in millions) 2018 2017 2016 2015 Butte fire Third-Party Claims $ — $ 350 $ 750 Insurance recoveries (7 ) (350 ) (625 ) Total 2015 Butte fire (7 ) — 125 2017 Northern California wildfires Third-Party Claims 3,500 — — Insurance recoveries (842 ) — — Total 2017 Northern California wildfires 2,658 — — 2018 Camp fire Third-Party Claims 10,500 — — Insurance recoveries (1,380 ) — — Total 2018 Camp fire 9,120 — — Total wildfire-related claims, net of insurance recoveries $ 11,771 $ — $ 125 In addition to the amounts shown in the table above, during the year ended December 31, 2018, the Utility incurred $245 million of legal and other costs related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. At December 31, 2018 and 2017 , the Utility's Consolidated Balance Sheets include estimated liabilities as follows: Balance At (in millions) December 31, 2018 December 31, 2017 2015 Butte fire $ 226 $ 561 2017 Northern California wildfires 3,500 — 2018 Camp fire 10,500 — Total wildfire-related claims $ 14,226 $ 561 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 January 4, 2019, (the “Cal Fire website”), indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 86 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. On February 7, 2019, the Butte County Sheriff's Office reported that the number of fatalities resulting from the 2018 Camp fire had been reduced from 86 to 85 . Although the cause of the 2018 Camp fire is still under investigation, based on the information currently known to PG&E Corporation and the Utility and reported to the CPUC and other agencies, including the facts described below, PG&E Corporation and the Utility believe it is probable that the Utility’s equipment will be determined to be an ignition point of the 2018 Camp fire. The Utility submitted two Electric Incident Reports (the “EIRs”) to the CPUC: one on November 8, 2018 and one on November 16, 2018. On December 11, 2018, the Utility publicly released a letter to the CPUC supplementing the EIRs (the “ 20 -Day Electric Incident Report”), which stated: • On Cal Fire’s website, Cal Fire has identified coordinates for the 2018 Camp fire near Tower :27/222 on the Utility’s Caribou-Palermo 115 kV Transmission Line and has identified the start time of the 2018 Camp fire as 6:33 a.m. on November 8, 2018. • On November 8, 2018, at approximately 6:15 a.m., the Utility’s Caribou-Palermo 115kV Transmission Line relayed and deenergized. At approximately 6:30 a.m. that day, a Utility employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by Utility employees. In the afternoon of November 8, the Utility observed damage on the line at Tower :27/222. Specifically, an aerial patrol identified that a suspension insulator supporting a transposition jumper had separated from an arm on Tower :27/222. • On November 14, 2018, the Utility observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point. In addition, the Utility observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator. • In addition to the events on the Caribou-Palermo 115kV Transmission Line, on November 8, 2018, at approximately 6:45 a.m., the Utility’s Big Bend 1101 12 kV Circuit experienced an outage. On November 9, 2018, a Utility employee on patrol arrived at the location of the pole with Line Recloser (“LR”) 1704 on the Big Bend 1101 Circuit and observed that the pole and other equipment were on the ground with bullets and bullet holes at the break point of the pole and on the equipment. On November 12, 2018, a Utility employee was patrolling Concow Road north of LR 1704 when he observed wires down and damaged and downed poles at the intersection of Concow Road and Rim Road. At this location, the employee observed several snapped trees, with some on top of the downed wires. The information contained in the EIRs and the 20-Day Electric Incident Report is factual and preliminary and does not reflect a determination of the causes of the 2018 Camp fire. These incidents remain under investigation by Cal Fire and the CPUC. With respect to the potential ignition point on the Utility’s Big Bend 1101 12 kV Circuit, although Cal Fire has identified this location as a potential ignition point, based on the condition of the site, PG&E Corporation and the Utility have not been able to determine whether the Big Bend 1101 12 kV Circuit may be a probable ignition point for the 2018 Camp fire. Neither Cal Fire nor the CPUC has publicly issued any news releases or other determinations for the 2018 Camp fire. The timing and outcome of the investigations are uncertain. PG&E Corporation and the Utility are cooperating with Cal Fire and the CPUC. Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. 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, including fire departments, 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 issued its determination on the causes of 19 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility's equipment. The remaining wildfires remain under Cal Fire's investigation, including the possible role of the Utility's power lines and other facilities. During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases, the first four fires “were caused by trees coming into contact with power lines” and the remaining 12 fires “were caused by electric power and distribution lines, conductors and the failure of power poles.” Cal Fire has not yet released its investigation reports related to the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires and stated in its news releases that these investigations have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” The Butte County District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain. Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation. On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure. Cal Fire has not publicly issued any news releases or other determinations for the Maacama, Pressley and Point wildfires. The timing and outcome of the Cal Fire investigation into these fires is uncertain. Further, the SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. 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, including fire departments, may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete. The Utility has submitted 23 electric incident reports to the CPUC associated with the 2017 Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $ 50,000 . The information contained in these reports is factual and preliminary and does not reflect a determination of the causes of the fires. 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 or penalties if the CPUC or any law enforcement agency brought an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations. As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which seek 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, includes 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 assert 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 seek 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, PG&E Corporation and the Utility are aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which seek to be certified as class actions. These cases have been 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, includes 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 assert 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 seek damages 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. Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires have filed 48 subrogation complaints in the San Francisco 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 37 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined 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 have 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 include, 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, and PG&E Corporation and the Utility expect additional similar claims to be made by other government entities. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court's decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation's and the Utility's petition for review. PG&E Corporation and the Utility expect to be the subject of numerous additional claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. PG&E Corporation and the Utility also are the subject of criminal investigations or other actions by the county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney’s Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million , not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.” Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the 2017 Northern California wildfires that started in these counties for a period of six months , until April 8, 2019. PG&E Corporation and the Utility anticipate further discussions with the District Attorneys in these counties relating to the 2017 Northern California wildfires and whether any criminal or civil charges should be brought. In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. Such proceedings are 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 such proceedings are stayed. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 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 or to the many investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set. 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, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain. Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires On January 28, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, stating that, as of such date, “more than $11.4 billion in insured losses have been reported from the November 2018 fires,” of which approximately $8.4 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires. The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.4 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularly with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.4 billion of insurance claims made as of the above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet ("future claims"), each of which could be significant. The scope of all claims related to the 2018 Camp fire and 2017 Northern California wildfires is not known at this time because of the applicable statutes of limitations under California law. Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, it is uncertain at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims may have on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion , which amount does not include potential punitive damages, fines and penalties or damages related to future claims. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount. If PG&E Corporation and the Utility were to be found liable for any punitive damages or subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. Such proceedings are 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 such proceedings are stayed. 2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, 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 is the amount within the range that is a better estimate than any other amount 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. 2018 Camp Fire In light of the current state of the law and the information currently available to the Utility, including, among other things, the facts described in the EIRs and the 20 -Day Electric Incident Report, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire, and accordingly PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation's and the Utility’s reasonably estimated losses, and is subject to change based on additional information. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire and 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire may change, which could result in material increases to the loss accrued. The $10.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. 2017 Northern California Wildfires In light of the current state of the law on inverse condemnation and the information currently available to the Utility, including, among other things, the Cal Fire determinations of cause as stated in Cal Fire’s press releases and their released reports, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with 17 of the 2017 Northern California wildfires referred

OTHER CONTINGENCIES AND COMMITM

OTHER CONTINGENCIES AND COMMITMENTS	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
OTHER CONTINGENCIES AND COMMITMENTS	WILDFIRE-RELATED CONTINGENCIES PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters. Wildfire-Related Claims Wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire. For the years ended December 31, 2018, 2017 and 2016, the Utility’s Consolidated Income Statements include estimated losses offset by insurance recoveries as follows: Year Ended December 31, (in millions) 2018 2017 2016 2015 Butte fire Third-Party Claims $ — $ 350 $ 750 Insurance recoveries (7 ) (350 ) (625 ) Total 2015 Butte fire (7 ) — 125 2017 Northern California wildfires Third-Party Claims 3,500 — — Insurance recoveries (842 ) — — Total 2017 Northern California wildfires 2,658 — — 2018 Camp fire Third-Party Claims 10,500 — — Insurance recoveries (1,380 ) — — Total 2018 Camp fire 9,120 — — Total wildfire-related claims, net of insurance recoveries $ 11,771 $ — $ 125 In addition to the amounts shown in the table above, during the year ended December 31, 2018, the Utility incurred $245 million of legal and other costs related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. At December 31, 2018 and 2017 , the Utility's Consolidated Balance Sheets include estimated liabilities as follows: Balance At (in millions) December 31, 2018 December 31, 2017 2015 Butte fire $ 226 $ 561 2017 Northern California wildfires 3,500 — 2018 Camp fire 10,500 — Total wildfire-related claims $ 14,226 $ 561 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 January 4, 2019, (the “Cal Fire website”), indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 86 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. On February 7, 2019, the Butte County Sheriff's Office reported that the number of fatalities resulting from the 2018 Camp fire had been reduced from 86 to 85 . Although the cause of the 2018 Camp fire is still under investigation, based on the information currently known to PG&E Corporation and the Utility and reported to the CPUC and other agencies, including the facts described below, PG&E Corporation and the Utility believe it is probable that the Utility’s equipment will be determined to be an ignition point of the 2018 Camp fire. The Utility submitted two Electric Incident Reports (the “EIRs”) to the CPUC: one on November 8, 2018 and one on November 16, 2018. On December 11, 2018, the Utility publicly released a letter to the CPUC supplementing the EIRs (the “ 20 -Day Electric Incident Report”), which stated: • On Cal Fire’s website, Cal Fire has identified coordinates for the 2018 Camp fire near Tower :27/222 on the Utility’s Caribou-Palermo 115 kV Transmission Line and has identified the start time of the 2018 Camp fire as 6:33 a.m. on November 8, 2018. • On November 8, 2018, at approximately 6:15 a.m., the Utility’s Caribou-Palermo 115kV Transmission Line relayed and deenergized. At approximately 6:30 a.m. that day, a Utility employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by Utility employees. In the afternoon of November 8, the Utility observed damage on the line at Tower :27/222. Specifically, an aerial patrol identified that a suspension insulator supporting a transposition jumper had separated from an arm on Tower :27/222. • On November 14, 2018, the Utility observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point. In addition, the Utility observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator. • In addition to the events on the Caribou-Palermo 115kV Transmission Line, on November 8, 2018, at approximately 6:45 a.m., the Utility’s Big Bend 1101 12 kV Circuit experienced an outage. On November 9, 2018, a Utility employee on patrol arrived at the location of the pole with Line Recloser (“LR”) 1704 on the Big Bend 1101 Circuit and observed that the pole and other equipment were on the ground with bullets and bullet holes at the break point of the pole and on the equipment. On November 12, 2018, a Utility employee was patrolling Concow Road north of LR 1704 when he observed wires down and damaged and downed poles at the intersection of Concow Road and Rim Road. At this location, the employee observed several snapped trees, with some on top of the downed wires. The information contained in the EIRs and the 20-Day Electric Incident Report is factual and preliminary and does not reflect a determination of the causes of the 2018 Camp fire. These incidents remain under investigation by Cal Fire and the CPUC. With respect to the potential ignition point on the Utility’s Big Bend 1101 12 kV Circuit, although Cal Fire has identified this location as a potential ignition point, based on the condition of the site, PG&E Corporation and the Utility have not been able to determine whether the Big Bend 1101 12 kV Circuit may be a probable ignition point for the 2018 Camp fire. Neither Cal Fire nor the CPUC has publicly issued any news releases or other determinations for the 2018 Camp fire. The timing and outcome of the investigations are uncertain. PG&E Corporation and the Utility are cooperating with Cal Fire and the CPUC. Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. 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, including fire departments, 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 issued its determination on the causes of 19 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility's equipment. The remaining wildfires remain under Cal Fire's investigation, including the possible role of the Utility's power lines and other facilities. During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases, the first four fires “were caused by trees coming into contact with power lines” and the remaining 12 fires “were caused by electric power and distribution lines, conductors and the failure of power poles.” Cal Fire has not yet released its investigation reports related to the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires and stated in its news releases that these investigations have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” The Butte County District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain. Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation. On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure. Cal Fire has not publicly issued any news releases or other determinations for the Maacama, Pressley and Point wildfires. The timing and outcome of the Cal Fire investigation into these fires is uncertain. Further, the SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. 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, including fire departments, may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete. The Utility has submitted 23 electric incident reports to the CPUC associated with the 2017 Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $ 50,000 . The information contained in these reports is factual and preliminary and does not reflect a determination of the causes of the fires. 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 or penalties if the CPUC or any law enforcement agency brought an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations. As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which seek 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, includes 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 assert 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 seek 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, PG&E Corporation and the Utility are aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which seek to be certified as class actions. These cases have been 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, includes 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 assert 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 seek damages 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. Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires have filed 48 subrogation complaints in the San Francisco 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 37 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined 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 have 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 include, 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, and PG&E Corporation and the Utility expect additional similar claims to be made by other government entities. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court's decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation's and the Utility's petition for review. PG&E Corporation and the Utility expect to be the subject of numerous additional claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. PG&E Corporation and the Utility also are the subject of criminal investigations or other actions by the county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney’s Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million , not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.” Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the 2017 Northern California wildfires that started in these counties for a period of six months , until April 8, 2019. PG&E Corporation and the Utility anticipate further discussions with the District Attorneys in these counties relating to the 2017 Northern California wildfires and whether any criminal or civil charges should be brought. In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. Such proceedings are 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 such proceedings are stayed. PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 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 or to the many investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set. 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, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain. Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires On January 28, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, stating that, as of such date, “more than $11.4 billion in insured losses have been reported from the November 2018 fires,” of which approximately $8.4 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires. The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.4 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularly with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.4 billion of insurance claims made as of the above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet ("future claims"), each of which could be significant. The scope of all claims related to the 2018 Camp fire and 2017 Northern California wildfires is not known at this time because of the applicable statutes of limitations under California law. Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities. There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, it is uncertain at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims may have on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion , which amount does not include potential punitive damages, fines and penalties or damages related to future claims. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount. If PG&E Corporation and the Utility were to be found liable for any punitive damages or subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. Such proceedings are 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 such proceedings are stayed. 2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, 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 is the amount within the range that is a better estimate than any other amount 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. 2018 Camp Fire In light of the current state of the law and the information currently available to the Utility, including, among other things, the facts described in the EIRs and the 20 -Day Electric Incident Report, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire, and accordingly PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation's and the Utility’s reasonably estimated losses, and is subject to change based on additional information. PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire and 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process. The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire may change, which could result in material increases to the loss accrued. The $10.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. 2017 Northern California Wildfires In light of the current state of the law on inverse condemnation and the information currently available to the Utility, including, among other things, the Cal Fire determinations of cause as stated in Cal Fire’s press releases and their released reports, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with 17 of the 2017 Northern California wildfires referred

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Chapter 11 Proceedings On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation's and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). PG&E Corporation and the Utility continue to operate their businesses as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. As debtors in possession, PG&E Corporation and the Utility are authorized to continue to operate as ongoing businesses, and may pay all debts and honor all obligations arising in the ordinary course of their businesses after the Petition Date. However, PG&E Corporation and the Utility may not pay third-party claims or creditors on account of obligations arising before the Petition Date or engage in transactions outside the ordinary course of business without approval 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 13 above), are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be administered under a Chapter 11 plan of reorganization to be voted upon by creditors and other stakeholders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continue during the pendency of the Chapter 11 Cases. To assure ordinary course operations, on January 31, 2019, PG&E Corporation and the Utility received interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize them to maintain their existing cash management system, to continue wage and salary payments and other benefits to their employees, to secure debtor in possession financing and other customary relief. On February 27, 2019, PG&E Corporation and the Utility received final approval of the first day motion to continue wage and salary payments and other benefits to their employees (with one limited objection with respect to a discrete matter having been preserved by the Bankruptcy Court) and certain other first day motions for customary relief. Hearings on certain other first day motions, including a hearing to consider final approval of PG&E Corporation’s and the Utility’s motions to continue their existing cash management system and to approve their debtor in possession financing, have not been held and no assurances can be given that the Bankruptcy Court will approve such motions on a final basis. PG&E Corporation and the Utility are unable to predict the date of the final hearing with respect to such motions, but there are hearings currently scheduled for March 12, March 13 and March 27, 2019. In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement. See Note 4 above for a description of the DIP Credit Agreement. The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of the Accelerated Direct Financial Obligations. Accordingly, as a result of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. 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 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 disclosed in Note 4 above. The filing of the Chapter 11 Cases may also provide the counterparties under certain commodity and related agreements with the right to declare an event of default and to seek termination of such rights subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. 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 Annual Report on 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. As of February 28, 2019, the Utility had outstanding borrowings of $ 350 million under the DIP Revolving Facility and $30 million in face amount of outstanding letters of credit, with remaining availability of $ 1.12 billion under the DIP Revolving Facility. US 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 issued a judgment of conviction against the Utility. The court sentenced the Utility to a 5 -year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after 3 years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service. 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 a third-party monitor at the Utility’s expense. The goal of the third-party 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 third-party 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 third-party 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 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. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. The court also invited parties to comment by February 20, 2019, on the 2019 Wildfire Safety Plan that the Utility submitted to the CPUC on February 6, 2019.

