PG&E (PCG) 10-Q 5 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 25, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
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 Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		518,674,276
Pacific Gas & Electric Co
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
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 Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding		264,374,809

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues
Total operating revenues	$ 4,381	$ 4,517	$ 12,671	$ 13,035
Operating Expenses
Operating and maintenance	1,611	1,324	5,001	4,453
Wildfire-related claims, net of insurance recoveries	(10)	53	2,108	0
Depreciation, amortization, and decommissioning	759	710	2,257	2,134
Total operating expenses	3,685	3,631	12,841	10,547
Operating Income (Loss)	696	886	(170)	2,488
Interest income	14	9	35	22
Interest expense	(232)	(220)	(678)	(663)
Other income, net	104	38	318	98
Income (Loss) Before Income Taxes	582	713	(495)	1,945
Income tax provision (benefit)	15	160	(527)	403
Net Income	567	553	32	1,542
Preferred stock dividend requirement of subsidiary	3	3	10	10
Preferred stock dividend requirement			0
Income Available for Common Shareholders	$ 564	$ 550	$ 22	$ 1,532
Weighted Average Common Shares Outstanding, Basic (in shares)	517	513	516	511
Weighted Average Common Shares Outstanding, Diluted (in shares)	517	516	517	514
Net Earnings Per Common Share, Basic (in dollars per share)	$ 1.09	$ 1.07	$ 0.04	$ 3
Net Earnings Per Common Share, Diluted (in dollars per share)	$ 1.09	$ 1.07	$ 0.04	$ 2.98
Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	$ 4,382	$ 4,516	$ 12,672	$ 13,037
Operating Expenses
Operating and maintenance	1,611	1,389	5,002	4,518
Wildfire-related claims, net of insurance recoveries	(10)	53	2,108	0
Depreciation, amortization, and decommissioning	759	710	2,257	2,134
Total operating expenses	3,685	3,696	12,842	10,612
Operating Income (Loss)	697	820	(170)	2,425
Interest income	14	10	34	22
Interest expense	(229)	(217)	(668)	(655)
Other income, net	103	38	321	93
Income (Loss) Before Income Taxes	585	651	(483)	1,885
Income tax provision (benefit)	14	138	(530)	394
Net Income	571	513	47	1,491
Preferred stock dividend requirement of subsidiary			0
Preferred stock dividend requirement	3	3	10	10
Income Available for Common Shareholders	568	510	37	1,481
Electric
Operating Revenues
Total operating revenues	3,466	3,648	9,729	10,036
Operating Expenses
Cost of goods	1,256	1,466	3,038	3,436
Electric | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	3,467	3,647	9,730	10,038
Operating Expenses
Cost of goods	1,256	1,466	3,038	3,436
Natural gas
Operating Revenues
Total operating revenues	915	869	2,942	2,999
Operating Expenses
Cost of goods	69	78	437	524
Natural gas | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	915	869	2,942	2,999
Operating Expenses
Cost of goods	$ 69	$ 78	$ 437	$ 524

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net Income	$ 567	$ 553	$ 32	$ 1,542
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	1	0	1	1
Total other comprehensive income	1	0	1	1
Comprehensive Income	568	553	33	1,543
Preferred stock dividend requirement of subsidiary	3	3	10	10
Comprehensive Income Attributable to Common Shareholders	565	550	23	1,533
Pacific Gas & Electric Co
Net Income	571	513	47	1,491
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	0	0	1	1
Total other comprehensive income	0	0	1	1
Comprehensive Income	$ 571	$ 513	$ 48	$ 1,492

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Pacific Gas & Electric Co
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 430	$ 449
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates)	1,297	1,243
Accrued unbilled revenue	962	946
Regulatory balancing accounts	1,326	1,222
Other	902	861
Regulatory assets	229	615
Inventories:
Gas stored underground and fuel oil	116	115
Materials and supplies	389	366
Other	698	464
Total current assets	6,349	6,281
Property, Plant, and Equipment
Electric	56,860	55,133
Gas	20,798	19,641
Construction work in progress	2,855	2,471
Other	2	3
Total property, plant, and equipment	80,515	77,248
Accumulated depreciation	(24,310)	(23,459)
Net property, plant, and equipment	56,205	53,789
Other Noncurrent Assets
Regulatory assets	4,429	3,793
Nuclear decommissioning trusts	2,917	2,863
Income taxes receivable	67	65
Other	1,418	1,221
Total other noncurrent assets	8,831	7,942
TOTAL ASSETS	71,385	68,012
Current Liabilities
Short-term borrowings	750	931
Long-term debt, classified as current	193	445
Accounts payable:
Trade creditors	1,699	1,646
Regulatory balancing accounts	1,230	1,120
Other	556	517
Disputed claims and customer refunds	217	243
Interest payable	151	217
Wildfire-related claims	2,794	561
Other	1,899	1,449
Total current liabilities	9,489	7,129
Noncurrent Liabilities
Long-term debt	18,407	17,753
Regulatory liabilities	8,607	8,679
Pension and other post-retirement benefits	2,014	2,128
Asset retirement obligations	4,999	4,899
Deferred income taxes	5,822	5,822
Other	2,351	2,130
Total noncurrent liabilities	42,200	41,411
Contingencies and Commitments (Note 9)
Shareholders' Equity
Common stock	12,833	12,632
Reinvested earnings	6,623	6,596
Accumulated other comprehensive income (loss)	(12)	(8)
Total shareholders' equity	19,444	19,220
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	19,696	19,472
TOTAL LIABILITIES AND EQUITY	71,385	68,012
Pacific Gas & Electric Co
Current Assets
Cash and cash equivalents	371	447
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates)	1,297	1,243
Accrued unbilled revenue	962	946
Regulatory balancing accounts	1,326	1,222
Other	902	862
Regulatory assets	229	615
Inventories:
Gas stored underground and fuel oil	116	115
Materials and supplies	389	366
Other	698	465
Total current assets	6,290	6,281
Property, Plant, and Equipment
Electric	56,860	55,133
Gas	20,798	19,641
Construction work in progress	2,855	2,471
Total property, plant, and equipment	80,513	77,245
Accumulated depreciation	(24,308)	(23,456)
Net property, plant, and equipment	56,205	53,789
Other Noncurrent Assets
Regulatory assets	4,429	3,793
Nuclear decommissioning trusts	2,917	2,863
Income taxes receivable	66	64
Other	1,289	1,094
Total other noncurrent assets	8,701	7,814
TOTAL ASSETS	71,196	67,884
Current Liabilities
Short-term borrowings	750	799
Long-term debt, classified as current	193	445
Accounts payable:
Trade creditors	1,699	1,644
Regulatory balancing accounts	1,230	1,120
Other	575	538
Disputed claims and customer refunds	217	243
Interest payable	149	214
Wildfire-related claims	2,794	561
Other	1,904	1,457
Total current liabilities	9,511	7,021
Noncurrent Liabilities
Long-term debt	18,057	17,403
Regulatory liabilities	8,607	8,679
Pension and other post-retirement benefits	1,910	2,026
Asset retirement obligations	4,999	4,899
Deferred income taxes	5,960	5,963
Other	2,367	2,146
Total noncurrent liabilities	41,900	41,116
Contingencies and Commitments (Note 9)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,505	8,505
Reinvested earnings	9,695	9,656
Accumulated other comprehensive income (loss)	5	6
Total shareholders' equity	19,785	19,747
Total equity	19,785	19,747
TOTAL LIABILITIES AND EQUITY	$ 71,196	$ 67,884

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Allowance for doubtful accounts	$ 58	$ 64
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	517,102,983	514,755,845
Pacific Gas & Electric Co
Allowance for doubtful accounts	$ 58	$ 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

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Cash Flows from Operating Activities
Net income	$ 567	$ 553	$ 32	$ 1,542
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning			2,257	2,134
Allowance for equity funds used during construction			(97)	(63)
Deferred income taxes and tax credits, net			10	848
Disallowed capital expenditures			(38)	47
Other			231	204
Effect of changes in operating assets and liabilities:
Accounts receivable			(201)	(58)
Wildfire-related insurance receivable			64	(166)
Inventories			(24)	(35)
Accounts payable			245	76
Wildfire-related claims			2,233	12
Income taxes receivable/payable			0	135
Other current assets and liabilities			(154)	23
Regulatory assets, liabilities, and balancing accounts, net			(128)	(30)
Other noncurrent assets and liabilities			(194)	68
Net cash provided by operating activities			4,236	4,737
Cash Flows from Investing Activities
Capital expenditures			(4,592)	(3,938)
Proceeds from sales and maturities of nuclear decommissioning trust investments	319	249	1,121	1,043
Purchases of nuclear decommissioning trust investments			(1,165)	(1,071)
Other			19	16
Net cash used in investing activities			(4,617)	(3,950)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities			775	0
Repayments under revolving credit facilities			(775)	0
Net issuances (repayments) of commercial paper, net of discount			(182)	(652)
Short-term debt financing			250	250
Short-term debt matured			(250)	(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7 and $11 at respective dates			1,143	734
Long-term debt matured or repurchased			(750)	(345)
Common stock issued			137	345
Common stock dividends paid			0	(754)
Other			14	(101)
Net cash provided by (used in) financing activities			362	(773)
Net change in cash and cash equivalents			(19)	14
Cash and cash equivalents at January 1			449	177	$ 177
Cash and cash equivalents at September 30	430	191	430	191	449
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized			(650)	(644)
Income taxes, net			(49)	158
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	0	272	0	272
Capital expenditures financed through accounts payable			348	301
Noncash common stock issuances			0	16
Terminated capital leases			161	0
Pacific Gas & Electric Co
Cash Flows from Operating Activities
Net income	571	513	47	1,491
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning			2,257	2,134
Allowance for equity funds used during construction			(97)	(63)
Deferred income taxes and tax credits, net			5	848
Disallowed capital expenditures			(38)	47
Other			170	196
Effect of changes in operating assets and liabilities:
Accounts receivable			(200)	(58)
Wildfire-related insurance receivable			64	(166)
Inventories			(24)	(35)
Accounts payable			245	76
Wildfire-related claims			2,233	12
Income taxes receivable/payable			0	135
Other current assets and liabilities			(156)	36
Regulatory assets, liabilities, and balancing accounts, net			(128)	(30)
Other noncurrent assets and liabilities			(194)	69
Net cash provided by operating activities			4,184	4,692
Cash Flows from Investing Activities
Capital expenditures			(4,592)	(3,938)
Proceeds from sales and maturities of nuclear decommissioning trust investments			1,121	1,043
Purchases of nuclear decommissioning trust investments			(1,165)	(1,071)
Other			19	16
Net cash used in investing activities			(4,617)	(3,950)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities			650	0
Repayments under revolving credit facilities			(650)	0
Net issuances (repayments) of commercial paper, net of discount			(50)	(652)
Short-term debt financing			250	250
Short-term debt matured			(250)	(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7 and $11 at respective dates			793	734
Long-term debt matured or repurchased			(400)	(345)
Preferred stock dividends paid			0	(10)
Common stock dividends paid			0	(784)
Equity contribution from PG&E Corporation			0	405
Other			14	(91)
Net cash provided by (used in) financing activities			357	(743)
Net change in cash and cash equivalents			(76)	(1)
Cash and cash equivalents at January 1			447	71	71
Cash and cash equivalents at September 30	$ 371	$ 70	371	70	$ 447
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized			(640)	(636)
Income taxes, net			(59)	158
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable			348	301
Terminated capital leases			$ 161	$ 0

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Discount on net issuances of commercial paper	$ 1	$ 4
Premium, discount, and issuance costs on proceeds from long-term debt	7	11
Pacific Gas & Electric Co
Discount on net issuances of commercial paper	0	4
Premium, discount, and issuance costs on proceeds from long-term debt	$ 7	$ 11