SCHEDULE I _ CONDENSED FINANCIA

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT	PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME Years Ended December 31, (in millions, except per share amounts) 2018 2017 2016 Administrative service revenue $ 90 $ 63 $ 70 Operating expenses (91 ) (5 ) (73 ) Interest income 2 1 1 Interest expense (15 ) (11 ) (10 ) Other income (expense) (2 ) 4 2 Equity in earnings of subsidiaries (6,832 ) 1,667 1,388 Income before income taxes (6,848 ) 1,719 1,378 Income tax provision (benefit) 3 73 (15 ) Net income $ (6,851 ) $ 1,646 $ 1,393 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, and $1, at respective dates) $ 4 $ 1 $ (2 ) Total other comprehensive income (loss) 4 1 (2 ) Comprehensive Income $ (6,847 ) $ 1,647 $ 1,391 Weighted Average Common Shares Outstanding, Basic 517 512 499 Weighted Average Common Shares Outstanding, Diluted 517 513 501 Net earnings per common share, basic $ (13.25 ) $ 3.21 $ 2.79 Net earnings per common share, diluted $ (13.25 ) $ 3.21 $ 2.78 PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2018 2017 ASSETS Current Assets Cash and cash equivalents $ 373 $ 2 Advances to affiliates 44 24 Income taxes receivable 18 27 Total current assets 435 53 Noncurrent Assets Equipment 2 3 Accumulated depreciation (2 ) (3 ) Net equipment — — Investments in subsidiaries 12,722 19,514 Other investments 162 144 Intercompany receivable — 72 Deferred income taxes 187 123 Total noncurrent assets 13,071 19,853 Total Assets $ 13,506 $ 19,906 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Short-term borrowings 300 132 Long-term debt, classified as current 350 — Accounts payable – other 16 6 Other 17 23 Total current liabilities 683 161 Noncurrent Liabilities Long-term debt — 350 Other 172 175 Total noncurrent liabilities 172 525 Common Shareholders’ Equity Common stock 12,910 12,632 Reinvested earnings (250 ) 6,596 Accumulated other comprehensive income (loss) (9 ) (8 ) Total common shareholders’ equity 12,651 19,220 Total Liabilities and Shareholders’ Equity $ 13,506 $ 19,906 PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2018 2017 2016 Cash Flows from Operating Activities: Net income $ (6,851 ) $ 1,646 $ 1,393 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 78 20 74 Equity in earnings of subsidiaries 6,833 (1,667 ) (1,388 ) Deferred income taxes and tax credits-net (62 ) 139 11 Current income taxes receivable/payable 9 (2 ) (1 ) Other 41 (75 ) (24 ) Net cash provided by operating activities 48 61 65 Cash Flows From Investing Activities: Investment in subsidiaries (45 ) (455 ) (835 ) Dividends received from subsidiaries (1) — 784 911 Net cash provided by (used in) investing activities (45 ) 329 76 Cash Flows From Financing Activities: Borrowings under revolving credit facility 425 — — Repayments under revolving credit facility (125 ) — — Net issuances (repayments) of commercial paper, net of discount of $1 in 2017 (132 ) 132 — Short-term debt financing 350 — — Long-term debt matured or repurchased (350 ) — — Common stock issued 200 395 822 Common stock dividends paid (2) — (1,021 ) (921 ) Net cash provided by (used in) financing activities 368 (494 ) (99 ) Net change in cash and cash equivalents 371 (104 ) 42 Cash and cash equivalents at January 1 2 106 64 Cash and cash equivalents at December 31 $ 373 $ 2 $ 106 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (13 ) $ (9 ) $ (9 ) Income taxes, net 10 — (13 ) Supplemental disclosure of noncash investing and financing activities Common stock dividends declared but not yet paid $ — $ — $ 248 Noncash common stock issuances — 21 20 (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On December 20, 2017, the Board of Directors of the Utility suspended quarterly cash dividends on the Utility's common stock, beginning the fourth quarter of 2017. (2) On December 20, 2017, the Board of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation's common stock, beginning the fourth quarter of 2017. In July and October of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.53 per share. In July and October of 2016 and January and April of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January and April of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

SCHEDULE II _ CONSOLIDATED VALU

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS	PG&E Corporation SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2018 , 2017 , and 2016 (in millions) Additions Description Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions (2) Balance at End of Period Valuation and qualifying accounts deducted from assets: 2018: Allowance for uncollectible accounts (1) $ 64 $ 34 $ — $ 42 $ 56 2017: Allowance for uncollectible accounts (1) $ 58 $ 55 $ — $ 49 $ 64 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ — $ 46 $ 58 (1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off. Pacific Gas and Electric Company SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2018 , 2017 , and 2016 (in millions) Additions Description Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Deductions (2) Balance at End of Period Valuation and qualifying accounts deducted from assets: 2018: Allowance for uncollectible accounts (1) $ 64 $ 34 $ — $ 42 $ 56 2017: Allowance for uncollectible accounts (1) $ 58 $ 55 $ — $ 49 $ 64 2016: Allowance for uncollectible accounts (1) $ 54 $ 50 $ — $ 46 $ 58 (1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.” (2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K.
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 wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.
Loss Contingencies	Loss Contingencies 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. 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.
Regulation and Regulated Operations	Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities. The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below. Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Revenue Recognition	Revenue Recognition Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of a reserve for revenues subject to refund. Regulatory Balancing Account Revenue The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years. 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 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.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.
Allowance for Doubtful Accounts Receivable	Allowance for Doubtful Accounts Receivable PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories	Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Emission Allowances	Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at weighted-average and are recoverable through rates.
Property, Plant, And Equipment	Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2018 2017 Electricity generating facilities (1) 5 to 120 $ 13,047 $ 11,843 Electricity distribution facilities 15 to 65 32,926 31,110 Electricity transmission facilities 15 to 75 13,177 12,180 Natural gas distribution facilities 20 to 60 13,296 12,312 Natural gas transmission and storage facilities 5 to 62 8,260 7,329 Construction work in progress 2,564 2,471 Total property, plant, and equipment 83,270 77,245 Accumulated depreciation (24,713 ) (23,456 ) Net property, plant, and equipment $ 58,557 $ 53,789 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 14 below.) The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.82% in 2018 , 3.83% in 2017 , and 3.73% in 2016 . The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC	AFUDC AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income.
Asset Retirement Obligations	The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. In December 2018, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly increased its ARO liabilities by $1.1 billion . The adjustment was a result of increased estimated costs based on a site-specific decommissioning analysis. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The total nuclear decommissioning obligation accrued was $4.7 billion and $3.5 billion at December 31, 2018 and 2017 , respectively. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion and $7.0 billion at December 31, 2018 and 2017 , respectively.
Disallowance of Plant Costs	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. See “Enforcement and Litigation Matters” in Note 14 below.
Nuclear Decommissioning Trusts	Nuclear Decommissioning Trusts The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
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 was the primary beneficiary of any of these VIEs at December 31, 2018 , it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2018 , it did not consolidate any of them.
Recently Adopted Accounting Guidance	Recently Adopted Accounting Standards Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606) , which amends the previous revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. See "Revenue Recognition" above. Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows. Previously, changes in restricted cash were reported within cash flows from investing activities. PG&E Corporation and the Utility applied the requirements on a retrospective basis when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. The retrospective adjustments to the Consolidated Statements of Cash Flows for PG&E Corporation and the Utility resulted in an increase to Net cash used in investing activities of $227 million, an increase to Cash, cash equivalents and restricted cash at January 1 by $234 million, and an increase to Cash, cash equivalents and restricted cash at December 31 by $7 million for the year ended December 31, 2016. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715) , which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018. On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. As a result, the Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $51 million and $54 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2017 and $97 million and $100 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2016. On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues. The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Consolidated Financial Statements and related disclosures. Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income . The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification. Accounting Standards Issued But Not Yet Adopted Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the guidance relating to the definition of a lease, recognition of ROU assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize an ROU asset and lease liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU became effective for PG&E Corporation and the Utility 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. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility will apply the requirements using the modified retrospective method. PG&E Corporation and the Utility expect this standard to increase ROU assets and liabilities by approximately $2.5 billion to $3.0 billion on the Consolidated Balance Sheets and will result in additional footnote disclosures, but do not expect the guidance will have a material impact on the Consolidated Statements of Income and Statements of Cash Flows. The majority of PG&E Corporation and the Utility's leases are power purchase agreements. 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 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 the guidance will have on their Consolidated Financial Statements and related disclosures.
Earnings Per Share	PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Fair Value Measurement	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.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Revenues Disaggregated by Type of Customer	The following table presents the Utility’s revenues disaggregated by type of customer: (in millions) Year Ended December 31, 2018 Electric Revenue from contracts with customers Residential $ 5,051 Commercial 4,908 Industrial 1,532 Agricultural 1,234 Public street and highway lighting 72 Other (1) (720 ) Total revenue from contracts with customers - electric 12,077 Regulatory balancing accounts (2) 636 Total electric operating revenue $ 12,713 Natural gas Revenue from contracts with customers Residential $ 2,042 Commercial 537 Transportation service only 1,151 Other (1) 75 Total revenue from contracts with customers - gas 3,805 Regulatory balancing accounts (2) 242 Total natural gas operating revenue 4,047 Total operating revenues $ 16,760 (1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers.
Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment	The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2018 2017 Electricity generating facilities (1) 5 to 120 $ 13,047 $ 11,843 Electricity distribution facilities 15 to 65 32,926 31,110 Electricity transmission facilities 15 to 75 13,177 12,180 Natural gas distribution facilities 20 to 60 13,296 12,312 Natural gas transmission and storage facilities 5 to 62 8,260 7,329 Construction work in progress 2,564 2,471 Total property, plant, and equipment 83,270 77,245 Accumulated depreciation (24,713 ) (23,456 ) Net property, plant, and equipment $ 58,557 $ 53,789 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 14 below.)
Schedule of Changes in Asset Retirement Obligations	The following table summarizes the changes in ARO liability during 2018 and 2017 , including nuclear decommissioning obligations: (in millions) 2018 2017 ARO liability at beginning of year $ 4,899 $ 4,684 Revision in estimated cash flows 993 128 Accretion 211 207 Liabilities settled (109 ) (120 ) ARO liability at end of year $ 5,994 $ 4,899
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income	The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2018 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Total Beginning balance $ (25 ) $ 17 $ (8 ) Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively) (104 ) (23 ) (127 ) Regulatory account transfer (net of taxes of $41 and $9, respectively) 107 23 130 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1) (4 ) 10 6 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1) 3 (4 ) (1 ) Regulatory account transfer (net of taxes of $1 and $3, respectively) (1) 2 (6 ) (4 ) Net current period other comprehensive loss 4 — 4 Ending balance $ (21 ) $ 17 $ (4 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2017 consisted of the following: (in millions, net of income tax) Pension Benefits Other Benefits Total Beginning balance $ (25 ) $ 16 $ (9 ) Other comprehensive income before reclassifications: Unrecognized prior service cost (net of taxes of $4 and $0, respectively) (6 ) — (6 ) Unrecognized net actuarial loss (net of taxes of $229 and $97, respectively) 333 141 474 Regulatory account transfer (net of taxes of $225 and $97, respectively) (327 ) (141 ) (468 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1) (4 ) 9 5 Amortization of net actuarial loss (net of taxes of $9 and $2, respectively) (1) 13 2 15 Regulatory account transfer (net of taxes of $6 and $8, respectively) (1) (9 ) (10 ) (19 ) Net current period other comprehensive loss — 1 1 Ending balance $ (25 ) $ 17 $ (8 ) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)

REGULATORY ASSETS, LIABILITIE_2

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Balance at December 31, Recovery Period (in millions) 2018 2017 Pension benefits (1) $ 1,947 $ 1,954 Indefinitely Environmental compliance costs 1,013 837 32 years Utility retained generation (2) 274 319 8 years Price risk management 90 65 10 years Unamortized loss, net of gain, on reacquired debt 76 79 25 years Catastrophic event memorandum account (3) 790 274 TBD years Wildfire expense memorandum account (4) 94 — TBD years Fire hazard prevention memorandum account (5) 263 1 TBD years Other 417 264 Various Total long-term regulatory assets $ 4,964 $ 3,793 (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 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.
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2018 2017 Cost of removal obligations (1) $ 5,981 $ 5,547 Deferred income taxes (2) 283 1,021 Recoveries in excess of AROs (3) 356 624 Public purpose programs (4) 674 590 Retirement Plan (5) 421 418 Other 824 479 Total long-term regulatory liabilities $ 8,539 $ 8,679 (1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs. (2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.) (3) 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 10 below.) (4) 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. (5) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.
Current Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at December 31, (in millions) 2018 2017 Electric distribution $ 160 $ — Electric transmission 128 139 Utility generation 79 — Gas distribution and transmission 462 486 Energy procurement 168 71 Public purpose programs 111 103 Other 327 423 Total regulatory balancing accounts receivable $ 1,435 $ 1,222
Current Regulatory Balancing Accounts Payable	Payable Balance at December 31, (in millions) 2018 2017 Electric distribution $ — $ 72 Electric transmission 134 120 Utility generation — 14 Gas distribution and transmission 9 — Energy procurement 59 149 Public purpose programs 587 452 Other 287 313 Total regulatory balancing accounts payable $ 1,076 $ 1,120

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Long-term Debt	The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: December 31, (in millions) 2018 2017 PG&E Corporation Term Loan: Stated Maturity Interest Rates 2020 variable rate (2) 350 350 Less: Current Portion (1) (350 ) — Total PG&E Corporation long-term debt — 350 Utility Senior notes: Stated Maturity Interest Rates 2018 8.25% — 400 2020 3.50% 800 800 2021 3.25% to 4.25% 550 550 2022 2.45% 400 400 2023 through 2046 2.95% to 6.35% 15,775 14,975 Unamortized discount, net of premium and debt issuance costs (178 ) (185 ) Less: current portion (1) (17,347 ) (400 ) Total senior notes, net of current portion — 16,540 Pollution control bonds: Stated Maturity Interest Rates Series 2008 G, due 2018 1.05% — 45 Series 2008 F and 2010 E, due 2026 (3) 1.75% 100 100 Series 2009 A-B, due 2026 (4) variable rate (5) 149 149 Series 1996 C, E, F, 1997 B due 2026 (4) variable rate (6) 614 614 Less: current portion (1) (863 ) (45 ) Total pollution control bonds — 863 Total Utility long-term debt, net of current portion — 17,403 Total consolidated long-term debt, net of current portion $ — $ 17,753 (1) On January 29, 2019, PG&E Corporation and the Utility commenced reorganization under Chapter 11 of the U.S. Bankruptcy Code. The commencement of the Chapter 11 Cases constituted an event of default or termination event under the above-referenced debt of PG&E Corporation and the Utility. With the exception of Pollution Control Bonds series 2008F and 2010E, where a trustee notice is required to trigger acceleration, the commencement of the Chapter 11 Cases caused an automatic and immediate acceleration of such debt, and the possibility of cure is uncertain. Therefore, all long-term debt is classified as current as of December 31, 2018 . (2) At December 31, 2018 , the interest rate on the Term Loan was 3.66% . (3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022. (4) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series 2009 A-B bonds have a maturity date of June 5, 2019. In December 2015, Series 1996 C, E, F, 1997 B bonds the letters of credit were extended to December 1, 2020. Although the stated maturity date 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. (5) At December 31, 2018 , the interest rate on these bonds was 2.08% . (6) At December 31, 2018 , the interest rate on these bonds ranged from 2.05% to 2.15% .
Schedule of Repayment Schedule	PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2018 are reflected in the table below: (in millions, except interest rates) 2019 2020 2021 2022 2023 Thereafter Total PG&E Corporation Variable interest rate as of December 31, 2018 — % 3.51 % — % — % — % — % 3.51 % Variable rate obligations $ — $ 350 $ — $ — $ — $ — $ 350 Utility Average fixed interest rate — % 3.50 % 3.80 % 2.31 % 3.83 % 4.74 % 4.52 % Fixed rate obligations $ — $ 800 $ 550 $ 500 $ 1,175 $ 14,600 $ 17,625 Variable interest rate as of December 31, 2018 1.78 % 1.59 % — % — % — % — % 1.63 % Variable rate obligations (1) $ 149 $ 614 $ — $ — $ — $ — $ 763 Total consolidated debt $ 149 $ 1,764 $ 550 $ 500 $ 1,175 $ 14,600 $ 18,738 (1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.
Schedule of Short-term Borrowings	The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their revolving credit facilities and commercial paper programs at December 31, 2018 : (in millions) Termination Date Credit Facility Limit Borrowings Against Revolver Commercial Paper Outstanding Facility Availability PG&E Corporation April 2022 $ 300 (1) $ 300 $ — $ — Utility April 2022 $ 3,000 (2) $ 2,965 (3) $ — $ 35 Total revolving credit facilities $ 3,300 $ 3,265 $ — $ 35 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days . (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. (3) Includes $80 million of letters of credit.

COMMON STOCK AND SHARE-BASED _2

COMMON STOCK AND SHARE-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2018
Common Stock And Share-Based Compensation [Abstract]
Schedule of Compensation Expense for Share-based Incentive Awards	The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2018 : (in millions) 2018 2017 2016 Stock Options $ 10 $ — $ — Restricted stock units 43 40 53 Performance shares 36 45 55 Total compensation expense (pre-tax) $ 89 $ 85 $ 108 Total compensation expense (after-tax) $ 63 $ 50 $ 64
Summary of Significant Assumptions Used for Shares Granted	The significant assumptions used for shares granted in 2018 were: 2018 Expected stock price volatility 23.00 % Expected annual dividend payment 3.10 % Risk-free interest rate 2.58 % Expected life (years) 6
Summary of Stock Option Activity	The following table summarizes stock option activity for PG&E Corporation and the Utility for 2018 : Number of Weighted Average Grant- Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1 — N/A N/A N/A Granted 1,571,876 $ 10.24 — — Vested — N/A — — Forfeited (49,739 ) 10.23 — — Outstanding at December 31 1,522,137 10.24 9.17 0 Expected to vest at December 31 1,430,407 $ 10.24 9.17 0 Exercisable at December 31 — N/A N/A N/A
Schedule of Restricted Stock Units	The following table summarizes restricted stock unit activity for 2018 : Number of Restricted Stock Units Weighted Average Grant- Date Fair Value Nonvested at January 1 1,379,235 $ 60.93 Granted 1,415,627 40.92 Vested (691,408 ) 58.78 Forfeited (123,642 ) 56.38 Nonvested at December 31 1,979,812 $ 47.66
Schedule of Performance Shares	The following table summarizes activity for performance shares in 2018 : Number of Performance Shares Weighted Average Grant- Date Fair Value Nonvested at January 1 1,748,028 $ 63.40 Granted 763,392 36.92 Vested (156,747 ) 56.24 Forfeited (1) (916,582 ) 53.68 Nonvested at December 31 1,438,091 $ 56.32 (1) Includes performance shares that expired with zero value as performance targets were not met.

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share	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 for 2018 , 2017 , and 2016 . Year Ended December 31, (in millions, except per share amounts) 2018 2017 2016 Income available for common shareholders $ (6,851 ) $ 1,646 $ 1,393 Weighted average common shares outstanding, basic 517 512 499 Add incremental shares from assumed conversions: Employee share-based compensation — 1 2 Weighted average common share outstanding, diluted 517 513 501 Total earnings per common share, diluted $ (13.25 ) $ 3.21 $ 2.78

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: PG&E Corporation Utility Year Ended December 31, (in millions) 2018 2017 2016 2018 2017 2016 Current: Federal $ (5 ) $ (10 ) $ (105 ) $ 5 $ 61 $ (105 ) State (8 ) 48 (70 ) (7 ) 50 (66 ) Deferred: Federal (2,264 ) 481 218 (2,278 ) 326 229 State (1,009 ) 6 16 (1,009 ) 4 16 Tax credits (6 ) (14 ) (4 ) (6 ) (14 ) (4 ) Income tax provision (benefit) $ (3,292 ) $ 511 $ 55 $ (3,295 ) $ 427 $ 70
Schedule of Deferred Tax Assets and Liabilities	The following table describes net deferred income tax liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2018 2017 2018 2017 Deferred income tax assets: Tax carryforwards $ 740 $ 830 $ 650 $ 736 Compensation 173 274 121 205 Income tax regulatory liability (1) 79 286 79 286 Wildfire-related Reserve (2) 3,433 34 3,433 34 Other (3) 87 151 93 160 Total deferred income tax assets $ 4,512 $ 1,575 $ 4,376 $ 1,421 Deferred income tax liabilities: Property related basis differences 7,672 7,269 7,660 7,256 Other (4) 121 128 121 128 Total deferred income tax liabilities $ 7,793 $ 7,397 $ 7,781 $ 7,384 Total net deferred income tax liabilities $ 3,281 $ 5,822 $ 3,405 $ 5,963 (1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. (For more information see Note 3 above). (2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire. (3) Amounts include benefits, environmental reserve, and customer advances for construction. (4) Amounts primarily relate to regulatory balancing accounts.
Schedule of Effective Income Tax Rate Reconciliation	The following table reconciles income tax expense at the federal statutory rate to the income tax provision: PG&E Corporation Utility Year Ended December 31, 2018 2017 2016 2018 2017 2016 Federal statutory income tax rate 21.0 % 35.0 % 35.0 % 21.0 % 35.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) 7.9 1.5 (2.5 ) 7.9 1.6 (2.2 ) Effect of regulatory treatment of fixed asset differences (2) 3.6 (16.5 ) (23.7 ) 3.6 (16.8 ) (23.4 ) Tax credits 0.1 (1.1 ) (0.8 ) 0.1 (1.1 ) (0.8 ) Benefit of loss carryback — — (1.1 ) — — (1.1 ) Compensation Related (3) (0.2 ) (1.0 ) (0.1 ) (0.1 ) (0.9 ) (0.2 ) Tax Reform Adjustment (4) 0.1 6.8 — 0.1 3.0 — Other, net (5) — (1.1 ) (3.0 ) — (0.7 ) (2.5 ) Effective tax rate 32.5 % 23.6 % 3.8 % 32.6 % 20.1 % 4.8 % (1) Includes the effect of state flow-through ratemaking treatment. In 2016, amounts reflect a settlement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision (impacting the twelve months ended December 31, 2017 ), the 2017 GRC decision (impacting the twelve months ended December 31, 2018 ), and by the 2015 GT&S decision which impacted all periods presented. All amounts are impacted by the level of income before income taxes. The 2014 GRC, 2017 GRC, and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In 2018 , the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017. (3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act. (4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act. (5) These amounts primarily represents the impact of tax audit settlements.
Schedule of Change in Unrecognized Tax Benefits	The following table reconciles the changes in unrecognized tax benefits: PG&E Corporation Utility (in millions) 2018 2017 2016 2018 2017 2016 Balance at beginning of year $ 349 $ 388 $ 468 $ 349 $ 382 $ 462 Reductions for tax position taken during a prior year (27 ) (71 ) (77 ) (27 ) (71 ) (77 ) Additions for tax position taken during the current year 55 48 56 55 48 56 Settlements — (14 ) (59 ) — (8 ) (59 ) Expiration of statute — (3 ) — — (3 ) — Balance at end of year $ 377 $ 349 $ 388 $ 377 $ 349 $ 382
Schedule of Operating Loss and Tax Credit Carryforward Balances	The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: (in millions) December 31, Expiration Year Federal: Net operating loss carryforward $ 3,880 2031 - 2036 Tax credit carryforward 118 2029 - 2037 Charitable contribution loss carryforward 10 2020 State: Net operating loss carryforward $ 58 2038 Tax credit carryforward 79 Various Charitable contribution loss carryforward 10 2020 - 2021

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Volumes of Outstanding Derivative Contracts	At December 31, 2018 and 2017 , respectively, the volumes of the Utility’s outstanding derivatives were as follows: Contract Volume Underlying Product Instruments 2018 2017 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 177,750,349 228,768,745 Options 13,735,405 60,736,806 Electricity (Megawatt-hours) Forwards and Swaps 3,833,490 2,872,013 Congestion Revenue Rights (3) 340,783,089 312,272,177 (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.
Outstanding Derivative Balances	At December 31, 2018 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance 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 At December 31, 2017 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance Current assets – other $ 30 $ (3 ) $ 10 $ 37 Other noncurrent assets – other 103 (1 ) — 102 Current liabilities – other (47 ) 3 13 (31 ) Noncurrent liabilities – other (66 ) 1 8 (57 ) Total commodity risk $ 20 $ — $ 31 $ 51

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on a Recurring Basis	Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At December 31, 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 9) 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 9) 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. Fair Value Measurements At December 31, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 385 $ — $ — $ — $ 385 Nuclear decommissioning trusts Short-term investments 23 — — — 23 Global equity securities 1,967 — — — 1,967 Fixed-income securities 733 562 — — 1,295 Assets measured at NAV — — — — 18 Total nuclear decommissioning trusts (2) 2,723 562 — — 3,303 Price risk management instruments (Note 9) Electricity — 3 129 6 138 Gas — 1 — — 1 Total price risk management instruments — 4 129 6 139 Rabbi trusts Fixed-income securities — 72 — — 72 Life insurance contracts — 71 — — 71 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 8 — — — 8 Assets measured at NAV — — — — 167 Total long-term disability trust 8 — — — 175 TOTAL ASSETS $ 3,116 $ 709 $ 129 $ 6 $ 4,145 Liabilities: Price risk management instruments (Note 9) Electricity 10 15 87 (25 ) 87 Gas — 1 — — 1 TOTAL LIABILITIES $ 10 $ 16 $ 87 $ (25 ) $ 88 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $440 million , primarily related to deferred taxes on appreciation of investment value.
Sensitivity Analysis	Fair Value at (in millions) At December 31, 2018 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities 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 Fair Value at (in millions) At December 31, 2017 Valuation Technique Unobservable Input Fair Value Measurement Assets Liabilities Range (1) Congestion revenue rights $ 129 $ 24 Market approach CRR auction prices $ (16.03) - 11.99 Power purchase agreements $ — $ 63 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour
Level 3 Reconciliation	The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2018 and 2017 , respectively: Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of January 1 $ 42 $ 55 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 53 (13 ) Asset (liability) balance as of December 31 $ 95 $ 42 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Carrying Amount and Fair Value of Financial Instruments	The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments, excluding pollution control bonds, were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At December 31, 2018 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation (1) $ 350 $ 350 $ 350 $ 350 Utility 17,450 14,747 17,090 19,128 (1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Notes. Also, in April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4.
Schedule of Unrealized Gains (Losses) Related to Available-for-sale Investments	The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) Amortized Cost Total Unrealized Gains Total Unrealized Losses Total Fair Value As of December 31, 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 As of December 31, 2017 Nuclear decommissioning trusts Short-term investments $ 23 $ — $ — $ 23 Global equity securities 524 1,463 (2 ) 1,985 Fixed-income securities 1,252 51 (8 ) 1,295 Total (1) $ 1,799 $ 1,514 $ (10 ) $ 3,303 (1) Represents amounts before deducting $408 million and $440 million at December 31, 2018 and 2017 , respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Long Term Debt Repayments	The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) December 31, 2018 Less than 1 year $ 60 1–5 years 391 5–10 years 341 More than 10 years 508 Total maturities of fixed-income securities $ 1,300
Schedule of Activity for Debt and Equity Securities	The following table provides a summary of activity for the fixed-income and equity securities: (in millions) 2018 2017 2016 Proceeds from sales and maturities of nuclear decommissioning investments $ 1,412 $ 1,291 $ 1,295 Gross realized gains on securities 54 53 18 Gross realized losses on securities (24 ) (11 ) (26 )

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2018
Employee Benefits and Share-based Compensation, Noncash [Abstract]
Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status	The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2018 and 2017 : Pension Plan (in millions) 2018 2017 Change in plan assets: Fair value of plan assets at beginning of year $ 16,652 $ 14,729 Actual return on plan assets (923 ) 2,380 Company contributions 334 335 Benefits and expenses paid (751 ) (792 ) Fair value of plan assets at end of year $ 15,312 $ 16,652 Change in benefit obligation: Benefit obligation at beginning of year $ 18,757 $ 17,305 Service cost for benefits earned 514 472 Interest cost 687 714 Actuarial (gain) loss (1,800 ) 1,048 Plan amendments — 10 Benefits and expenses paid (751 ) (792 ) Benefit obligation at end of year (1) $ 17,407 $ 18,757 Funded Status: Current liability $ (8 ) $ (7 ) Noncurrent liability (2,087 ) (2,098 ) Net liability at end of year $ (2,095 ) $ (2,105 ) (1) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.8 billion at December 31, 2018 and 2017 , respectively. Postretirement Benefits Other than Pensions (in millions) 2018 2017 Change in plan assets: Fair value of plan assets at beginning of year $ 2,420 $ 2,173 Actual return on plan assets (108 ) 298 Company contributions 31 33 Plan participant contribution 81 87 Benefits and expenses paid (166 ) (171 ) Fair value of plan assets at end of year $ 2,258 $ 2,420 Change in benefit obligation: Benefit obligation at beginning of year $ 1,897 $ 1,877 Service cost for benefits earned 66 59 Interest cost 69 77 Actuarial (gain) loss (221 ) (49 ) Benefits and expenses paid (150 ) (157 ) Federal subsidy on benefits paid 3 3 Plan participant contributions 81 87 Benefit obligation at end of year $ 1,745 $ 1,897 Funded Status: (1) Noncurrent asset $ 545 $ 553 Noncurrent liability (32 ) (30 ) Net asset at end of year $ 513 $ 523 (1) At December 31, 2018 and 2017 , the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
Components of Net Periodic Benefit Cost	Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: Pension Plan (in millions) 2018 2017 2016 Service cost for benefits earned (1) $ 514 $ 472 $ 453 Interest cost 687 714 715 Expected return on plan assets (1,021 ) (770 ) (828 ) Amortization of prior service cost (6 ) (7 ) 8 Amortization of net actuarial loss 5 22 24 Net periodic benefit cost 179 431 372 Less: transfer to regulatory account (2) 157 (92 ) (34 ) Total expense recognized $ 336 $ 339 $ 338 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. Postretirement Benefits Other than Pensions (in millions) 2018 2017 2016 Service cost for benefits earned (1) $ 66 $ 59 $ 52 Interest cost 69 77 76 Expected return on plan assets (130 ) (97 ) (107 ) Amortization of prior service cost 14 15 15 Amortization of net actuarial loss (5 ) 4 4 Net periodic benefit cost $ 14 $ 58 $ 40 (1) A portion of service costs are capitalized pursuant to ASU 2017-07.
Estimated Amortized Net Periodic Benefit	The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2019 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ (6 ) $ 14 Unrecognized net loss 3 (3 ) Total $ (3 ) $ 11
Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost	The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost. Pension Plan PBOP Plans December 31, December 31, 2018 2017 2016 2018 2017 2016 Discount rate 4.35 % 3.64 % 4.11 % 4.29 - 4.37% 3.60 - 3.67 % 4.05 - 4.19 % Rate of future compensation increases 3.90 % 3.90 % 4.00 % — — — Expected return on plan assets 6.00 % 6.20 % 5.30 % 3.60 - 6.80% 3.30 - 7.10% 2.80 - 6.00%
Schedule of Assumed Health Care Cost Trend	A one-percentage-point change in assumed health care cost trend rate would have the following effects: (in millions) One-Percentage-Point Increase One-Percentage-Point Decrease Effect on postretirement benefit obligation $ 112 $ (113 ) Effect on service and interest cost 9 (10 )
Target Asset Allocation Percentages	The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2019 2018 2017 2019 2018 2017 Global equity securities 29 % 29 % 27 % 33 % 33 % 32 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 8 % 8 % 10 % 6 % 6 % 7 % Fixed-income securities 58 % 58 % 58 % 58 % 58 % 58 % Total 100 % 100 % 100 % 100 % 100 % 100 %
Schedule of Changes in Fair Value of Plan Assets	The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2018 and 2017 . Fair Value Measurements At December 31, 2018 2017 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 333 $ 22 $ — $ 355 $ 287 $ 424 $ — $ 711 Global equity securities 1,145 — — 1,145 1,292 — — 1,292 Real assets 461 — — 461 499 — — 499 Fixed-income securities 1,897 5,216 8 7,121 1,916 5,520 4 7,440 Assets measured at NAV — — — 6,202 — — — 6,818 Total $ 3,836 $ 5,238 $ 8 $ 15,284 $ 3,994 $ 5,944 $ 4 $ 16,760 PBOP Plans: Short-term investments $ 33 $ — $ — $ 33 $ 31 $ — $ — $ 31 Global equity securities 115 — — 115 141 — — 141 Real assets 50 — — 50 55 — — 55 Fixed-income securities 153 857 — 1,010 163 757 — 920 Assets measured at NAV — — — 1,056 — — — 1,281 Total $ 351 $ 857 $ — $ 2,264 $ 390 $ 757 $ — $ 2,428 Total plan assets at fair value $ 17,548 $ 19,188
Schedule of Level 3 Reconciliation	The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2018 and 2017 : (in millions) For the year ended December 31, 2018 Fixed-Income Balance at beginning of year $ 4 Actual return on plan assets: Relating to assets still held at the reporting date (3 ) Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 6 Settlements 1 Balance at end of year $ 8 (in millions) For the year ended December 31, 2017 Fixed-Income Balance at beginning of year $ 5 Actual return on plan assets: Relating to assets still held at the reporting date (1 ) Relating to assets sold during the period — Purchases, issuances, sales, and settlements: Purchases 3 Settlements (3 ) Balance at end of year $ 4
Schedule of Estimated Benefits Expected to be Paid	As of December 31, 2018 , the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: (in millions) Pension Plan PBOP Plans Federal Subsidy 2019 778 88 (8 ) 2020 855 91 (9 ) 2021 891 94 (9 ) 2022 925 99 (3 ) 2023 957 102 (3 ) Thereafter in the succeeding five years 5,136 507 (12 )