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2017 Form 10-K. This quarterly report should be read in conjunction with the 2017 Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other post-retirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred. 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 “Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities. Cal Fire issued its determination on the causes of 17 of the Northern California wildfires, and alleged that each of these fires 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. Additionally, the Northern California wildfires are under investigation by the CPUC’s SED. See “Northern California Wildfires” in Note 9 below.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2018 , the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2018 , it did not consolidate any of them. Pension and Other Post-Retirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned (1) $ 128 $ 118 $ 16 $ 14 Interest cost 171 178 17 20 Expected return on plan assets (255 ) (193 ) (33 ) (24 ) Amortization of prior service cost (1 ) (1 ) 4 4 Amortization of net actuarial loss 1 6 (1 ) 1 Net periodic benefit cost 44 108 3 15 Regulatory account transfer (2) 41 (23 ) — — Total $ 85 $ 85 $ 3 $ 15 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned (1) $ 385 $ 354 $ 49 $ 44 Interest cost 515 535 52 58 Expected return on plan assets (766 ) (578 ) (98 ) (73 ) Amortization of prior service cost (4 ) (5 ) 11 12 Amortization of net actuarial loss 4 17 (4 ) 3 Net periodic benefit cost 134 323 10 44 Regulatory account transfer (2) 118 (69 ) — — Total $ 252 $ 254 $ 10 $ 44 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Total (in millions, net of income tax) Three Months Ended September 30, 2018 Beginning balance $ (30 ) $ 17 $ (13 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) (1 ) 3 2 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1) 1 (1 ) — Regulatory account transfer (net of taxes of $0 and $1, respectively) (1) 1 (2 ) (1 ) Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (29 ) $ 17 $ (12 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ (25 ) $ 17 $ (8 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) (1 ) 2 1 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $2 and $2, respectively) (3 ) (3 ) (6 ) Net current period other comprehensive gain (loss) — — — Ending balance $ (25 ) $ 17 $ (8 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $1 and $3, respectively) (1) (3 ) 8 5 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) 3 (3 ) — Regulatory account transfer (net of taxes of $0 and $2, respectively) (1) 1 (5 ) (4 ) Reclassification of stranded income tax to retained earnings (5 ) — (5 ) Net current period other comprehensive gain (loss) $ (4 ) $ — $ (4 ) Ending balance (29 ) 17 (12 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) (3 ) 7 4 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 10 2 12 Regulatory account transfer (net of taxes of $5 and $6, respectively) (7 ) (8 ) (15 ) Net current period other comprehensive gain (loss) $ — $ 1 $ 1 Ending balance (25 ) 17 (8 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above. 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 Condensed Consolidated Financial Statements as of the adoption date or for the three and nine months ended September 30, 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. Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. 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 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’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months . Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer: (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Electric Revenue from contracts with customers Residential $ 1,649 $ 4,023 Commercial 1,430 3,737 Industrial 448 1,126 Agricultural 523 966 Public street and highway lighting 18 55 Other (1) (273 ) (388 ) Total revenue from contracts with customers - electric 3,795 9,519 Regulatory balancing accounts (2) (328 ) 211 Total electric operating revenue $ 3,467 $ 9,730 Natural gas Revenue from contracts with customers Residential $ 242 $ 1,652 Commercial 87 402 Transportation service only 287 847 Other (1) 30 (149 ) Total revenue from contracts with customers - gas 646 2,752 Regulatory balancing accounts (2) 269 190 Total natural gas operating revenue 915 2,942 Total operating revenues $ 4,382 $ 12,672 (1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU 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 Condensed 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 $13 million and $14 million for PG&E Corporation and the Utility, respectively, for the three months ended September 30, 2017 and $39 million and $41 million for PG&E Corporation and the Utility, respectively, for the nine months ended September 30, 2017 . 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 Condensed 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 Condensed 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 Condensed 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 lease 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 asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility intend to elect 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 expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and related disclosures. 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	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	REGULATORY A SSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Long-Term Regulatory Assets Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2018 December 31, 2017 Pension benefits $ 1,837 $ 1,954 Environmental compliance costs 851 837 Utility retained generation 285 319 Price risk management 67 65 Unamortized loss, net of gain, on reacquired debt 80 79 Catastrophic event memorandum account (1) 760 274 Wildfire expense memorandum account (2) 77 — Fire hazard prevention memorandum account (3) 65 1 Other 407 264 Total long-term regulatory assets $ 4,429 $ 3,793 (1) Represents costs related to certain catastrophic events that the Utility believes are probable of recovery. For more information, see Note 9 below. (2) Represents costs related to insurance premiums that the Utility believes are probable of recovery. For more information, see Note 9 below. (3) Represents costs related to wildfire prevention vegetation management work that the Utility believes are probable of recovery. Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2018 December 31, 2017 Cost of removal obligations $ 5,888 $ 5,547 Deferred income taxes 437 1,021 Recoveries in excess of AROs 489 624 Public purpose programs 660 590 Other 1,133 897 Total long-term regulatory liabilities $ 8,607 $ 8,679 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2018 December 31, 2017 Electric distribution $ 31 $ — Electric transmission 109 139 Gas distribution and transmission 624 486 Energy procurement 131 71 Public purpose programs 120 103 Other 311 423 Total regulatory balancing accounts receivable $ 1,326 $ 1,222 Payable Balance at (in millions) September 30, 2018 December 31, 2017 Electric distribution $ — $ 72 Electric transmission 132 120 Utility generation 70 14 Gas distribution and transmission 9 — Energy procurement 69 149 Public purpose programs 588 452 Other 362 313 Total regulatory balancing accounts payable $ 1,230 $ 1,120 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.

DEBT

DEBT	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
DEBT	DEBT Revolving Credit Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2018 : (in millions) Termination Date Facility Limit Letters of Credit Outstanding Borrowings Facility Availability PG&E Corporation April 2022 $ 300 (1) $ — $ — $ 300 Utility April 2022 3,000 (2) 87 — 2,913 Total revolving credit facilities $ 3,300 $ 87 $ — $ 3,213 (1) Includes a $50 million lender commitment to the letter of credit sublimit 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 sublimit and a $75 million commitment for swingline loans. 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. Additionally, in February 2018, the Utility entered into a $250 million floating rate unsecured term loan that will mature on February 22, 2019. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Long-term Debt Issuances and Redemptions During the first quarter of 2018, the Utility satisfied and discharged its remaining obligation of $400 million aggregate principal amount of the 8.25% Senior Notes due October 15, 2018. In April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. The term loan will mature on April 16, 2020, unless extended by PG&E Corporation pursuant to the terms of the term loan agreement. The proceeds were used for general corporate purposes, including the early redemption of PG&E Corporation’s outstanding $350 million principal amount of 2.40% Senior Notes due March 1, 2019. On April 26, 2018, PG&E Corporation completed the early redemption of these bonds, which satisfied and discharged its remaining obligation of $350 million. In August 2018, the Utility issued $ 500 million principal amount of 4.25% Senior Notes due August 1, 2023 and $ 300 million principal amount of 4.65% Senior Notes due August 1, 2028. The proceeds will be used to repay $500 million floating rate Senior Notes due November 28, 2018, to repay a $250 million term loan maturing on February 22, 2019 and for general corporate purposes. Variable Rate Interest At September 30, 2018 , the interest rates on the $ 614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 1.55% to 1.68% . At September 30, 2018 , the interest rates on the $ 149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 1.60% .

EQUITY

EQUITY	9 Months Ended
	Sep. 30, 2018
Stockholders' Equity Note [Abstract]
EQUITY	EQUITY PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2018 were as follows: PG&E Corporation Utility (in millions) Total Equity Total Shareholders' Equity Balance at December 31, 2017 $ 19,472 $ 19,747 Comprehensive income 33 48 Common stock issued 137 — Share-based compensation 64 — Preferred stock dividend requirement — (10 ) Preferred stock dividend requirement of subsidiary (10 ) — Balance at September 30, 2018 $ 19,696 $ 19,785 There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the nine months ended September 30, 2018 . As of September 30, 2018 , the remaining amount available under this agreement was $ 246.3 million. PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans. During the nine months ended September 30, 2018 , 3.6 million shares were issued for cash proceeds of $ 136.7 million under these plans. Dividends On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the Northern California wildfires. The dividends declared per share on PG&E Corporation's common stock were $0 and $0.53 , for the three months ended September 30, 2018 and 2017 , respectively, and $0 and $1.55 for the nine months ended September 30, 2018 and 2017 , respectively.

EARNINGS PER SHARE

EARNINGS PER SHARE	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE PG&E Corporation’s basic EPS are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2018 2017 2018 2017 Income available for common shareholders $ 564 $ 550 $ 22 $ 1,532 Weighted average common shares outstanding, basic 517 513 516 511 Add incremental shares from assumed conversions: Employee share-based compensation — 3 1 3 Weighted average common shares outstanding, diluted 517 516 517 514 Total earnings per common share, diluted $ 1.09 $ 1.07 $ 0.04 $ 2.98 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

DERIVATIVES

DERIVATIVES	9 Months Ended
	Sep. 30, 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 Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments September 30, December 31, Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 250,021,802 228,768,745 Options 29,534,224 60,736,806 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,939,691 2,872,013 Congestion Revenue Rights (3) 316,451,690 312,272,177 (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 September 30, 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 $ 34 $ (2 ) $ 5 $ 37 Other noncurrent assets – other 88 — — 88 Current liabilities – other (39 ) 2 12 (25 ) Noncurrent liabilities – other (67 ) — 4 (63 ) Total commodity risk $ 16 $ — $ 21 $ 37 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 Condensed 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. The Utility’s credit rating remains investment grade. If the Utility credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. The Utility held derivatives with a net liability fair value of $44 million and $1 million at September 30, 2018 and December 31, 2017 , respectively, offset by an immaterial amount from related derivatives in an asset position. If the credit-risk-related contingency feature were triggered, at September 30, 2018 , the Utility would be required to post additional collateral immediately in the amount of $12 million .

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 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 September 30, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 377 — — — $ 377 Nuclear decommissioning trusts Short-term investments 14 — — — 14 Global equity securities 1,970 — — — 1,970 Fixed-income securities 738 631 — — 1,369 Assets measured at NAV — — — — 19 Total nuclear decommissioning trusts (2) 2,722 631 — — 3,372 Price risk management instruments (Note 7) Electricity 1 5 110 2 118 Gas — 6 — 1 7 Total price risk management instruments 1 11 110 3 125 Rabbi trusts Fixed-income securities — 75 — — 75 Life insurance contracts — 68 — — 68 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 8 — — — 8 Assets measured at NAV — — — — 112 Total long-term disability trust 8 — — — 120 TOTAL ASSETS $ 3,108 $ 785 $ 110 $ 3 $ 4,137 Liabilities: Price risk management instruments (Note 7) Electricity $ 5 $ 12 $ 86 $ (17 ) $ 86 Gas — 3 — (1 ) 2 TOTAL LIABILITIES $ 5 $ 15 $ 86 $ (18 ) $ 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 $455 million , primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements 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 7) 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 7) 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 nine months ended September 30, 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 Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.) Fair Value at (in millions) September 30, 2018 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 110 $ 44 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 42 Discounted cash flow Forward prices $ 19.81 - 38.80 (1) Represents price per megawatt-hour. Fair Value at (in millions) December 31, 2017 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input 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 tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2018 and 2017 : Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of July 1 $ 34 $ 48 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (10 ) — Asset (liability) balance as of September 30 $ 24 $ 48 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Price Risk Management Instruments (in millions) 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) (18 ) (7 ) Asset (liability) balance as of September 30 $ 24 $ 48 (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 September 30, 2018 and December 31, 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 debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2018 At December 31, 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation (1) $ 350 $ 350 $ 350 $ 350 Utility 17,491 16,413 17,090 19,128 (1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Note. 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) As of September 30, 2018 Amortized Total Total Total Fair Nuclear decommissioning trusts Short-term investments $ 14 $ — $ — $ 14 Global equity securities 478 1,513 (2 ) 1,989 Fixed-income securities 1,369 28 (28 ) 1,369 Total (1) $ 1,861 $ 1,541 $ (30 ) $ 3,372 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 $455 million and $440 million for the periods ended September 30, 2018 and December 31, 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) September 30, 2018 Less than 1 year $ 69 1–5 years 401 5–10 years 386 More than 10 years 513 Total maturities of fixed-income securities $ 1,369 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 319 $ 249 $ 1,121 $ 1,043 Gross realized gains on securities 3 8 51 50 Gross realized losses on securities (5 ) — (14 ) (8 )