RELATED PARTY AGREEMENTS AND _2

RELATED PARTY AGREEMENTS AND TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Schedule of Significant Related Party Transactions	The Utility’s significant related party transactions were: Year Ended December 31, (in millions) 2018 2017 2016 Utility revenues from: Administrative services provided to PG&E Corporation $ 4 $ 8 $ 7 Utility expenses from: Administrative services received from PG&E Corporation $ 94 $ 65 $ 74 Utility employee benefit due to PG&E Corporation 76 73 91

WILDFIRE-RELATED CONTINGENCIES

WILDFIRE-RELATED CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Summary of Wildfire-Related Claims	For the years ended December 31, 2018, 2017 and 2016, the Utility’s Consolidated Income Statements include estimated losses offset by insurance recoveries as follows: Year Ended December 31, (in millions) 2018 2017 2016 2015 Butte fire Third-Party Claims $ — $ 350 $ 750 Insurance recoveries (7 ) (350 ) (625 ) Total 2015 Butte fire (7 ) — 125 2017 Northern California wildfires Third-Party Claims 3,500 — — Insurance recoveries (842 ) — — Total 2017 Northern California wildfires 2,658 — — 2018 Camp fire Third-Party Claims 10,500 — — Insurance recoveries (1,380 ) — — Total 2018 Camp fire 9,120 — — Total wildfire-related claims, net of insurance recoveries $ 11,771 $ — $ 125
Schedule of Environmental Remediation Liability	At December 31, 2018 and 2017 , the Utility's Consolidated Balance Sheets include estimated liabilities as follows: Balance At (in millions) December 31, 2018 December 31, 2017 2015 Butte fire $ 226 $ 561 2017 Northern California wildfires 3,500 — 2018 Camp fire 10,500 — Total wildfire-related claims $ 14,226 $ 561
Changes in Insurance Receivable	The following table presents changes in the insurance receivable for the year ended December 31, 2018. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Consolidated Balance Sheets: (in millions) Insurance Receivable 2018 Camp fire Accrued insurance recoveries $ 1,380 Reimbursements — Balance at December 31, 2018 $ 1,380 2017 Northern California wildfires Accrued insurance recoveries $ 842 Reimbursements (13 ) Balance at December 31, 2018 $ 829 The following table presents changes in the insurance receivable since December 31, 2015 . The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets: Insurance Receivable (in millions) Balance at December 31, 2015 $ — Accrued insurance recoveries 625 Reimbursements (50 ) Balance at December 31, 2016 575 Accrued insurance recoveries 297 Reimbursements (276 ) Balance at December 31, 2017 596 Accrued insurance recoveries — Reimbursements (511 ) Balance at December 31, 2018 $ 85
Change in Accruals Related to Third-Party Claims	The following table presents changes in the third-party claims liability since December 31, 2015 . The balance for the third-party claims liability is included in Wildfire-related claims in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets: Loss Accrual (in millions) Balance at December 31, 2015 $ — Accrued losses 750 Payments (1) (60 ) Balance at December 31, 2016 690 Accrued losses 350 Payments (1) (479 ) Balance at December 31, 2017 561 Accrued losses — Payments (1) (335 ) Balance at December 31, 2018 $ 226 (1) As of December 31, 2018 , the Utility has paid $ 874 million of the $ 904 million in settlements to date in connection with the 2015 Butte fire.

OTHER CONTINGENCIES AND COMMI_2

OTHER CONTINGENCIES AND COMMITMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Environmental Remediation Liability	Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following: Balance at (in millions) December 31, December 31, Topock natural gas compressor station $ 369 $ 334 Hinkley natural gas compressor station 146 147 Former manufactured gas plant sites owned by the Utility or third parties (1) 520 320 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2) 111 115 Fossil fuel-fired generation facilities and sites (3) 137 123 Total environmental remediation liability $ 1,283 $ 1,039 (1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach. (2) Primarily driven by Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant.
Schedule of Undiscounted Future Expected Power Purchase Agreement Payments	The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2018 : Power Purchase Agreements (in millions) Renewable Energy Conventional Energy Other Natural Gas Nuclear Fuel Total 2019 $ 2,221 $ 642 $ 108 $ 412 $ 108 $ 3,491 2020 2,183 639 83 153 151 3,209 2021 2,174 582 65 93 64 2,978 2022 1,984 511 61 93 54 2,703 2023 1,914 223 61 93 49 2,340 Thereafter 24,217 435 162 264 47 25,125 Total purchase commitments $ 34,693 $ 3,032 $ 540 $ 1,108 $ 473 $ 39,846
Schedule of Future Minimum Payments for Operating Leases	At December 31, 2018 , the future minimum payments related to these commitments were as follows: (in millions) Operating Leases 2019 $ 44 2020 41 2021 36 2022 28 2023 19 Thereafter 121 Total minimum lease payments $ 289

SCHEDULE I _ CONDENSED FINANC_2

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Financial Information Disclosure [Abstract]
Condensed Income Statement	Years Ended December 31, (in millions, except per share amounts) 2018 2017 2016 Administrative service revenue $ 90 $ 63 $ 70 Operating expenses (91 ) (5 ) (73 ) Interest income 2 1 1 Interest expense (15 ) (11 ) (10 ) Other income (expense) (2 ) 4 2 Equity in earnings of subsidiaries (6,832 ) 1,667 1,388 Income before income taxes (6,848 ) 1,719 1,378 Income tax provision (benefit) 3 73 (15 ) Net income $ (6,851 ) $ 1,646 $ 1,393 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, and $1, at respective dates) $ 4 $ 1 $ (2 ) Total other comprehensive income (loss) 4 1 (2 ) Comprehensive Income $ (6,847 ) $ 1,647 $ 1,391 Weighted Average Common Shares Outstanding, Basic 517 512 499 Weighted Average Common Shares Outstanding, Diluted 517 513 501 Net earnings per common share, basic $ (13.25 ) $ 3.21 $ 2.79 Net earnings per common share, diluted $ (13.25 ) $ 3.21 $ 2.78
Condensed Balance Sheet	Balance at December 31, (in millions) 2018 2017 ASSETS Current Assets Cash and cash equivalents $ 373 $ 2 Advances to affiliates 44 24 Income taxes receivable 18 27 Total current assets 435 53 Noncurrent Assets Equipment 2 3 Accumulated depreciation (2 ) (3 ) Net equipment — — Investments in subsidiaries 12,722 19,514 Other investments 162 144 Intercompany receivable — 72 Deferred income taxes 187 123 Total noncurrent assets 13,071 19,853 Total Assets $ 13,506 $ 19,906 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Short-term borrowings 300 132 Long-term debt, classified as current 350 — Accounts payable – other 16 6 Other 17 23 Total current liabilities 683 161 Noncurrent Liabilities Long-term debt — 350 Other 172 175 Total noncurrent liabilities 172 525 Common Shareholders’ Equity Common stock 12,910 12,632 Reinvested earnings (250 ) 6,596 Accumulated other comprehensive income (loss) (9 ) (8 ) Total common shareholders’ equity 12,651 19,220 Total Liabilities and Shareholders’ Equity $ 13,506 $ 19,906
Schedule of Condensed Statement of Cash Flows	Year ended December 31, 2018 2017 2016 Cash Flows from Operating Activities: Net income $ (6,851 ) $ 1,646 $ 1,393 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 78 20 74 Equity in earnings of subsidiaries 6,833 (1,667 ) (1,388 ) Deferred income taxes and tax credits-net (62 ) 139 11 Current income taxes receivable/payable 9 (2 ) (1 ) Other 41 (75 ) (24 ) Net cash provided by operating activities 48 61 65 Cash Flows From Investing Activities: Investment in subsidiaries (45 ) (455 ) (835 ) Dividends received from subsidiaries (1) — 784 911 Net cash provided by (used in) investing activities (45 ) 329 76 Cash Flows From Financing Activities: Borrowings under revolving credit facility 425 — — Repayments under revolving credit facility (125 ) — — Net issuances (repayments) of commercial paper, net of discount of $1 in 2017 (132 ) 132 — Short-term debt financing 350 — — Long-term debt matured or repurchased (350 ) — — Common stock issued 200 395 822 Common stock dividends paid (2) — (1,021 ) (921 ) Net cash provided by (used in) financing activities 368 (494 ) (99 ) Net change in cash and cash equivalents 371 (104 ) 42 Cash and cash equivalents at January 1 2 106 64 Cash and cash equivalents at December 31 $ 373 $ 2 $ 106 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (13 ) $ (9 ) $ (9 ) Income taxes, net 10 — (13 ) Supplemental disclosure of noncash investing and financing activities Common stock dividends declared but not yet paid $ — $ — $ 248 Noncash common stock issuances — 21 20 (1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. On December 20, 2017, the Board of Directors of the Utility suspended quarterly cash dividends on the Utility's common stock, beginning the fourth quarter of 2017. (2) On December 20, 2017, the Board of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation's common stock, beginning the fourth quarter of 2017. In July and October of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.53 per share. In July and October of 2016 and January and April of 2017, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. In January and April of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)facility	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2019USD ($)	Jan. 01, 2016USD ($)	Dec. 31, 2015USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Period for probable revenue recovery		24 months
Increase in net cash used in investing activities		$ 6,564	$ 5,650	$ 5,753
Increase in cash, cash equivalents, and restricted cash	$ 1,675	1,675	456	184			$ 357
Increase in operating and maintenance expense		$ 7,153	6,321	7,326
Accounting Standards Update 2016-18
Public Utility, Property, Plant and Equipment [Line Items]
Increase in net cash used in investing activities				227
Increase in cash, cash equivalents, and restricted cash				7		$ 234
Accounting Standards Update 2017-07
Public Utility, Property, Plant and Equipment [Line Items]
Increase in operating and maintenance expense			$ 51	$ 97
Pacific Gas & Electric Co
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate		3.82%	3.83%	3.73%
AFUDC interest recorded		$ 53	$ 38	$ 51
AFUDC equity recorded		129	89	112
Adjustment to asset retirement obligation	1,100
Nuclear decommissioning obligation accrued		4,700	3,500
Estimated cost recovery on spent nuclear fuel storage proceeding every year			7,000
Approximate estimated nuclear decommissioning cost in future dollars		10,600	7,000
Increase in net cash used in investing activities		6,564	5,650	5,753
Increase in cash, cash equivalents, and restricted cash	$ 1,302	1,302	454	78			$ 293
Increase in operating and maintenance expense		$ 7,153	6,383	7,327
Pacific Gas & Electric Co | Accounting Standards Update 2017-07
Public Utility, Property, Plant and Equipment [Line Items]
Increase in operating and maintenance expense			$ 54	$ 100
Pacific Gas & Electric Co | Diablo Canyon
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility		2
Pacific Gas & Electric Co | Humboldt Bay
Public Utility, Property, Plant and Equipment [Line Items]
Number of generation facilities | facility		1
Minimum | Accounting Standards Update 2016-02 | Scenario, Forecast
Public Utility, Property, Plant and Equipment [Line Items]
Operating lease, right-of-use asset					$ 2,500
Operating lease, right-of-use liability					2,500
Maximum | Accounting Standards Update 2016-02 | Scenario, Forecast
Public Utility, Property, Plant and Equipment [Line Items]
Operating lease, right-of-use asset					3,000
Operating lease, right-of-use liability					$ 3,000

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - Pacific Gas & Electric Co $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Revenue from contracts with customers
Total operating revenues	$ 16,760
Electric
Revenue from contracts with customers
Total revenue from contracts with customers	12,077
Regulatory balancing accounts	636
Total operating revenues	12,713
Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	5,051
Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	4,908
Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	1,532
Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	1,234
Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	72
Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	(720)
Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	3,805
Regulatory balancing accounts	242
Total operating revenues	4,047
Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	2,042
Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	537
Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	1,151
Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ 75

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Estimated Useful Lives and Balances of Utility's Property, Plant and Equipment) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 83,270	$ 77,245
Accumulated depreciation	(24,713)	(23,456)
Net property, plant, and equipment	58,557	53,789
Electricity generating facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 13,047	11,843
Electricity generating facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Electricity generating facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	120 years
Electricity distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 32,926	31,110
Electricity distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 years
Electricity distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	65 years
Electricity transmission facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 13,177	12,180
Electricity transmission facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	15 years
Electricity transmission facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	75 years
Natural gas distribution facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 13,296	12,312
Natural gas distribution facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	20 years
Natural gas distribution facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	60 years
Natural gas transmission and storage facilities
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 8,260	7,329
Natural gas transmission and storage facilities | Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	5 years
Natural gas transmission and storage facilities | Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated Useful Lives (years)	62 years
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 2,564	$ 2,471

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO liability at beginning of year	$ 4,899	$ 4,684
Revision in estimated cash flows	993	128
Accretion	211	207
Liabilities settled	(109)	(120)
ARO liability at end of year	$ 5,994	$ 4,899

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ (8)	$ (9)
Net current period other comprehensive loss	4	1
Ending balance	(4)	(8)
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(127)	474
Amounts reclassified from other comprehensive income:	(1)	15
Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	130	(468)
Amounts reclassified from other comprehensive income:	(4)	(19)
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:		(6)
Amounts reclassified from other comprehensive income:	6	5
Pension Plan | Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(25)	(25)
Net current period other comprehensive loss	4	0
Ending balance	(21)	(25)
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(104)	333
Amounts reclassified from other comprehensive income:	3	13
Other comprehensive income before reclassifications, tax	41	229
Amounts reclassified from other comprehensive income, tax	2	9
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	107	(327)
Amounts reclassified from other comprehensive income:	2	(9)
Other comprehensive income before reclassifications, tax	41	225
Amounts reclassified from other comprehensive income, tax	1	6
Pension Plan | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:		(6)
Amounts reclassified from other comprehensive income:	(4)	(4)
Other comprehensive income before reclassifications, tax		4
Amounts reclassified from other comprehensive income, tax	2	3
PBOP Plans | Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	16
Net current period other comprehensive loss	0	1
Ending balance	17	17
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	(23)	141
Amounts reclassified from other comprehensive income:	(4)	2
Other comprehensive income before reclassifications, tax	9	97
Amounts reclassified from other comprehensive income, tax	1	2
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Transition Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:	23	(141)
Amounts reclassified from other comprehensive income:	(6)	(10)
Other comprehensive income before reclassifications, tax	9	97
Amounts reclassified from other comprehensive income, tax	3	8
PBOP Plans | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income before reclassifications:		0
Amounts reclassified from other comprehensive income:	10	9
Other comprehensive income before reclassifications, tax		0
Amounts reclassified from other comprehensive income, tax	$ 4	$ 6

REGULATORY ASSETS, LIABILITIE_3

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 4,964	$ 3,793
Utility retained generation asset costs	1,200
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,947	1,954
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 1,013	837
Recovery Period	32 years
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 274	319
Recovery Period	8 years
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 90	65
Recovery Period	10 years
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 76	79
Recovery Period	25 years
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 790	274
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	94	0
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	263	1
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 417	$ 264

REGULATORY ASSETS, LIABILITIE_4

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 8,539	$ 8,679
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	5,981	5,547
Deferred income tax
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	283	1,021
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	356	624
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	674	590
Retirement Plan
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	421	418
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 824	$ 479