CONTINGENCIES AND COMMITMENTS

CONTINGENCIES AND COMMITMENTS	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
CONTINGENCIES AND COMMITMENTS	CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters. Enforcement and Litigation Matters Wildfire-Related Claims Wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the Northern California wildfires and the Butte fire. For the three and nine months ended September 30, 2018 and 2017, the Utility’s Condensed Consolidated Income Statements include estimated losses offset by insurance recoveries as follows: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Butte fire Third-Party Claims $ — $ 350 $ — $ 350 Insurance recoveries — (297 ) (7 ) (350 ) Total Butte fire — 53 (7 ) — Northern California wildfires Third-Party Claims — — 2,500 — Insurance recoveries (10 ) — (385 ) — Total Northern California wildfires (10 ) — 2,115 — Total wildfire-related claims, net of insurance recoveries $ (10 ) $ 53 $ 2,108 $ — In addition to the amounts shown in the table above, during the three and nine months ended September 30, 2018, the Utility incurred $53 million and $120 million , respectively, of legal and other costs related to the Northern California wildfires. See "Butte Fire" below for legal expenses related to the Butte Fire. At September 30, 2018 and December 31, 2017, the Utility's Condensed Consolidated Balance Sheets include estimated losses as follows: Balance At (in millions) September 30, 2018 December 31, 2017 Butte fire $ 294 $ 561 Northern California wildfires 2,500 — Total wildfire-related claims $ 2,794 $ 561 Northern California Wildfires 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. According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities. Cal Fire issued its determination on the causes of 17 of the Northern California wildfires, and alleged that each of these fires 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. Additionally, the Northern California wildfires are under investigation by the CPUC’s SED. During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 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, Honey, 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 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." Also on October 9, 2018, the Office of the District Attorney of Yuba County issued a news release indicating that no criminal charges would be filed in relation 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.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. Cal Fire has not publicly issued any news releases or other determinations for the Tubbs, Maacama, Pressley, and Point wildfires. The timing and outcome of the Cal Fire investigation into the remaining 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. As of October 30, 2018, the Utility had submitted 23 electric incident reports to the CPUC associated with the 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 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, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. 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, courts could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC. There is no guarantee that the CPUC would authorize cost recovery even if a court decision were to determine that the doctrine of inverse condemnation applies. In addition to such 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, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility could be subject to material fines or penalties if the CPUC or any law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations. As of October 30, 2018, PG&E Corporation and the Utility are aware of approximately 500 complaints on behalf of at least 3,100 plaintiffs related to the Northern California wildfires, five of which seek to be certified as class actions. These cases have been coordinated in the San Francisco Superior Court. The coordinated litigation is in the early stages of discovery. The litigation pending against PG&E Corporation and the Utility includes claims under multiple theories of liability, including inverse condemnation and negligence. Plaintiffs also seek punitive damages. PG&E Corporation and the Utility also are the subject of 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 this time against PG&E Corporation or the Utility pertaining to the Cascade fire. 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 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 Northern California wildfires and whether any criminal or civil charges should be brought. Regardless of any determinations of cause by Cal Fire, ultimately PG&E Corporation and the Utility’s liability will be resolved through litigation, 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. PG&E Corporation and the Utility are continuing to review the evidence concerning the causes of the 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 investigation 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. In addition, insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed 36 subrogation complaints in the San Francisco County Superior Court. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. Further, various government entities, including Mendocino, Napa and Sonoma Counties and the City of Santa Rosa, also asserted claims against PG&E Corporation and the Utility based on the damages that these public entities allegedly suffered as a result of the fires. 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. On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 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. PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires. The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved. Estimated Losses from Third-Party Claims Potential liabilities related to the 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, 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. 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 14 of the Northern California wildfires referred to as the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires), and accordingly, PG&E Corporation and the Utility recorded a charge in the amount of $2.5 billion during the quarter ended June 30, 2018. This charge corresponds to the lower end of the range of PG&E Corporation 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 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 Northern California wildfires may change, which could result in material increases to the loss accrued. The $2.5 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. It also does not include any amounts in connection with the Atlas, 37, Tubbs, Cascade, Maacama, Pressley and Point fires because at this time PG&E Corporation and the Utility have not concluded that a loss arising from those fires is probable. However, in the future it is possible that facts could emerge that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in the accrual of a liability at that time, the amount of which could be significant. On September 6, 2018, the California Department of Insurance issued a news release announcing an update on property losses in connection with the October and December 2017 wildfires in California. As of that date, 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 Northern California wildfires. The balance relates to claims from the Southern California December 2017 wildfires. That news release reflected insured property losses only. Also, that amount did not account for uninsured losses, interest, attorneys’ fees, fire suppression and clean-up costs, personal injury and wrongful death damages or other costs. If PG&E Corporation and the Utility were to be found liable for certain or all of such other costs and expenses, including the potential liabilities outlined above, the amount of the liability could significantly exceed the approximately $10 billion in estimated insured property losses with respect to the Northern California wildfires. Loss Recoveries PG&E Corporation and the Utility have liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $840 million , subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. In addition, coverage limits within these wildfire insurance policies could result in further material self-insured costs in the event each fire were deemed to be a separate occurrence under the terms of the insurance policies. PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through September 30, 2018, PG&E Corporation and the Utility recorded $385 million for probable insurance recoveries in connection with the Northern California wildfires. This amount reflects an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future. If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, the potential losses arising out of the Northern California wildfires could significantly exceed the coverage limits of the insurance. The following table presents changes in the insurance receivable for the nine months ended September 30, 2018. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets: Insurance Receivable (in millions) Accrued insurance recoveries $ 385 Reimbursements (13 ) Balance at September 30, 2018 $ 372 In addition, it could take a number of years before the extent of the Utility’s liability is known and the Utility could apply for recovery of costs in excess of insurance. On June 21, 2018, the CPUC issued a decision granting the Utility's request to establish a WEMA for the purpose of tracking specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all, and even if such recovery is possible, it could take a number of years to resolve and a number of years to collect. As of September 30, 2018, the Condensed Consolidated Financial Statements include long-term regulatory assets of $77 million , consisting of insurance premium costs that are probable of recovery. Should PG&E Corporation and the Utility conclude in future periods that recovery of insurance premiums in excess of amounts included in authorized revenue requirements is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of costs related to the Northern California wildfires or any conclusion that such recovery is no longer probable could have a material adverse effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Recently adopted Senate Bill 901 establishes a customer harm threshold, directing the CPUC to limit disallowances in the aggregate, so that they do not exceed the maximum amount that PG&E Corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. It is uncertain how the new legislation will affect the Utility's ability to recover costs related to the Northern California wildfires. PG&E Corporation and the Utility have considered actions that might be taken to attempt to address liquidity needs of the business should the Utility be unable to recover costs related to the Northern California wildfires, but the inability to recover costs in excess of insurance through increases in rates or to collect such rates in a timely manner could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Derivative Litigation Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs' access to discovery in other actions. The parties submitted a joint status report on October 24, 2018. On August 3, 2018, a third purported derivative lawsuit entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation's and the Utility's 2017 proxy statement contained misrepresentations regarding the companies' risk management and safety programs. PG&E Corporation's motion to stay the litigation was filed on October 15, 2018. Plaintiffs' opposition to that motion currently is due November 29, 2018, and defendants' reply brief in support of that motion currently is due December 24, 2018. The hearing on PG&E Corporation's motion to stay currently is set for January 31, 2019. On October 23, 2018, a fourth purported derivative lawsuit entitled City of Warren Police and Fire Retirement System v. Chew, et al. was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings. Securities Class Action Litigation In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al. , respectively. The complaints allege material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints assert claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and seek unspecified monetary relief, interest, attorneys' fees and other costs. Both complaints identify a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In Re PG&E Corporation Securities Litigation . The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. Plaintiffs currently have until November 9, 2018 to file an amended consolidated complaint and defendants currently have until January 8, 2019 to move to dismiss, answer or otherwise respond to that complaint. PG&E Corporation and the Utility are unable to predict the timing and outcome of these proceedings. Clean-up and Repair Costs The Utility incurred costs of $308 million for clean-up and repair of the Utility’s facilities (including $145 million in capital expenditures) through September 30, 2018, in connection with the Northern California wildfires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs. The Utility capitalizes and records as regulatory assets costs that are probable of recovery in rates. At September 30, 2018, the CEMA balance related to the Northern California wildfires was $101 million and reflects an approximately $40 million reduction to the regulatory asset that was recorded in the three months ended June 30, 2018, for costs that are no longer probable of recovery. Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs or any conclusion that such recovery is no longer probable, could have a material adverse effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows. Butte Fire In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. Third-Party Claims On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council previously had authorized the coordination of all cases in Sacramento County. As of October 30, 2018, 95 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately 4,000 individual plaintiffs representing approximately 2,100 households and their insurance companies. These complaints are part of or are in the process of being added to the coordinated proceeding. Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability. Plaintiffs also seek punitive damages. Several plaintiffs have dismissed the Utility's two vegetation management contractors from their complaints. The Utility does not expect the number of individual complaints and plaintiffs to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the Butte fire has expired. The Utility continues to mediate and settle cases. On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny plaintiffs' claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal's decision. Both requests were denied. Neither the trial nor appellate courts addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. Based on the July 2, 2018 Court of Appeal's ruling, the Utility believes a loss related to punitive damages is remote. On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnat

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2017 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2017 Form 10-K. This quarterly report should be read in conjunction with the 2017 Form 10-K.
Use of Estimates and Assumptions	The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other post-retirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.
Variable Interest Entities	Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2018 , the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2018 , it did not consolidate any of them.
Pension and Other Post-Retirement Benefits	Pension and Other Post-Retirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.
Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted	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 Condensed Consolidated Financial Statements as of the adoption date or for the three and nine months ended September 30, 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. Revenue from Contracts with Customers The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns. 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 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’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months . Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income. The following table presents the Utility’s revenues disaggregated by type of customer: (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Electric Revenue from contracts with customers Residential $ 1,649 $ 4,023 Commercial 1,430 3,737 Industrial 448 1,126 Agricultural 523 966 Public street and highway lighting 18 55 Other (1) (273 ) (388 ) Total revenue from contracts with customers - electric 3,795 9,519 Regulatory balancing accounts (2) (328 ) 211 Total electric operating revenue $ 3,467 $ 9,730 Natural gas Revenue from contracts with customers Residential $ 242 $ 1,652 Commercial 87 402 Transportation service only 287 847 Other (1) 30 (149 ) Total revenue from contracts with customers - gas 646 2,752 Regulatory balancing accounts (2) 269 190 Total natural gas operating revenue 915 2,942 Total operating revenues $ 4,382 $ 12,672 (1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers. Presentation of Net Periodic Pension and Post-Retirement Benefit Costs In March 2017, the FASB issued ASU 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 Condensed 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 $13 million and $14 million for PG&E Corporation and the Utility, respectively, for the three months ended September 30, 2017 and $39 million and $41 million for PG&E Corporation and the Utility, respectively, for the nine months ended September 30, 2017 . 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 Condensed 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 Condensed 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 Condensed 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 lease 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 asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility intend to elect 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 expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets and do not expect the guidance will have a material impact on the Condensed Consolidated Statements of Income, Statements of Cash Flows and related disclosures. 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 are calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Derivative Instruments	The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets.
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.
Fair Value of Financial Instruments	In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3
Contingencies and Commitments	PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Components of Net Periodic Benefit Cost	The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned (1) $ 128 $ 118 $ 16 $ 14 Interest cost 171 178 17 20 Expected return on plan assets (255 ) (193 ) (33 ) (24 ) Amortization of prior service cost (1 ) (1 ) 4 4 Amortization of net actuarial loss 1 6 (1 ) 1 Net periodic benefit cost 44 108 3 15 Regulatory account transfer (2) 41 (23 ) — — Total $ 85 $ 85 $ 3 $ 15 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Service cost for benefits earned (1) $ 385 $ 354 $ 49 $ 44 Interest cost 515 535 52 58 Expected return on plan assets (766 ) (578 ) (98 ) (73 ) Amortization of prior service cost (4 ) (5 ) 11 12 Amortization of net actuarial loss 4 17 (4 ) 3 Net periodic benefit cost 134 323 10 44 Regulatory account transfer (2) 118 (69 ) — — Total $ 252 $ 254 $ 10 $ 44 (1) A portion of service costs are capitalized pursuant to ASU 2017-07. (2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates
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) are summarized below: Pension Other Total (in millions, net of income tax) Three Months Ended September 30, 2018 Beginning balance $ (30 ) $ 17 $ (13 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) (1 ) 3 2 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1) 1 (1 ) — Regulatory account transfer (net of taxes of $0 and $1, respectively) (1) 1 (2 ) (1 ) Net current period other comprehensive gain (loss) 1 — 1 Ending balance $ (29 ) $ 17 $ (12 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ (25 ) $ 17 $ (8 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) (1 ) 2 1 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $2 and $2, respectively) (3 ) (3 ) (6 ) Net current period other comprehensive gain (loss) — — — Ending balance $ (25 ) $ 17 $ (8 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $1 and $3, respectively) (1) (3 ) 8 5 Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1) 3 (3 ) — Regulatory account transfer (net of taxes of $0 and $2, respectively) (1) 1 (5 ) (4 ) Reclassification of stranded income tax to retained earnings (5 ) — (5 ) Net current period other comprehensive gain (loss) $ (4 ) $ — $ (4 ) Ending balance (29 ) 17 (12 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) (3 ) 7 4 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 10 2 12 Regulatory account transfer (net of taxes of $5 and $6, respectively) (7 ) (8 ) (15 ) Net current period other comprehensive gain (loss) $ — $ 1 $ 1 Ending balance (25 ) 17 (8 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)
Summary of Revenues Disaggregated by Type of Customer	The following table presents the Utility’s revenues disaggregated by type of customer: (in millions) Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Electric Revenue from contracts with customers Residential $ 1,649 $ 4,023 Commercial 1,430 3,737 Industrial 448 1,126 Agricultural 523 966 Public street and highway lighting 18 55 Other (1) (273 ) (388 ) Total revenue from contracts with customers - electric 3,795 9,519 Regulatory balancing accounts (2) (328 ) 211 Total electric operating revenue $ 3,467 $ 9,730 Natural gas Revenue from contracts with customers Residential $ 242 $ 1,652 Commercial 87 402 Transportation service only 287 847 Other (1) 30 (149 ) Total revenue from contracts with customers - gas 646 2,752 Regulatory balancing accounts (2) 269 190 Total natural gas operating revenue 915 2,942 Total operating revenues $ 4,382 $ 12,672 (1) This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items. (2) These amounts represent revenues authorized to be billed or refunded to customers.

REGULATORY ASSETS, LIABILITIE_2

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2018 December 31, 2017 Pension benefits $ 1,837 $ 1,954 Environmental compliance costs 851 837 Utility retained generation 285 319 Price risk management 67 65 Unamortized loss, net of gain, on reacquired debt 80 79 Catastrophic event memorandum account (1) 760 274 Wildfire expense memorandum account (2) 77 — Fire hazard prevention memorandum account (3) 65 1 Other 407 264 Total long-term regulatory assets $ 4,429 $ 3,793 (1) Represents costs related to certain catastrophic events that the Utility believes are probable of recovery. For more information, see Note 9 below. (2) Represents costs related to insurance premiums that the Utility believes are probable of recovery. For more information, see Note 9 below. (3) Represents costs related to wildfire prevention vegetation management work that the Utility believes are probable of recovery.
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2018 December 31, 2017 Cost of removal obligations $ 5,888 $ 5,547 Deferred income taxes 437 1,021 Recoveries in excess of AROs 489 624 Public purpose programs 660 590 Other 1,133 897 Total long-term regulatory liabilities $ 8,607 $ 8,679
Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2018 December 31, 2017 Electric distribution $ 31 $ — Electric transmission 109 139 Gas distribution and transmission 624 486 Energy procurement 131 71 Public purpose programs 120 103 Other 311 423 Total regulatory balancing accounts receivable $ 1,326 $ 1,222
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) September 30, 2018 December 31, 2017 Electric distribution $ — $ 72 Electric transmission 132 120 Utility generation 70 14 Gas distribution and transmission 9 — Energy procurement 69 149 Public purpose programs 588 452 Other 362 313 Total regulatory balancing accounts payable $ 1,230 $ 1,120

DEBT (Tables)

DEBT (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of Debt	The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2018 : (in millions) Termination Date Facility Limit Letters of Credit Outstanding Borrowings Facility Availability PG&E Corporation April 2022 $ 300 (1) $ — $ — $ 300 Utility April 2022 3,000 (2) 87 — 2,913 Total revolving credit facilities $ 3,300 $ 87 $ — $ 3,213 (1) Includes a $50 million lender commitment to the letter of credit sublimit 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 sublimit and a $75 million commitment for swingline loans.