REGULATORY ASSETS, LIABILITIE_5

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	$ 1,076	$ 1,120
Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	1,435	1,222
Electric distribution | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	0	72
Electric distribution | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	160	0
Electric transmission | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	134	120
Electric transmission | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	128	139
Utility generation | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	0	14
Utility generation | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	79	0
Gas distribution and transmission | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	9	0
Gas distribution and transmission | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	462	486
Energy procurement | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	59	149
Energy procurement | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	168	71
Public purpose programs | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	587	452
Public purpose programs | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	111	103
Other | Regulatory Balancing Accounts Payable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	287	313
Other | Regulatory Balancing Accounts Receivable
Regulatory Liabilities [Line Items]
Total regulatory balancing accounts	$ 327	$ 423

DEBT (Debtor In Possession ("DI

DEBT (Debtor In Possession ("DIP") Facilities) (Details) - Line of Credit	Feb. 28, 2019USD ($)	Feb. 27, 2019	Apr. 30, 2017	Feb. 01, 2019USD ($)
Senior Secured Superpriority Debt | DIP Credit Agreement | Subsequent Event
Line of Credit Facility [Line Items]
Amount arranged	$ 1,500,000,000			$ 5,500,000,000
Covenant terms, unstayed indebtedness, maximum amount	200,000,000
Covenant terms, post-petition obligations liability, maximum amount	$ 200,000,000
Senior Secured Superpriority Debt | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Extension fee	0.0025
Senior Secured Superpriority Debt | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Federal Funds Effective Swap Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Senior Secured Superpriority Debt | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Senior Secured Superpriority Debt | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.00%
DIP Revolving Facility | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate			0.50%
DIP Revolving Facility | Minimum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate			0.90%
DIP Revolving Facility | Minimum | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate			0.00%
DIP Revolving Facility | Pacific Gas & Electric Co | Minimum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate			0.80%
DIP Revolving Facility | Pacific Gas & Electric Co | Minimum | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate			0.00%
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event
Line of Credit Facility [Line Items]
Amount arranged				3,500,000,000
Borrowings available				1,500,000,000
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Borrowings available	$ 350,000,000
Fee on unused borrowings based on average daily unutilized commitments	0.375%
Fronting fee	0.125%
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.25%
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Up To Six Months
Line of Credit Facility [Line Items]
Fee on unused borrowings	1.125%
DIP Revolving Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | After Six Months
Line of Credit Facility [Line Items]
Fee on unused borrowings	2.25%
Letter of Credit Subfacility | DIP Credit Agreement | Subsequent Event
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
Letters of credit available				750,000,000
Letter of Credit Subfacility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Letters of credit available	$ 30,000,000
DIP Initial Term Loan Facility | DIP Credit Agreement | Subsequent Event
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
DIP Initial Term Loan Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.25%
DIP Initial Term Loan Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.25%
DIP Delayed Draw Term Loan Facility | DIP Credit Agreement | Subsequent Event
Line of Credit Facility [Line Items]
Amount arranged				$ 500,000,000
DIP Delayed Draw Term Loan Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.25%
DIP Delayed Draw Term Loan Facility | DIP Credit Agreement | Subsequent Event | Pacific Gas & Electric Co | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.25%

DEBT (Schedule of Long-term Deb

DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Apr. 26, 2018	Dec. 31, 2017
Debt [Line Items]
Total consolidated long-term debt, net of current portion	$ 0		$ 17,753
Pacific Gas & Electric Co
Debt [Line Items]
Less: current portion	(17,347)		(400)
Unamortized discount, net of premium and debt issuance costs	(178)		(185)
Total senior notes, net of current portion	0		16,540
Less: current portion	(863)		(45)
Total pollution control bonds	0		863
Total consolidated long-term debt, net of current portion	0		17,403
PG&E Corporation
Debt [Line Items]
Total senior notes, net of current portion	0		350
Total consolidated long-term debt, net of current portion	$ 0		350
Senior Notes Due 2019
Debt [Line Items]
Interest Rates		2.40%
Senior Notes Due 2019 | PG&E Corporation
Debt [Line Items]
Interest Rates	3.66%
Senior notes	$ 350		350
Less: current portion	$ (350)		0
Senior Notes Due 2018 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	8.25%
Senior notes	$ 0		400
Senior Notes Due 2020 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	3.50%
Senior notes	$ 800		800
Senior Notes Due 2021 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes	$ 550		550
Senior Notes Due 2021 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Interest Rates	3.25%
Senior Notes Due 2021 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Interest Rates	4.25%
Senior Notes Due 2022 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	2.45%
Senior notes	$ 400		400
Senior Notes Due 2023 through 2046 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes	$ 15,775		14,975
Senior Notes Due 2023 through 2046 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Interest Rates	2.95%
Senior Notes Due 2023 through 2046 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Interest Rates	6.35%
Pollution Control Bonds Series 2008, G, 1.05%, Due 2018 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	1.05%
Pollution control bonds	$ 0		45
Pollution Control Bonds Series 2008, F, And 2010, E, 1.75%, Due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	1.75%
Pollution control bonds	$ 100		100
Pollution Control Bonds Series 2009, A-B, Variable Rate, Due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Interest Rates	2.08%
Pollution control bonds	$ 149		149
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds	$ 614		$ 614
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Interest Rates	2.05%
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Interest Rates	2.15%

DEBT (Schedule of Long-term D_2

DEBT (Schedule of Long-term Debt Repayments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Debt [Line Items]
Total consolidated debt	$ 18,738
Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	1.63%
Variable rate obligations	$ 763
Average fixed interest rate	4.52%
Fixed rate obligations	$ 17,625
PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	3.51%
Variable rate obligations	$ 350
2,019
Debt [Line Items]
Total consolidated debt	$ 149
2019 | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	1.78%
Variable rate obligations	$ 149
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
2019 | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
2,020
Debt [Line Items]
Total consolidated debt	$ 1,764
2020 | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	1.59%
Variable rate obligations	$ 614
Average fixed interest rate	3.50%
Fixed rate obligations	$ 800
2020 | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	3.51%
Variable rate obligations	$ 350
2,021
Debt [Line Items]
Total consolidated debt	$ 550
2021 | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
Average fixed interest rate	3.80%
Fixed rate obligations	$ 550
2021 | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
2,022
Debt [Line Items]
Total consolidated debt	$ 500
2022 | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
Average fixed interest rate	2.31%
Fixed rate obligations	$ 500
2022 | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
2,023
Debt [Line Items]
Total consolidated debt	$ 1,175
2023 | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
Average fixed interest rate	3.83%
Fixed rate obligations	$ 1,175
2023 | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
Thereafter
Debt [Line Items]
Total consolidated debt	$ 14,600
Thereafter | Pacific Gas & Electric Co
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0
Average fixed interest rate	4.74%
Fixed rate obligations	$ 14,600
Thereafter | PG&E Corporation
Debt [Line Items]
Variable interest rate as of December 31, 2018	0.00%
Variable rate obligations	$ 0

DEBT (Schedule of Line of Credi

DEBT (Schedule of Line of Credit) (Details)	12 Months Ended
	Dec. 31, 2018USD ($)
Pacific Gas & Electric Co
Debt [Line Items]
Letters of credit, sublimit	$ 500,000,000
Swingline loans, sublimit	75,000,000
PG&E Corporation
Debt [Line Items]
Letters of credit, sublimit	50,000,000
Swingline loans, sublimit	$ 100,000,000
Swingline loan repay term (days)	7 days
Revolving Credit Facility
Debt [Line Items]
Credit Facility Limit	$ 3,300,000,000
Borrowings Against Revolver	3,265,000,000
Commercial Paper Outstanding	0
Facility Availability	35,000,000
Revolving Credit Facility | Pacific Gas & Electric Co
Debt [Line Items]
Credit Facility Limit	3,000,000,000
Borrowings Against Revolver	2,965,000,000
Commercial Paper Outstanding	0
Facility Availability	35,000,000
Letters of credit	80,000,000
Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Credit Facility Limit	300,000,000
Borrowings Against Revolver	300,000,000
Commercial Paper Outstanding	0
Facility Availability	$ 0

DEBT (Short-term Borrowings) (D

DEBT (Short-term Borrowings) (Details) - USD ($)	Apr. 30, 2017	May 31, 2017	Dec. 31, 2018	Nov. 30, 2018	Feb. 28, 2018	Jun. 30, 2016
Debt [Line Items]
Commercial paper, maturities (days)			365 days
Revolving Credit Facility | Line of Credit
Debt [Line Items]
Extension term		1 year
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage			65.00%			65.00%
Ownership requirement percentage			80.00%
Required ownership of voting capital stock			70.00%
Revolving Credit Facility | Line of Credit | Minimum
Debt [Line Items]
Facility fee	0.10%
Revolving Credit Facility | Line of Credit | Maximum
Debt [Line Items]
Facility fee	0.275%
Revolving Credit Facility | Line of Credit | Base Rate
Debt [Line Items]
Basis spread on variable rate	0.50%
Revolving Credit Facility | Line of Credit | Base Rate | Minimum
Debt [Line Items]
Basis spread on variable rate	0.00%
Revolving Credit Facility | Line of Credit | Base Rate | Maximum
Debt [Line Items]
Basis spread on variable rate	0.475%
Revolving Credit Facility | Line of Credit | LIBOR | Minimum
Debt [Line Items]
Basis spread on variable rate	0.90%
Revolving Credit Facility | Line of Credit | LIBOR | Maximum
Debt [Line Items]
Basis spread on variable rate	1.475%
Pacific Gas & Electric Co
Debt [Line Items]
Commercial paper sublimit			$ 2,500,000,000
Commercial paper average yield			1.91%
Floating rate unsecured term loan					$ 250,000,000
Pacific Gas & Electric Co | Commercial Paper
Debt [Line Items]
Average outstanding borrowings			$ 9,000,000
Maximum amount outstanding			205,000,000
Pacific Gas & Electric Co | Unsecured Debt | Floating Rate Unsecured Term Loan, Due 2019
Debt [Line Items]
Debt instrument, face amount					$ 250,000,000
Pacific Gas & Electric Co | Unsecured Debt | Floating Rate Senior Notes, Due 2018
Debt [Line Items]
Repayments of debt				$ 500,000,000
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | Minimum
Debt [Line Items]
Facility fee	0.075%
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | Maximum
Debt [Line Items]
Facility fee	0.225%
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | Base Rate | Minimum
Debt [Line Items]
Basis spread on variable rate	0.00%
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | Base Rate | Maximum
Debt [Line Items]
Basis spread on variable rate	0.275%
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | LIBOR | Minimum
Debt [Line Items]
Basis spread on variable rate	0.80%
Pacific Gas & Electric Co | Revolving Credit Facility | Line of Credit | LIBOR | Maximum
Debt [Line Items]
Basis spread on variable rate	1.275%
PG&E Corporation
Debt [Line Items]
Commercial paper sublimit			$ 300,000,000
Commercial paper average yield			1.85%
PG&E Corporation | Commercial Paper
Debt [Line Items]
Average outstanding borrowings			$ 29,000,000
Maximum amount outstanding			$ 137,000,000

COMMON STOCK AND SHARE-BASED _3

COMMON STOCK AND SHARE-BASED COMPENSATION (Narrative) (Details) - USD ($)	12 Months Ended			48 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2018	Jun. 30, 2016
Common stock, shares outstanding (in shares)	520,338,710	514,755,845		520,338,710
Cash proceeds from stock issuance	$ 12,910,000,000	$ 12,632,000,000		$ 12,910,000,000
Percentage of equity for capital structure to be maintained	52.00%
Number of shares issued for LTIP, maximum (in shares)	17,000,000			17,000,000
Shares available for LTIP award (in shares)	15,150,531.721			15,150,531.721
Weighted average grant date fair value of granted shares (in dollars per share)	$ 40.92	$ 66.95	$ 56.68
Total fair value	$ 41,000,000	$ 57,000,000	$ 36,000,000
Total unrecognized compensation costs	$ 43,000,000
Remaining weighted average period	1 year 9 months 16 days
Pacific Gas & Electric Co
Common stock, shares outstanding (in shares)	264,374,809	264,374,809		264,374,809
Cash proceeds from stock issuance	$ 1,322,000,000	$ 1,322,000,000		$ 1,322,000,000
Restricted reinvested earnings	0			0
2014 LTIP
Total unrecognized compensation costs	$ 1,500,000			$ 1,500,000
Stock Options | 2014 LTIP
Terms of award	P10Y
Award vesting period	4 years
Granted (in dollars per share)	$ 10.24
Restricted stock units
Award vesting period				3 years
Performance shares
Award vesting period	3 years
Industry performance period	3 years
Award grant date fair value recognition period	3 years
Performance shares granted (in dollars per share)	$ 36.92	$ 77	$ 53.61
Tax benefit from employee stock plans	$ 0	$ 0	$ 0
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized	$ 31,000,000
Weighted-average period	1 year 8 months 5 days
Expirations, fair value (in dollars per share)	$ 0
Line of Credit | Revolving Credit Facility
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%			65.00%	65.00%
February 2017 Equity Distribution Agreement
Common stock issued (in shares)	0			0
Dividend Reinvestment and Stock Purchase Plan
Common stock issued (in shares)	5,600,000			5,600,000
Cash proceeds from stock issuance	$ 199,000,000			$ 199,000,000
PG&E Corporation
Cash proceeds from stock issuance	12,910,000,000	$ 12,632,000,000		12,910,000,000
Restricted reinvested earnings	1,400,000,000			1,400,000,000
Net assets restricted for ratio requirement	$ 11,000,000			$ 11,000,000

COMMON STOCK AND SHARE-BASED _4

COMMON STOCK AND SHARE-BASED COMPENSATION (Long-term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 89	$ 85	$ 108
Total compensation expense (after-tax)	63	50	64
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	10	0	0
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	43	40	53
Performance shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense (pre-tax)	$ 36	$ 45	$ 55

COMMON STOCK AND SHARE-BASED _5

COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Significant Assumptions Used for Shares Granted) (Details) - 2014 LTIP - Stock Options	12 Months Ended
	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected stock price volatility	23.00%
Expected annual dividend payment	3.10%
Risk-free interest rate	2.58%
Expected life (years)	6 years

COMMON STOCK AND SHARE-BASED _6

COMMON STOCK AND SHARE-BASED COMPENSATION (Summary of Stock Option Activity) (Details) - 2014 LTIP - Stock Options	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Number of Stock Option
Outstanding, beginning of period (in shares)	0
Granted (in shares)	1,571,876
Vested (in shares)	0
Forfeited (in shares)	(49,739)
Outstanding, end of period (in shares)	1,522,137
Expected to vest (in shares)	1,430,407
Exercisable (in shares)	0
Weighted Average Grant- Date Fair Value
Granted (in dollars per share) | $ / shares	$ 10.24
Forfeited (in dollars per share) | $ / shares	10.23
Outstanding, end of period (in dollars per share) | $ / shares	10.24
Expected to vest (in dollars per share) | $ / shares	$ 10.24
Weighted Average Remaining Contractual Term
Outstanding	9 years 2 months 2 days
Expected to vest	9 years 2 months 2 days
Aggregate Intrinsic Value
Outstanding | $	$ 0
Expected | $	$ 0

COMMON STOCK AND SHARE-BASED _7

COMMON STOCK AND SHARE-BASED COMPENSATION (Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Restricted Stock Units
Nonvested (in shares)	1,379,235
Granted (in shares)	1,415,627
Vested (in shares)	(691,408)
Forfeited (in shares)	(123,642)
Nonvested (in shares)	1,979,812	1,379,235
Weighted Average Grant- Date Fair Value
Nonvested (in dollars per share)	$ 60.93
Granted (in dollars per share)	40.92	$ 66.95	$ 56.68
Vested (in dollars per share)	58.78
Forfeited (in dollars per share)	56.38
Nonvested (in dollars per share)	$ 47.66	$ 60.93

COMMON STOCK AND SHARE-BASED _8

COMMON STOCK AND SHARE-BASED COMPENSATION (Performance Shares) (Details) - Performance shares - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Number of Performance Shares
Nonvested (in shares)	1,748,028
Granted (in shares)	763,392
Vested (in shares)	(156,747)
Forfeited (in shares)	(916,582)
Nonvested (in shares)	1,438,091	1,748,028
Weighted Average Grant- Date Fair Value
Nonvested (ins dollars per share)	$ 63.40
Granted (in dollars per share)	36.92	$ 77	$ 53.61
Vested (in dollars per share)	56.24
Forfeited (in dollars per share)	53.68
Nonvested (in dollars per share)	$ 56.32	$ 63.40