EQUITY (Tables)

EQUITY (Tables)	9 Months Ended
	Sep. 30, 2018
Stockholders' Equity Note [Abstract]
Changes in Equity	PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2018 were as follows: PG&E Corporation Utility (in millions) Total Equity Total Shareholders' Equity Balance at December 31, 2017 $ 19,472 $ 19,747 Comprehensive income 33 48 Common stock issued 137 — Share-based compensation 64 — Preferred stock dividend requirement — (10 ) Preferred stock dividend requirement of subsidiary (10 ) — Balance at September 30, 2018 $ 19,696 $ 19,785

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Common Shares Outstanding for Calculating Diluted	The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2018 2017 2018 2017 Income available for common shareholders $ 564 $ 550 $ 22 $ 1,532 Weighted average common shares outstanding, basic 517 513 516 511 Add incremental shares from assumed conversions: Employee share-based compensation — 3 1 3 Weighted average common shares outstanding, diluted 517 516 517 514 Total earnings per common share, diluted $ 1.09 $ 1.07 $ 0.04 $ 2.98

DERIVATIVES (Tables)

DERIVATIVES (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Volumes Of Outstanding Derivative Contracts	The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments September 30, December 31, Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 250,021,802 228,768,745 Options 29,534,224 60,736,806 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,939,691 2,872,013 Congestion Revenue Rights (3) 316,451,690 312,272,177 (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.
Schedule of Offsetting Assets	At September 30, 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 $ 34 $ (2 ) $ 5 $ 37 Other noncurrent assets – other 88 — — 88 Current liabilities – other (39 ) 2 12 (25 ) Noncurrent liabilities – other (67 ) — 4 (63 ) Total commodity risk $ 16 $ — $ 21 $ 37 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
Schedule of Offsetting Liabilities	At September 30, 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 $ 34 $ (2 ) $ 5 $ 37 Other noncurrent assets – other 88 — — 88 Current liabilities – other (39 ) 2 12 (25 ) Noncurrent liabilities – other (67 ) — 4 (63 ) Total commodity risk $ 16 $ — $ 21 $ 37 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)	9 Months Ended
	Sep. 30, 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 September 30, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 377 — — — $ 377 Nuclear decommissioning trusts Short-term investments 14 — — — 14 Global equity securities 1,970 — — — 1,970 Fixed-income securities 738 631 — — 1,369 Assets measured at NAV — — — — 19 Total nuclear decommissioning trusts (2) 2,722 631 — — 3,372 Price risk management instruments (Note 7) Electricity 1 5 110 2 118 Gas — 6 — 1 7 Total price risk management instruments 1 11 110 3 125 Rabbi trusts Fixed-income securities — 75 — — 75 Life insurance contracts — 68 — — 68 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 8 — — — 8 Assets measured at NAV — — — — 112 Total long-term disability trust 8 — — — 120 TOTAL ASSETS $ 3,108 $ 785 $ 110 $ 3 $ 4,137 Liabilities: Price risk management instruments (Note 7) Electricity $ 5 $ 12 $ 86 $ (17 ) $ 86 Gas — 3 — (1 ) 2 TOTAL LIABILITIES $ 5 $ 15 $ 86 $ (18 ) $ 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 $455 million , primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements 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 7) 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 7) 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.
Level 3 Measurements and Sensitivity Analysis	Fair Value at (in millions) September 30, 2018 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 110 $ 44 Market approach CRR auction prices $ (18.61) - 32.26 Power purchase agreements $ — $ 42 Discounted cash flow Forward prices $ 19.81 - 38.80 (1) Represents price per megawatt-hour. Fair Value at (in millions) December 31, 2017 Fair Value Measurement Assets Liabilities Valuation Technique Unobservable Input 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 tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2018 and 2017 : Price Risk Management Instruments (in millions) 2018 2017 Asset (liability) balance as of July 1 $ 34 $ 48 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (10 ) — Asset (liability) balance as of September 30 $ 24 $ 48 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Price Risk Management Instruments (in millions) 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) (18 ) (7 ) Asset (liability) balance as of September 30 $ 24 $ 48 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Carrying Amount and Fair Value of Financial Instruments	The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2018 At December 31, 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation (1) $ 350 $ 350 $ 350 $ 350 Utility 17,491 16,413 17,090 19,128 (1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Note. 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) As of September 30, 2018 Amortized Total Total Total Fair Nuclear decommissioning trusts Short-term investments $ 14 $ — $ — $ 14 Global equity securities 478 1,513 (2 ) 1,989 Fixed-income securities 1,369 28 (28 ) 1,369 Total (1) $ 1,861 $ 1,541 $ (30 ) $ 3,372 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 $455 million and $440 million for the periods ended September 30, 2018 and December 31, 2017 , respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule of Maturities on Debt Instruments	The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) September 30, 2018 Less than 1 year $ 69 1–5 years 401 5–10 years 386 More than 10 years 513 Total maturities of fixed-income securities $ 1,369
Schedule of Activity for Debt and Equity Securities	The following table provides a summary of activity for fixed income and equity securities: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 319 $ 249 $ 1,121 $ 1,043 Gross realized gains on securities 3 8 51 50 Gross realized losses on securities (5 ) — (14 ) (8 )

CONTINGENCIES AND COMMITMENTS (

CONTINGENCIES AND COMMITMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Summary of Wildfire-Related Claims	For the three and nine months ended September 30, 2018 and 2017, the Utility’s Condensed Consolidated Income Statements include estimated losses offset by insurance recoveries as follows: Three Months Ended September 30, Nine Months Ended September 30, (in millions) 2018 2017 2018 2017 Butte fire Third-Party Claims $ — $ 350 $ — $ 350 Insurance recoveries — (297 ) (7 ) (350 ) Total Butte fire — 53 (7 ) — Northern California wildfires Third-Party Claims — — 2,500 — Insurance recoveries (10 ) — (385 ) — Total Northern California wildfires (10 ) — 2,115 — Total wildfire-related claims, net of insurance recoveries $ (10 ) $ 53 $ 2,108 $ — In addition to the amounts shown in the table above, during the three and nine months ended September 30, 2018, the Utility incurred $53 million and $120 million , respectively, of legal and other costs related to the Northern California wildfires. See "Butte Fire" below for legal expenses related to the Butte Fire. At September 30, 2018 and December 31, 2017, the Utility's Condensed Consolidated Balance Sheets include estimated losses as follows: Balance At (in millions) September 30, 2018 December 31, 2017 Butte fire $ 294 $ 561 Northern California wildfires 2,500 — Total wildfire-related claims $ 2,794 $ 561
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 Condensed 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) (267 ) Balance at September 30, 2018 $ 294 (1) As of September 30, 2018 , the Utility has paid $806 million of the $832 million in settlements to date in connection with the Butte fire.
Changes in Insurance Receivable	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 Condensed 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 (436 ) Balance at September 30, 2018 $ 160 The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets: Insurance Receivable (in millions) Accrued insurance recoveries $ 385 Reimbursements (13 ) Balance at September 30, 2018 $ 372
Schedule of Environmental Remediation Liability	The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following: Balance at September 30, December 31, (in millions) 2018 2017 Topock natural gas compressor station $ 362 $ 334 Hinkley natural gas compressor station 151 147 Former manufactured gas plant sites owned by the Utility or third parties (1) 375 320 Utility-owned generation facilities (other than fossil fuel-fired), (2) 116 115 Fossil fuel-fired generation facilities and sites (3) 136 123 Total environmental remediation liability $ 1,140 $ 1,039 (1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach. (2) Primarily driven by the Geothermal landfill and Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant.