PREFERRED STOCK (Narrative) (De

PREFERRED STOCK (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Minimum
Preferred Stock [Line Items]
Redemption price (in dollars per share)	$ 25.75	$ 25.75
Maximum
Preferred Stock [Line Items]
Redemption price (in dollars per share)	$ 27.25	$ 27.25
Pacific Gas & Electric Co
Preferred Stock [Line Items]
Preferred stock dividend requirement	$ 14	$ 14	$ 14
Pacific Gas & Electric Co | Nonredeemable Preferred Stock
Preferred Stock [Line Items]
Nonredeemable preferred stock outstanding	$ 145	$ 145
Preferred stock dividends per share, low range (in dollars per share)	$ 1.25
Preferred stock dividends per share, high range (in dollars per share)	$ 1.5
Pacific Gas & Electric Co | Nonredeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate	5.00%	5.00%
Pacific Gas & Electric Co | Nonredeemable Preferred Stock | Maximum | 6.00% Series
Preferred Stock [Line Items]
Preferred stock interest rate	6.00%	6.00%
Pacific Gas & Electric Co | Redeemable Preferred Stock
Preferred Stock [Line Items]
Redeemable preferred stock outstanding	$ 113	$ 113
Preferred stock dividends per share, low range (in dollars per share)	$ 1.09
Preferred stock dividends per share, high range (in dollars per share)	$ 1.25
Pacific Gas & Electric Co | Redeemable Preferred Stock | Minimum
Preferred Stock [Line Items]
Preferred stock interest rate	4.36%	4.36%
Pacific Gas & Electric Co | Redeemable Preferred Stock | Maximum | 5% Series A
Preferred Stock [Line Items]
Preferred stock interest rate	5.00%	5.00%
PG&E Corporation
Preferred Stock [Line Items]
Preferred stock dividend requirement		$ 14	$ 14
No Par Value | PG&E Corporation
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)	80,000,000
$100 Par Value | Pacific Gas & Electric Co
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share)	$ 100
$100 Par Value | PG&E Corporation
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)	5,000,000
Preferred stock, par value (in dollars per share)	$ 100
$25 Par Value
Preferred Stock [Line Items]
Preferred stock, shares authorized (in shares)	75,000,000
Preferred stock, par value (in dollars per share)	$ 25
$25 Par Value | Pacific Gas & Electric Co
Preferred Stock [Line Items]
Preferred stock, par value (in dollars per share)	$ 25

EARNINGS PER SHARE (Reconciliat

EARNINGS PER SHARE (Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Shares of Common Stock Outstanding for Calculating Diluted EPS) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Income available for common shareholders	$ (6,851)	$ 1,646	$ 1,393
Weighted average common shares outstanding, basic	517	512	499
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	0	1	2
Weighted average common share outstanding, diluted (in shares)	517	513	501
Total earnings per common share, diluted (in dollars per share)	$ (13.25)	$ 3.21	$ 2.78

INCOME TAXES (Schedule of Incom

INCOME TAXES (Schedule of Income Tax Provision) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current:
Federal	$ (5)	$ (10)	$ (105)
State	(8)	48	(70)
Deferred:
Federal	(2,264)	481	218
State	(1,009)	6	16
Tax credits	(6)	(14)	(4)
Income tax provision (benefit)	(3,292)	511	55
Pacific Gas & Electric Co
Current:
Federal	5	61	(105)
State	(7)	50	(66)
Deferred:
Federal	(2,278)	326	229
State	(1,009)	4	16
Tax credits	(6)	(14)	(4)
Income tax provision (benefit)	$ (3,295)	$ 427	$ 70

INCOME TAXES (Schedule of Defer

INCOME TAXES (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pacific Gas & Electric Co
Deferred income tax assets:
Tax carryforwards	$ 650	$ 736
Compensation	121	205
Income tax regulatory liability	79	286
Wildfire-related Reserve (2)	3,433	34
Other	93	160
Total deferred income tax assets	4,376	1,421
Deferred income tax liabilities:
Property related basis differences	7,660	7,256
Other	121	128
Total deferred income tax liabilities	7,781	7,384
Total net deferred income tax liabilities	3,405	5,963
PG&E Corporation
Deferred income tax assets:
Tax carryforwards	740	830
Compensation	173	274
Income tax regulatory liability	79	286
Wildfire-related Reserve (2)	3,433	34
Other	87	151
Total deferred income tax assets	4,512	1,575
Deferred income tax liabilities:
Property related basis differences	7,672	7,269
Other	121	128
Total deferred income tax liabilities	7,793	7,397
Total net deferred income tax liabilities	$ 3,281	$ 5,822

INCOME TAXES (Schedule of Effec

INCOME TAXES (Schedule of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pacific Gas & Electric Co
Federal statutory income tax rate	21.00%	35.00%	35.00%
State income tax (net of federal benefit)	7.90%	1.60%	(2.20%)
Effect of regulatory treatment of fixed asset differences	3.60%	(16.80%)	(23.40%)
Tax credits	0.10%	(1.10%)	(0.80%)
Benefit of loss carryback	0.00%	0.00%	(1.10%)
Compensation Related	(0.10%)	(0.90%)	(0.20%)
Tax Reform Adjustment	0.10%	3.00%	0.00%
Other, net	0.00%	(0.70%)	(2.50%)
Effective tax rate	32.60%	20.10%	4.80%
PG&E Corporation
Federal statutory income tax rate	21.00%	35.00%	35.00%
State income tax (net of federal benefit)	7.90%	1.50%	(2.50%)
Effect of regulatory treatment of fixed asset differences	3.60%	(16.50%)	(23.70%)
Tax credits	0.10%	(1.10%)	(0.80%)
Benefit of loss carryback	0.00%	0.00%	(1.10%)
Compensation Related	(0.20%)	(1.00%)	(0.10%)
Tax Reform Adjustment	0.10%	6.80%	0.00%
Other, net	0.00%	(1.10%)	(3.00%)
Effective tax rate	32.50%	23.60%	3.80%

INCOME TAXES (Schedule of Chang

INCOME TAXES (Schedule of Change in Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pacific Gas & Electric Co
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	$ 349	$ 382	$ 462
Reductions for tax position taken during a prior year	(27)	(71)	(77)
Additions for tax position taken during the current year	55	48	56
Settlements	0	(8)	(59)
Expiration of statute	0	(3)	0
Balance, end of period	377	349	382
PG&E Corporation
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance, beginning of period	349	388	468
Reductions for tax position taken during a prior year	(27)	(71)	(77)
Additions for tax position taken during the current year	55	48	56
Settlements	0	(14)	(59)
Expiration of statute	0	(3)	0
Balance, end of period	$ 377	$ 349	$ 388

INCOME TAXES (Narrative) (Detai

INCOME TAXES (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Contingency [Line Items]
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year	$ 5,000,000
Decrease in unrecognized tax benefits is reasonably possible	50,000,000
Income tax examination, penalties and interest expense (immaterial)	0	$ 0	$ 0
Pacific Gas & Electric Co
Income Tax Contingency [Line Items]
Tax Cuts and Jobs Act, measurement period adjustment, income tax benefit	$ 13,000,000

INCOME TAXES (Summary of Operat

INCOME TAXES (Summary of Operating Loss and Tax Credit Carryforward) (Details) $ in Millions	Dec. 31, 2018USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	$ 3,880
Tax credit carryforward	118
Charitable contribution loss carryforward	10
State
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	58
Tax credit carryforward	79
Charitable contribution loss carryforward	$ 10

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts) (Details)	Dec. 31, 2018MWhMMBTU	Dec. 31, 2017MWhMMBTU
Forwards and Swaps | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume | MMBTU	177,750,349	228,768,745
Forwards and Swaps | Electricity (Megawatt-hours)
Derivative [Line Items]
Contract Volume | MWh	3,833,490	2,872,013
Options | Natural Gas (MMBtus)
Derivative [Line Items]
Contract Volume | MMBTU	13,735,405	60,736,806
Congestion revenue rights | Electricity (Megawatt-hours)
Derivative [Line Items]
Contract Volume | MWh	340,783,089	312,272,177

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Derivatives And Hedging Activities [Line Items]
Derivative asset, netting	$ (88)	$ (6)
Derivative liability, netting	10	25
Commodity Contract | Pacific Gas & Electric Co
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	90	20
Derivative asset, netting	0	0
Cash Collateral	98	31
Total Derivative Balance, Assets	188	51
Commodity Contract | Pacific Gas & Electric Co | Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	44	30
Derivative asset, netting	(1)	(3)
Cash Collateral	89	10
Total Derivative Balance, Assets	132	37
Commodity Contract | Pacific Gas & Electric Co | Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	165	103
Derivative asset, netting	0	(1)
Cash Collateral	0	0
Total Derivative Balance, Assets	165	102
Commodity Contract | Pacific Gas & Electric Co | Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(29)	(47)
Derivative liability, netting	1	3
Cash Collateral	7	13
Total Derivative Balance, Liabilities	(21)	(31)
Commodity Contract | Pacific Gas & Electric Co | Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(90)	(66)
Derivative liability, netting	0	1
Cash Collateral	2	8
Total Derivative Balance, Liabilities	$ (88)	$ (57)

DERIVATIVES (Narrative) (Detail

DERIVATIVES (Narrative) (Details) $ in Millions	Jan. 31, 2019USD ($)
Pacific Gas & Electric Co | Subsequent Event
Derivative [Line Items]
Net position of derivative contracts/additional collateral posting requirements	$ 6.2

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	$ 1,593	$ 385
Total nuclear decommissioning trusts	3,138	3,303
Rabbi trusts	160	143
Long-term disability trust	162	175
Derivative asset, netting	88	6
Total assets	5,350	4,145
Derivative liability, netting	(10)	(25)
Amount primarily related to deferred taxes on appreciation of investment value	408	440
Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, netting	51	6
Derivative liability, netting	(10)	(25)
Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative asset, netting	37	0
Derivative liability, netting	0	0
Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	29	23
Long-term disability trust	7	8
Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	1,793	1,967
Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	1,300	1,295
Rabbi trusts	93	72
Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	297	139
TOTAL LIABILITIES	109	88
Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	259	138
TOTAL LIABILITIES	107	87
Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	38	1
TOTAL LIABILITIES	2	1
Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	67	71
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	1,593	385
Total nuclear decommissioning trusts	2,483	2,723
Rabbi trusts	0	0
Long-term disability trust	7	8
Total assets	4,083	3,116
Level 1 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	29	23
Long-term disability trust	7	8
Level 1 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	1,793	1,967
Level 1 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	661	733
Rabbi trusts	0	0
Level 1 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	4	10
Level 1 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	4	10
Level 1 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 1 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0	0
Total nuclear decommissioning trusts	639	562
Rabbi trusts	160	143
Long-term disability trust	0	0
Total assets	805	709
Level 2 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Long-term disability trust	0	0
Level 2 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Level 2 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	639	562
Rabbi trusts	93	72
Level 2 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	6	4
TOTAL LIABILITIES	7	16
Level 2 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	5	3
TOTAL LIABILITIES	5	15
Level 2 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	1	1
TOTAL LIABILITIES	2	1
Level 2 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	67	71
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0	0
Total nuclear decommissioning trusts	0	0
Rabbi trusts	0	0
Long-term disability trust	0	0
Total assets	203	129
Level 3 | Short-term investments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Long-term disability trust	0	0
Level 3 | Global equity securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Level 3 | Fixed-income securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	0	0
Rabbi trusts	0	0
Level 3 | Price risk management instruments
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	203	129
TOTAL LIABILITIES	108	87
Level 3 | Price risk management instruments | Electric
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	203	129
TOTAL LIABILITIES	108	87
Level 3 | Price risk management instruments | Gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total price risk management instruments	0	0
TOTAL LIABILITIES	0	0
Level 3 | Life insurance contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Rabbi trusts	0	0
NAV
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total nuclear decommissioning trusts	16	18
Long-term disability trust	$ 155	$ 167

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	Dec. 31, 2018USD ($)$ / MWh	Dec. 31, 2017USD ($)$ / MWh
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	$ 203	$ 129
Liabilities | $	75	24
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets | $	0	0
Liabilities | $	$ 33	$ 63
CRR auction prices | Market approach | Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh) | $ / MWh	(18.61)	(16.03)
CRR auction prices | Market approach | Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh) | $ / MWh	32.26	11.99
Forward prices | Discounted cash flow | Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh) | $ / MWh	19.81	18.81
Forward prices | Discounted cash flow | Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range (in dollars per mwh) | $ / MWh	38.80	38.80

FAIR VALUE MEASUREMENTS (Leve_2

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price risk management instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Asset (liability) balance, beginning of period	$ 42	$ 55
Included in regulatory assets and liabilities or balancing accounts	53	(13)
Asset (liability) balance, end of period	$ 95	$ 42

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($)	Dec. 31, 2018	Apr. 30, 2018	Apr. 26, 2018	Dec. 31, 2017
Senior Notes Due 2019
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Repayments of debt			$ 350,000,000
Stated interest rate			2.40%
Floating Rate Unsecured Term Loan | Unsecured Debt
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt instrument, face amount		$ 350,000,000
Carrying Amount
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 350,000,000			$ 350,000,000
Carrying Amount | Pacific Gas & Electric Co
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	17,450,000,000			17,090,000,000
Level 2 | Estimate of Fair Value Measurement
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	350,000,000			350,000,000
Level 2 | Estimate of Fair Value Measurement | Pacific Gas & Electric Co
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Debt financial instrument	$ 14,747,000,000			$ 19,128,000,000

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains Losses Related to Available-for-sale Investments) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 1,885	$ 1,799
Total Unrealized Gains	1,276	1,514
Total Unrealized Losses	(23)	(10)
Total Fair Value	3,138	3,303
Amount primarily related to deferred taxes on appreciation of investment value	408	440
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	29	23
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	29	23
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	568	524
Total Unrealized Gains	1,246	1,463
Total Unrealized Losses	(5)	(2)
Total Fair Value	1,809	1,985
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,288	1,252
Total Unrealized Gains	30	51
Total Unrealized Losses	(18)	(8)
Total Fair Value	$ 1,300	$ 1,295

FAIR VALUE MEASUREMENTS (Sche_2

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 3,138	$ 3,303
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	60
1–5 years	391
5–10 years	341
More than 10 years	508
Total maturities of fixed-income securities	$ 1,300	$ 1,295

FAIR VALUE MEASUREMENTS (Sche_3

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning investments	$ 1,412	$ 1,291	$ 1,295
Gross realized gains on securities	54	53	18
Gross realized losses on securities	$ (24)	$ (11)	$ (26)

EMPLOYEE BENEFIT PLANS (Narrati

EMPLOYEE BENEFIT PLANS (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)noncallable_bond	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Defined Benefit Plan Disclosure [Line Items]
Assumed health care cost trend rate	6.50%
Ultimate trend rate	4.50%
Assumed return	6.00%
10 year actual rate of return	10.00%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used (noncallable bond) | noncallable_bond	1,101
Total fair value of trust other net liabilities	$ (22)
Total fair value of trust other net assets		$ 116
Retirement savings plan expense	$ 105	$ 103	$ 97
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
10 year actual rate of return	6.00%	6.20%	5.30%
Company contributions	$ 334	$ 335
Expected employer contribution next year	327
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Company contributions	31	33
Expected employer contribution next year	24
Pacific Gas & Electric Co | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Public utilities, approved rate, amount	$ 327	$ 327

EMPLOYEE BENEFIT PLANS (Reconci

EMPLOYEE BENEFIT PLANS (Reconciliation of Changes in Plan Assets Benefit Obligations and Funded Status) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Funded Status:
Noncurrent liability	$ (2,119)	$ (2,128)
Pension Plan
Change in plan assets:
Fair value of plan assets at beginning of year	16,652	14,729
Actual return on plan assets	(923)	2,380
Company contributions	334	335
Benefits and expenses paid	(751)	(792)
Fair value of plan assets at end of year	15,312	16,652	$ 14,729
Change in benefit obligation:
Benefit obligation at beginning of year	18,757	17,305
Service cost for benefits earned	514	472	453
Interest cost	687	714	715
Actuarial (gain) loss	(1,800)	1,048
Plan amendments	0	10
Benefits and expenses paid	(751)	(792)
Benefit obligation at end of year	17,407	18,757	17,305
Funded Status:
Current liability	(8)	(7)
Noncurrent liability	(2,087)	(2,098)
Net assets (liabilities) at end of year	(2,095)	(2,105)
Accumulated benefit obligation	15,800	16,800
PBOP Plans
Change in plan assets:
Fair value of plan assets at beginning of year	2,420	2,173
Actual return on plan assets	(108)	298
Company contributions	31	33
Plan participant contribution	81	87
Benefits and expenses paid	(166)	(171)
Fair value of plan assets at end of year	2,258	2,420	2,173
Change in benefit obligation:
Benefit obligation at beginning of year	1,897	1,877
Service cost for benefits earned	66	59	52
Interest cost	69	77	76
Actuarial (gain) loss	(221)	(49)
Benefits and expenses paid	(150)	(157)
Federal subsidy on benefits paid	3	3
Plan participant contributions	81	87
Benefit obligation at end of year	1,745	1,897	$ 1,877
Funded Status:
Noncurrent asset	545	553
Noncurrent liability	(32)	(30)
Net assets (liabilities) at end of year	$ 513	$ 523

EMPLOYEE BENEFIT PLANS (Compone

EMPLOYEE BENEFIT PLANS (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 514	$ 472	$ 453
Interest cost	687	714	715
Expected return on plan assets	(1,021)	(770)	(828)
Amortization of prior service cost	(6)	(7)	8
Amortization of net actuarial loss	5	22	24
Net periodic benefit cost	179	431	372
Less: transfer to regulatory account	157	(92)	(34)
Total expense recognized	336	339	338
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	66	59	52
Interest cost	69	77	76
Expected return on plan assets	(130)	(97)	(107)
Amortization of prior service cost	14	15	15
Amortization of net actuarial loss	(5)	4	4
Net periodic benefit cost	$ 14	$ 58	$ 40

EMPLOYEE BENEFIT PLANS (Estimat

EMPLOYEE BENEFIT PLANS (Estimated Amortized Net Periodic Benefit) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	$ (6)
Unrecognized net loss	3
Total	(3)
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	14
Unrecognized net loss	(3)
Total	$ 11

EMPLOYEE BENEFIT PLANS (Schedul

EMPLOYEE BENEFIT PLANS (Schedule of Assumptions Used in Calculating Projected Benefit Cost and Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	10.00%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.35%	3.64%	4.11%
Rate of future compensation increases	3.90%	3.90%	4.00%
Expected return on plan assets	6.00%	6.20%	5.30%
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Rate of future compensation increases	0.00%	0.00%	0.00%
PBOP Plans | Minimum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.29%	3.60%	4.05%
Expected return on plan assets	3.60%	3.30%	2.80%
PBOP Plans | Maximum
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.37%	3.67%	4.19%
Expected return on plan assets	6.80%	7.10%	6.00%

EMPLOYEE BENEFIT PLANS (Sched_2

EMPLOYEE BENEFIT PLANS (Schedule of Assumed Health Care Cost Trend) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Employee Benefits and Share-based Compensation, Noncash [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$ 112
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	(113)
Effect on service and interest cost, One-Percentage-Point Increase	9
Effect on service and interest cost, One-Percentage-Point Decrease	$ (10)

EMPLOYEE BENEFIT PLANS (Target

EMPLOYEE BENEFIT PLANS (Target Asset Allocation Percentages) (Details)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		29.00%	27.00%
Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		5.00%	5.00%
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		8.00%	10.00%
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		58.00%	58.00%
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		100.00%	100.00%
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		33.00%	32.00%
PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		3.00%	3.00%
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		6.00%	7.00%
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation		58.00%	58.00%
Scenario, Forecast | Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Scenario, Forecast | Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	29.00%
Scenario, Forecast | Pension Plan | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	5.00%
Scenario, Forecast | Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	8.00%
Scenario, Forecast | Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	58.00%
Scenario, Forecast | PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	100.00%
Scenario, Forecast | PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	33.00%
Scenario, Forecast | PBOP Plans | Absolute return
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	3.00%
Scenario, Forecast | PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	6.00%
Scenario, Forecast | PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total target asset allocation	58.00%

EMPLOYEE BENEFIT PLANS (Sched_3

EMPLOYEE BENEFIT PLANS (Schedule of Fair Value of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	$ 17,548	$ 19,188
Level 3
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	8	4	$ 5
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	15,284	16,760
Assets measured at NAV	15,312	16,652	14,729
Pension Plan | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	355	711
Pension Plan | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,145	1,292
Pension Plan | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	461	499
Pension Plan | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	7,121	7,440
Pension Plan | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	3,836	3,994
Pension Plan | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	333	287
Pension Plan | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,145	1,292
Pension Plan | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	461	499
Pension Plan | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,897	1,916
Pension Plan | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	5,238	5,944
Pension Plan | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	22	424
Pension Plan | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	5,216	5,520
Pension Plan | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8	4
Pension Plan | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
Pension Plan | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	8	4
Pension Plan | NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	6,202	6,818
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	2,264	2,428
Assets measured at NAV	2,258	2,420	$ 2,173
PBOP Plans | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	33	31
PBOP Plans | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	115	141
PBOP Plans | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	50	55
PBOP Plans | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	1,010	920
PBOP Plans | Level 1
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	351	390
PBOP Plans | Level 1 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	33	31
PBOP Plans | Level 1 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	115	141
PBOP Plans | Level 1 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	50	55
PBOP Plans | Level 1 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	153	163
PBOP Plans | Level 2
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	857	757
PBOP Plans | Level 2 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 2 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	857	757
PBOP Plans | Level 3
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Short-term investments
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Global equity securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Real assets
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | Level 3 | Fixed-income securities
Defined Benefit Plan Disclosure [Line Items]
Total plan assets at fair value	0	0
PBOP Plans | NAV
Defined Benefit Plan Disclosure [Line Items]
Assets measured at NAV	$ 1,056	$ 1,281

EMPLOYEE BENEFIT PLANS (Sched_4

EMPLOYEE BENEFIT PLANS (Schedule of Level 3 Reconciliation) (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]
Fair value of plan assets at beginning of year	$ 4	$ 5
Actual return on plan assets:
Relating to assets still held at the reporting date	(3)	(1)
Relating to assets sold during the period	0	0
Purchases, issuances, sales, and settlements:
Purchases	6	3
Settlements	1	(3)
Fair value of plan assets at end of year	$ 8	$ 4

EMPLOYEE BENEFIT PLANS (Sched_5

EMPLOYEE BENEFIT PLANS (Schedule of Estimated Benefits Expected to Be Paid) (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
2,019	$ 778
2,020	855
2,021	891
2,022	925
2,023	957
Thereafter in the succeeding five years	5,136
PBOP Plans
Defined Benefit Plan Disclosure [Line Items]
2,019	88
2,020	91
2,021	94
2,022	99
2,023	102
Thereafter in the succeeding five years	507
Federal Subsidy
Defined Benefit Plan Disclosure [Line Items]
2,019	(8)
2,020	(9)
2,021	(9)
2,022	(3)
2,023	(3)
Thereafter in the succeeding five years	$ (12)

RELATED PARTY AGREEMENTS AND _3

RELATED PARTY AGREEMENTS AND TRANSACTIONS (Summary of Significant Related Party Transactions) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Administrative services provided to PG&E Corporation
Related Party Transaction [Line Items]
Utility revenues from	$ 4	$ 8	$ 7
Administrative services received from PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	94	65	74
Utility employee benefit due to PG&E Corporation
Related Party Transaction [Line Items]
Utility expenses from	$ 76	$ 73	$ 91

RELATED PARTY AGREEMENTS AND _4

RELATED PARTY AGREEMENTS AND TRANSACTIONS (Narrative) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Current payables	$ 33	$ 20
Current receivables	$ 38	$ 22

WILDFIRE-RELATED CONTINGENCIE_2

WILDFIRE-RELATED CONTINGENCIES (Summary of Estimated Losses Related to Wildfire-Related Claims) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Total wildfire-related claims, net of insurance recoveries			$ 11,771	$ 0	$ 125
2017 Northern California wildfires
Loss Contingencies [Line Items]
Third-Party Claims	$ 1,000	$ 2,500	3,500
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Total wildfire-related claims, net of insurance recoveries			11,771	0	125
Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Third-Party Claims			0	350	750
Insurance recoveries			(7)	(350)	(625)
Total wildfire-related claims, net of insurance recoveries			(7)	0	125
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Third-Party Claims			3,500	0	0
Insurance recoveries			(842)	0	0
Total wildfire-related claims, net of insurance recoveries			2,658	0	0
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Third-Party Claims			10,500	0	0
Insurance recoveries			(1,380)	0	0
Total wildfire-related claims, net of insurance recoveries			$ 9,120	$ 0	$ 0

WILDFIRE-RELATED CONTINGENCIE_3

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Claims Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Pacific Gas & Electric Co | Wildfires
Loss Contingencies [Line Items]
Legal and other costs	$ 245

WILDFIRE-RELATED CONTINGENCIE_4

WILDFIRE-RELATED CONTINGENCIES (Summary of Estimated Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 14,226	$ 561
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Total wildfire-related claims	14,226	561
Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Total wildfire-related claims	226	561
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Total wildfire-related claims	3,500	0
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 10,500	$ 0

WILDFIRE-RELATED CONTINGENCIE_5

WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire Background) (Details) - Pacific Gas & Electric Co - 2018 Camp fire	Dec. 11, 2018	Nov. 16, 2018report	Nov. 16, 2018report	Nov. 08, 2018report	Feb. 07, 2019fatality	Jan. 04, 2019abuildingresidencestructurefatality
Loss Contingencies [Line Items]
Number of Electric Incident Reports (report) | report		1	2	1
Electric Incident Report, term	20 days
Subsequent Event
Loss Contingencies [Line Items]
Number of acres burned (acre) | a						153,336
Number of fatalities (fatality) | fatality					85	86
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_6

WILDFIRE-RELATED CONTINGENCIES (2017 Northern California Wildfires Background) (Details) - Pacific Gas & Electric Co - 2017 Northern California wildfires a in Thousands, $ in Thousands	3 Months Ended
	Jun. 30, 2018wildfire	Dec. 31, 2018USD ($)wildfireincident_report	Oct. 30, 2017awildfirefatalitystructure
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
Number of fires in which determination has been reported on (wildfire)	16	19
Number of fires cause by trees contact with power lines (wildfire)	4
Number of fires caused by electric power and distribution lines, conductors and the failure of power poles (wildfire)	12
Number of electric incident reports submitted (incident report) | incident_report		23
Property damage coverage per incident | $		$ 50

WILDFIRE-RELATED CONTINGENCIE_7

WILDFIRE-RELATED CONTINGENCIES (Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) $ in Millions	Jan. 28, 2019complaintlawsuitplaintiff	Oct. 31, 2018USD ($)
Complaints Brought By Butte County District Attorney | Wildfires
Loss Contingencies [Line Items]
Settlement agreement term		4 years
Settlement expense | $		$ 1.5
Waiving of statutes of limitation, term		6 months
Pending Litigation | Subsequent Event | 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) | complaint	100
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	4,200
Pending Litigation | Subsequent Event | 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) | lawsuit	9
Pending Litigation | Subsequent Event | 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) | complaint	750
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	3,800
Pending Litigation | Subsequent Event | 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) | lawsuit	5
Pending Litigation | Subsequent Event | 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) | complaint	48
Pending Litigation | Subsequent Event | Subrogation 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) | lawsuit	37

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, $ in Millions	Jan. 28, 2019USD ($)	Sep. 06, 2018USD ($)insurance_claim	Dec. 31, 2018USD ($)	Dec. 31, 2015USD ($)
2018 Camp fire
Loss Contingencies [Line Items]
Loss in period			$ 10,500
2017 Northern California wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers (more than)		$ 12,280
Insurance claims received by insurers (insurance claim) | insurance_claim		55
Statewide insurance claims related to wildfire		$ 10,000
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Estimate of possible losses			$ 30,000
Subsequent Event | November 2018 Fires
Loss Contingencies [Line Items]
Total insurance claims received by insurers (more than)	$ 11,400
Subsequent Event | 2018 Camp fire
Loss Contingencies [Line Items]
Total insurance claims received by insurers (more than)	8,400
Subsequent Event | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers (more than)	$ 18,400
Pacific Gas & Electric Co | San Bruno Natural Gas Explosion
Loss Contingencies [Line Items]
Loss in period				$ 1,600
Loss contingency liability				$ 558

WILDFIRE-RELATED CONTINGENCIE_9

WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge) (Details) $ in Millions	Dec. 11, 2018	Dec. 31, 2018USD ($)wildfire	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)wildfire	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
2018 Camp fire
Loss Contingencies [Line Items]
Accrued losses				$ 10,500
2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of fires with probable losses (wildfire) | wildfire		17		17
Loss from claims related to wildfire		$ 1,000	$ 2,500	$ 3,500
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Electric Incident Report, term	20 days
Loss from claims related to wildfire				10,500	$ 0	$ 0
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire				$ 3,500	$ 0	$ 0

WILDFIRE-RELATED CONTINGENCI_10

WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) - USD ($) $ in Millions	Feb. 11, 2019	Dec. 31, 2018	Sep. 30, 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
2018 Camp fire
Loss Contingencies [Line Items]
Estimated insurance recoveries		$ 1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Estimated insurance recoveries		$ 842
Subsequent Event | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Estimated additional borrowings as part of reorganization	$ 3,000

WILDFIRE-RELATED CONTINGENCI_11

WILDFIRE-RELATED CONTINGENCIES (Summary of Insurance Receivables) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Reimbursements	$ (1,698)	$ (21)	$ (575)
2018 Camp fire
Loss Contingencies [Line Items]
Accrued insurance recoveries	1,380
Reimbursements	0
Insurance receivable	1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Accrued insurance recoveries	842
Reimbursements	(13)
Insurance receivable	$ 829

WILDFIRE-RELATED CONTINGENCI_12

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_13

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
Subsequent Event
Loss Contingencies [Line Items]
Number of public offerings of notes with complaints against underwriters (offering) | offering	4

WILDFIRE-RELATED CONTINGENCI_14

WILDFIRE-RELATED CONTINGENCIES (Clean-up and Repair Costs) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Capital expenditures	$ 368	$ 501	$ 403
Total long-term regulatory assets	4,964	3,793
Catastrophic event memorandum account
Loss Contingencies [Line Items]
Total long-term regulatory assets	790	274
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Capital expenditures	368	501	$ 403
Total long-term regulatory assets	4,964	$ 3,793
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Service restoration and repair costs	354
Capital expenditures	183
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Service restoration and repair costs	327
Capital expenditures	157
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Total long-term regulatory assets	$ 82

WILDFIRE-RELATED CONTINGENCI_15

WILDFIRE-RELATED CONTINGENCIES (2015 Butte Fire) (Details) - Pacific Gas & Electric Co - 2015 Butte fire household in Thousands, $ in Millions

Jan. 31, 2019contractorhouseholdcomplaintplaintiff

Nov. 13, 2018USD ($)

Sep. 06, 2018plaintiff

Mar. 02, 2018USD ($)

Mar. 01, 2018USD ($)

Apr. 13, 2017USD ($)

May 31, 2017USD ($)

Feb. 28, 2019USD ($)

Sep. 30, 2018plaintiff

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

May 01, 2018decision

May 23, 2016contractor

Apr. 28, 2016aoutbuildingfatalityhomecomercial_propertystructure

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 plaintiffs, smaller public entities (plaintiff) | plaintiff

5

Number of plaintiffs, fire districts (plaintiff) | plaintiff

3

Number of plaintiffs, water district (plaintiff) | plaintiff

1

Fire fighting costs recovery requested

$ 87

Value of claims brought against the company

$ 190

Reasonably possible loss to be incurred

$ 1,100

Coverage for third party liability

922

Probable insurance recoveries

922

Cumulative reimbursements from insurance policies

7

$ 350

$ 625

Reimbursements from insurance policies

7

Subsequent Event

Loss Contingencies [Line Items]

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

Reimbursements from insurance policies

$ 25

Agreement Reached in Litigation to Stipulate to Judgment on Inverse Condemnation Grounds

Loss Contingencies [Line Items]

Number of previous appellate courts decisions (decision) | decision

2

Number of plaintiffs in lawsuit (plaintiff) | plaintiff

2

County of Calaveras

Loss Contingencies [Line Items]

Value of claims brought against company

$ 167

$ 85

Settlement reached

$ 25.4

Vegetation Management Contractors

Loss Contingencies [Line Items]

Cumulative reimbursements from insurance policies

$ 60

WILDFIRE-RELATED CONTINGENCI_16

WILDFIRE-RELATED CONTINGENCIES (Schedule of Loss Accrual) (Details) - 2015 Butte fire - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	$ 561	$ 690	$ 0
Accrued losses	0	350	750
Payments	(335)	(479)	(60)
Loss accrual, ending balance	226	$ 561	$ 690
Pacific Gas & Electric Co
Loss Contingency Accrual [Roll Forward]
Settlement agreement paid	874
Settlement agreements entered	$ 904

WILDFIRE-RELATED CONTINGENCI_17

WILDFIRE-RELATED CONTINGENCIES (Schedule of Insurance Receivable) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Insurance Receivable [Roll Forward]
Reimbursements	$ (1,698)	$ (21)	$ (575)
2015 Butte fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	596	575	0
Accrued insurance recoveries	0	297	625
Reimbursements	(511)	(276)	(50)
Insurance Receivable, Ending Balance	$ 85	$ 596	$ 575

OTHER CONTINGENCIES AND COMMI_3

OTHER CONTINGENCIES AND COMMITMENTS (Enforcement Matters) (Details) - USD ($) $ in Thousands	Sep. 21, 2018	May 17, 2018	Apr. 26, 2018	Dec. 31, 2018
Pacific Gas & Electric Co | Electric
Loss Contingencies [Line Items]
Requested revenue rate	98.85%
Ex Parte Communications
Loss Contingencies [Line Items]
Proposed penalty			$ 97,500
Payment to State General Fund		$ 12,000	12,000
Gas transmission and storage revenue reduction			63,500
2018 GTandS revenue requirement reduction			31,750
2019 GTandS revenue requirement reduction			31,750
Revenue requirement reduction in Next GRC cycle			10,000
Payment to city of San Bruno		6,000	6,000
Payment to city of San Carlos		$ 6,000	$ 6,000
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Accrual for GTandS revenue requirement reduction				$ 32,000

OTHER CONTINGENCIES AND COMMI_4

OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Accrued legal liabilities	$ 98	$ 86

OTHER CONTINGENCIES AND COMMI_5

OTHER CONTINGENCIES AND COMMITMENTS (Disallowance of Plant Costs) (Details) - USD ($) $ in Millions	Jun. 23, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2014
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance	$ 696
Permanently disallowed capital	120
Amount subject to audit	$ 576
Capital expenditure charges		$ 219
2011-2014
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance				$ 134
2015-2018
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance			$ 44

OTHER CONTINGENCIES AND COMMI_6

OTHER CONTINGENCIES AND COMMITMENTS (Schedule Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]
Topock natural gas compressor station	$ 369	$ 334
Hinkley natural gas compressor station	146	147
Former manufactured gas plant sites owned by the Utility or third parties	520	320
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	111	115
Fossil fuel-fired generation facilities and sites	137	123
Total environmental remediation liability	$ 1,283	$ 1,039

OTHER CONTINGENCIES AND COMMI_7

OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) $ in Millions	Dec. 31, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 930
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 303
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	$ 141
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 518
Former Manufactured Gas Plant | Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
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	$ 135
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	$ 105

OTHER CONTINGENCIES AND COMMI_8

OTHER CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Loss Contingencies [Line Items]
Costs for insurance coverage	$ 360
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	1,400
Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	700
Catastrophic bond reinsurance instrument	10
Insurance Coverage for Property Damages
Loss Contingencies [Line Items]
Liability insurance coverage	700
Catastrophic bond reinsurance instrument	$ 200

OTHER CONTINGENCIES AND COMMI_9

OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Maximum total payment incurred per event under the loss sharing program	$ 450
Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	131
Amount of liability insurance for Humboldt Bay Unit 3	53
Diablo Canyon
Long-term Purchase Commitment [Line Items]
Maximum public liability per nuclear incident under Price-Anderson Act	14,100
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	450
Maximum annual payment incurred per event under the loss sharing program	275
Coverage for purchased public liability insurance, per incident	$ 41
Period for inflation adjustment	5 years
Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	$ 3,200
Nuclear Incident | Humboldt Bay Unit
Long-term Purchase Commitment [Line Items]
Amount of indemnification from the NRC for public liability arising from nuclear incidents	500
Non-Nuclear Incident
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,600
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation	47
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Full insurance policy limit	200
Potential premium obligation	$ 3

OTHER CONTINGENCIES AND COMM_10

OTHER CONTINGENCIES AND COMMITMENTS (Resolution of Remaining Chapter 11 Disputed Claims) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Disputed claims and customer refunds	$ 220	$ 243

OTHER CONTINGENCIES AND COMM_11

OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Third-Party Power Purchases) (Details) $ in Millions	Dec. 31, 2018USD ($)
Long-term Purchase Commitment [Line Items]
2,019	$ 3,491
2,020	3,209
2,021	2,978
2,022	2,703
2,023	2,340
Thereafter	25,125
Total purchase commitments	39,846
Renewable Energy
Long-term Purchase Commitment [Line Items]
2,019	2,221
2,020	2,183
2,021	2,174
2,022	1,984
2,023	1,914
Thereafter	24,217
Total purchase commitments	34,693
Conventional Energy
Long-term Purchase Commitment [Line Items]
2,019	642
2,020	639
2,021	582
2,022	511
2,023	223
Thereafter	435
Total purchase commitments	3,032
Other
Long-term Purchase Commitment [Line Items]
2,019	108
2,020	83
2,021	65
2,022	61
2,023	61
Thereafter	162
Total purchase commitments	540
Natural Gas
Long-term Purchase Commitment [Line Items]
2,019	412
2,020	153
2,021	93
2,022	93
2,023	93
Thereafter	264
Total purchase commitments	1,108
Nuclear Fuel
Long-term Purchase Commitment [Line Items]
2,019	108
2,020	151
2,021	64
2,022	54
2,023	49
Thereafter	47
Total purchase commitments	$ 473

OTHER CONTINGENCIES AND COMM_12

OTHER CONTINGENCIES AND COMMITMENTS (Purchase and Commitment Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Nuclear Fuel
Third-Party Power Purchase Agreements [Line Items]
Payments for nuclear fuel	$ 73	$ 83	$ 100
Qualifying Facilities
Third-Party Power Purchase Agreements [Line Items]
Capitalized asset for fixed capacity payments for corresponding assets	11	18
Capitalized asset for fixed capacity payments, accumulated amortization	8	143
Present value of fixed capacity payments, portion classified as current liabilities	2	11
Present value of fixed capacity payments, portion classified as noncurrent liabilities	9	7
Power Purchases and Electric Capacity
Third-Party Power Purchase Agreements [Line Items]
Costs incurred for power purchases and electric capacity	3,100	3,300	3,500
Gas Contracts
Third-Party Power Purchase Agreements [Line Items]
Cost of goods	$ 600	$ 900	$ 700

OTHER CONTINGENCIES AND COMM_13

OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Future Minimum Operating Lease Payments) (Details) $ in Millions	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,019	$ 44
2,020	41
2,021	36
2,022	28
2,023	19
Thereafter	121
Total minimum lease payments	$ 289

OTHER CONTINGENCIES AND COMM_14

OTHER CONTINGENCIES AND COMMITMENTS (Other Commitments) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Payments for operating leases	$ 43	$ 45	$ 43
Minimum
Operating Leased Assets [Line Items]
Extension option for operating leases	1 year
Maximum
Operating Leased Assets [Line Items]
Extension option for operating leases	5 years

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details)	Jan. 26, 2017USD ($)	Feb. 28, 2019USD ($)	Feb. 01, 2019USD ($)	Jan. 04, 2019wildfire	Dec. 31, 2018USD ($)	Oct. 30, 2017wildfire	Aug. 09, 2016count
DIP Revolving Facility
Subsequent Event [Line Items]
Remaining borrowings capacity					$ 35,000,000
DIP Revolving Facility | DIP Credit Agreement | Line of Credit | Subsequent Event
Subsequent Event [Line Items]
Borrowings available			$ 1,500,000,000
Letter of Credit Subfacility | DIP Credit Agreement | Line of Credit | Subsequent Event
Subsequent Event [Line Items]
Letters of credit available			$ 750,000,000
Pacific Gas & Electric Co | 2017 Northern California wildfires
Subsequent Event [Line Items]
Number of wildfires (wildfire) | wildfire						21
Pacific Gas & Electric Co | Judicial Ruling | Unfavorable Regulatory Action
Subsequent Event [Line Items]
Number of guilty counts of obstructing a federal agency proceeding | count							1
Number of guilty counts of violating pipeline integrity management regulations | count							5
Corporate probation period, term	5 years
Oversight by third-party monitor period, term	5 years
Oversight by third-party monitor period, application for early termination, term	3 years
Damages awarded	$ 3,000,000
Pacific Gas & Electric Co | Subsequent Event | 2017 Northern California wildfires
Subsequent Event [Line Items]
Number of wildfires (wildfire) | wildfire				18
Pacific Gas & Electric Co | DIP Revolving Facility
Subsequent Event [Line Items]
Remaining borrowings capacity					$ 35,000,000
Pacific Gas & Electric Co | DIP Revolving Facility | DIP Credit Agreement | Line of Credit | Subsequent Event
Subsequent Event [Line Items]
Borrowings available		$ 350,000,000
Remaining borrowings capacity		1,120,000,000
Pacific Gas & Electric Co | Letter of Credit Subfacility | DIP Credit Agreement | Line of Credit | Subsequent Event
Subsequent Event [Line Items]
Letters of credit available		$ 30,000,000

SCHEDULE I _ CONDENSED FINANC_3

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Income Statement and Comprehensive Income) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue	$ 16,759	$ 17,135	$ 17,666
Operating expenses	(26,459)	(14,230)	(15,586)
Interest income	76	31	23
Interest expense	(929)	(888)	(829)
Other income, net	424	123	188
Income (Loss) Before Income Taxes	(10,129)	2,171	1,462
Income tax provision (benefit)	(3,292)	511	55
Income (Loss) Available for Common Shareholders	(6,851)	1,646	1,393
Other Comprehensive Income
Pension and other postretirement benefit plans obligations	4	1	(2)
Total other comprehensive income (loss)	$ 4	$ 1	$ (2)
Weighted Average Common Shares Outstanding, Basic (in shares)	517	512	499
Weighted Average Common Shares Outstanding, Diluted (in shares)	517	513	501
Net Earnings (Loss) Per Common Share, Basic (in dollars per share)	$ (13.25)	$ 3.21	$ 2.79
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share)	$ (13.25)	$ 3.21	$ 2.78
Pension and other postretirement benefit plans obligations, tax	$ 2	$ 0	$ 1
Net change in investments, tax	0	0	0
PG&E Corporation
Operating expenses	(91)	(5)	(73)
Interest income	2	1	1
Interest expense	(15)	(11)	(10)
Other income, net	(2)	4	2
Equity in earnings of subsidiaries	(6,832)	1,667	1,388
Income (Loss) Before Income Taxes	(6,848)	1,719	1,378
Income tax provision (benefit)	3	73	(15)
Income (Loss) Available for Common Shareholders	(6,851)	1,646	1,393
Other Comprehensive Income
Pension and other postretirement benefit plans obligations	4	1	(2)
Total other comprehensive income (loss)	4	1	(2)
Comprehensive Income	$ (6,847)	$ 1,647	$ 1,391
Weighted Average Common Shares Outstanding, Basic (in shares)	517	512	499
Weighted Average Common Shares Outstanding, Diluted (in shares)	517	513	501
Net Earnings (Loss) Per Common Share, Basic (in dollars per share)	$ (13.25)	$ 3.21	$ 2.79
Net Earnings (Loss) Per Common Share, Diluted (in dollars per share)	$ (13.25)	$ 3.21	$ 2.78
Pension and other postretirement benefit plans obligations, tax	$ 0	$ 0	$ 1
Net change in investments, tax	0	0	0
Administrative service revenue | PG&E Corporation
Revenue	$ 90	$ 63	$ 70

SCHEDULE I _ CONDENSED FINANC_4

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 1,668	$ 449	$ 177
Income taxes receivable	23	0
Total current assets	9,195	6,281
Noncurrent Assets
Equipment	83,272	77,248
Accumulated depreciation	(24,715)	(23,459)
Net property, plant, and equipment	58,557	53,789
TOTAL ASSETS	76,995	68,012
Current Liabilities
Short-term borrowings	3,435	931
Long-term debt, classified as current	18,559	445
Other	1,512	1,449
Total current liabilities	41,695	7,129
Noncurrent Liabilities
Long-term debt	0	17,753
Other	2,464	2,130
Total noncurrent liabilities	22,397	41,411
Common Shareholders’ Equity
Common stock, no par value	12,910	12,632
Reinvested earnings	(250)	6,596
Accumulated other comprehensive income (loss)	(9)	(8)
Total shareholders' equity	12,651	19,220
TOTAL LIABILITIES AND EQUITY	76,995	68,012
PG&E Corporation
Current Assets
Cash and cash equivalents	373	2	$ 106	$ 64
Advances to affiliates	44	24
Income taxes receivable	18	27
Total current assets	435	53
Noncurrent Assets
Equipment	2	3
Accumulated depreciation	(2)	(3)
Net property, plant, and equipment	0	0
Investments in subsidiaries	12,722	19,514
Other investments	162	144
Intercompany receivable	0	72
Deferred income taxes	187	123
Total noncurrent assets	13,071	19,853
TOTAL ASSETS	13,506	19,906
Current Liabilities
Short-term borrowings	300	132
Long-term debt, classified as current	350	0
Accounts payable – other	16	6
Other	17	23
Total current liabilities	683	161
Noncurrent Liabilities
Long-term debt	0	350
Other	172	175
Total noncurrent liabilities	172	525
Common Shareholders’ Equity
Common stock, no par value	12,910	12,632
Reinvested earnings	(250)	6,596
Accumulated other comprehensive income (loss)	(9)	(8)
Total shareholders' equity	12,651	19,220
TOTAL LIABILITIES AND EQUITY	$ 13,506	$ 19,906

SCHEDULE I _ CONDENSED FINANC_5

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT (Schedule of Condensed Statement of Cash Flows) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended									12 Months Ended
	Oct. 31, 2017	Jul. 31, 2017	Apr. 30, 2017	Jan. 31, 2017	Oct. 31, 2016	Jul. 31, 2016	Apr. 30, 2016	Jan. 31, 2016	Jan. 31, 2015	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net income										$ (6,837)	$ 1,660	$ 1,407
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes and tax credits, net										(2,532)	1,254	1,030
Net cash provided by operating activities										4,752	5,977	4,409
Cash Flows from Investing Activities
Net cash used in investing activities										(6,564)	(5,650)	(5,753)
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities										3,960	0	0
Repayments under revolving credit facilities										(775)	0	0
Net issuances (repayments) of commercial paper, net of discount of $1 in 2017										(182)	(840)	(9)
Short-term debt financing										600	750	500
Long-term debt matured or repurchased										(795)	(1,445)	(160)
Common stock issued										200	395	822
Common stock dividends paid										0	(1,021)	(921)
Net cash provided by (used in) financing activities										3,031	(55)	1,171
Cash and cash equivalents, beginning of period				$ 177						449	177
Cash and cash equivalents, end of period										1,668	449	177
Cash received (paid) for:
Interest, net of amounts capitalized										(786)	(790)	(726)
Income taxes, net										(49)	162	231
Supplemental disclosure of noncash investing and financing activities
Common stock dividends declared but not yet paid										0	0	248
Noncash common stock issuances										0	21	20
Discount on net issuances of commercial paper										1	5	6
PG&E Corporation
Cash Flows from Operating Activities
Net income										(6,851)	1,646	1,393
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization										78	20	74
Equity in earnings of subsidiaries										6,833	(1,667)	(1,388)
Deferred income taxes and tax credits, net										(62)	139	11
Current income taxes receivable/payable										9	(2)	(1)
Other										41	(75)	(24)
Net cash provided by operating activities										48	61	65
Cash Flows from Investing Activities
Investment in subsidiaries										(45)	(455)	(835)
Dividends received from subsidiaries										0	784	911
Net cash used in investing activities										(45)	329	76
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities										425	0	0
Repayments under revolving credit facilities										(125)	0	0
Net issuances (repayments) of commercial paper, net of discount of $1 in 2017										(132)	132	0
Short-term debt financing										350	0	0
Long-term debt matured or repurchased										(350)	0	0
Common stock issued										200	395	822
Common stock dividends paid										0	(1,021)	(921)
Net cash provided by (used in) financing activities										368	(494)	(99)
Net change in cash, cash equivalents, and restricted cash										371	(104)	42
Cash and cash equivalents, beginning of period				$ 106				$ 64		2	106	64
Cash and cash equivalents, end of period										373	2	106
Cash received (paid) for:
Interest, net of amounts capitalized										(13)	(9)	(9)
Income taxes, net										10	0	(13)
Supplemental disclosure of noncash investing and financing activities
Common stock dividends declared but not yet paid										0	0	248
Noncash common stock issuances										$ 0	21	$ 20
Common stock dividends paid per share (in dollars per share)	$ 0.53	$ 0.53	$ 0.49	$ 0.49	$ 0.49	$ 0.49	$ 0.455	$ 0.455	$ 0.455
Discount on net issuances of commercial paper											$ 1

SCHEDULE II _ CONSOLIDATED VA_2

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 64	$ 58	$ 54
Charged to Costs and Expenses	34	55	50
Charged to Other Accounts	0	0	0
Deductions	42	49	46
Balance at End of Period	56	64	58
Pacific Gas & Electric Co
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	64	58
Balance at End of Period	$ 56	$ 64	$ 58

Uncategorized Items - pcg-20181

Label	Element	Value
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 29,000,000
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	29,000,000
Retained Earnings [Member] | Pacific Gas & Electric Co [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	24,000,000
Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	29,000,000
Parent [Member] | Pacific Gas & Electric Co [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 24,000,000