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details) a in Thousands	9 Months Ended
	Sep. 30, 2018segmentwildfire	Oct. 30, 2017awildfirefatalitystructure
Organization And Basis Of Presentation [Line Items]
Number of operating segments (segment) | segment	1
Nothern California Wild Fire
Organization And Basis Of Presentation [Line Items]
Number wildfires (wildfire) | wildfire	17	21
Number of acres burned (acre) | a		245
Number of structures destroyed (structure) | structure		8,900
Number of fatalities (fatality) | fatality		44

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 128	$ 118	$ 385	$ 354
Interest cost	171	178	515	535
Expected return on plan assets	(255)	(193)	(766)	(578)
Amortization of prior service cost	(1)	(1)	(4)	(5)
Amortization of net actuarial loss	1	6	4	17
Net periodic benefit cost	44	108	134	323
Regulatory account transfer	41	(23)	118	(69)
Total	85	85	252	254
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	16	14	49	44
Interest cost	17	20	52	58
Expected return on plan assets	(33)	(24)	(98)	(73)
Amortization of prior service cost	4	4	11	12
Amortization of net actuarial loss	(1)	1	(4)	3
Net periodic benefit cost	3	15	10	44
Regulatory account transfer	0	0	0	0
Total	$ 3	$ 15	$ 10	$ 44

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance			$ 19,472
Ending balance	$ 19,696		19,696
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(13)	$ (8)	(8)	$ (9)
Net current period other comprehensive gain (loss)	1	0	(4)	1
Ending balance	(12)	(8)	(12)	(8)
AOCI Attributable to Parent | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(30)	(25)	(25)	(25)
Net current period other comprehensive gain (loss)	1	0	(4)	0
Ending balance	(29)	(25)	(29)	(25)
AOCI Attributable to Parent | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	17	17	16
Net current period other comprehensive gain (loss)	0	0	0	1
Ending balance	17	17	17	17
Amortization of prior service benefit (cost)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	1	5	4
Amortization of prior service benefit (cost) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(1)	(3)	(3)
Amount attributable to tax	0	0	1	2
Amortization of prior service benefit (cost) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	3	2	8	7
Amount attributable to tax	1	2	3	5
Amortization of net actuarial gain (loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	5	0	12
Amortization of net actuarial gain (loss) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	4	3	10
Amount attributable to tax	0	2	1	7
Amortization of net actuarial gain (loss) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	1	(3)	2
Amount attributable to tax	0	0	1	1
Regulatory account transfer
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(6)	(4)	(15)
Regulatory account transfer | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	(3)	1	(7)
Amount attributable to tax	0	2	0	5
Regulatory account transfer | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(3)	(5)	(8)
Amount attributable to tax	$ 1	$ 2	2	$ 6
Reclassification of stranded income tax to retained earnings
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income			(5)
Reclassification of stranded income tax to retained earnings | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income			(5)
Reclassification of stranded income tax to retained earnings | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income			$ 0

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Period for probable revenue recovery			24 months
Increase in operating and maintenance expense	$ 1,611	$ 1,324	$ 5,001	$ 4,453
Increase in other income	$ 104	38	$ 318	98
Accounting Standards Update 2017-07
Public Utility, Property, Plant and Equipment [Line Items]
Increase in operating and maintenance expense		13		39
Increase in other income		$ 14		$ 41

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue from contracts with customers
Total operating revenues	$ 4,381	$ 4,517	$ 12,671	$ 13,035
Electric
Revenue from contracts with customers
Total operating revenues	3,466	3,648	9,729	10,036
Natural gas
Revenue from contracts with customers
Total operating revenues	915	869	2,942	2,999
Pacific Gas & Electric Co
Revenue from contracts with customers
Total operating revenues	4,382	4,516	12,672	13,037
Pacific Gas & Electric Co | Electric
Revenue from contracts with customers
Total revenue from contracts with customers	3,795		9,519
Regulatory balancing accounts	(328)		211
Total operating revenues	3,467	3,647	9,730	10,038
Pacific Gas & Electric Co | Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,649		4,023
Pacific Gas & Electric Co | Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,430		3,737
Pacific Gas & Electric Co | Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	448		1,126
Pacific Gas & Electric Co | Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	523		966
Pacific Gas & Electric Co | Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	18		55
Pacific Gas & Electric Co | Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	(273)		(388)
Pacific Gas & Electric Co | Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	646		2,752
Regulatory balancing accounts	269		190
Total operating revenues	915	$ 869	2,942	$ 2,999
Pacific Gas & Electric Co | Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	242		1,652
Pacific Gas & Electric Co | Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	87		402
Pacific Gas & Electric Co | Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	287		847
Pacific Gas & Electric Co | Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ 30		$ (149)

REGULATORY ASSETS, LIABILITIE_3

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 4,429	$ 3,793
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,837	1,954
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	851	837
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	285	319
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	67	65
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	80	79
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	760	274
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	77	0
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	65	1
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 407	$ 264

REGULATORY ASSETS, LIABILITIE_4

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 8,607	$ 8,679
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	5,888	5,547
Deferred income taxes
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	437	1,021
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	489	624
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	660	590
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,133	$ 897

REGULATORY ASSETS, LIABILITIE_5

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,326	$ 1,222
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	31	0
Total regulatory balancing accounts receivable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	109	139
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	624	486
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	131	71
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	120	103
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	311	423
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1,230	1,120
Total regulatory balancing accounts payable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	72
Total regulatory balancing accounts payable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	132	120
Total regulatory balancing accounts payable | Utility generation
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	70	14
Total regulatory balancing accounts payable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	9	0
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	69	149
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	588	452
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 362	$ 313

DEBT (Schedule of Line of Credi

DEBT (Schedule of Line of Credit) (Details)	9 Months Ended
	Sep. 30, 2018USD ($)
Debt [Line Items]
Letters of credit sublimit	$ 50,000,000
Swingline loans sublimit	$ 100,000,000
Swingline loan repay term	7 days
Utility
Debt [Line Items]
Letters of credit sublimit	$ 500,000,000
Swingline loans sublimit	75,000,000
Revolving Credit Facility
Debt [Line Items]
Facility Limit	300,000,000
Letters of Credit Outstanding	0
Borrowings	0
Facility Availability	300,000,000
Revolving Credit Facility | Credit Facilities
Debt [Line Items]
Facility Limit	3,300,000,000
Letters of Credit Outstanding	87,000,000
Borrowings	0
Facility Availability	3,213,000,000
Revolving Credit Facility | Utility
Debt [Line Items]
Facility Limit	3,000,000,000
Letters of Credit Outstanding	87,000,000
Borrowings	0
Facility Availability	$ 2,913,000,000

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($)	Apr. 26, 2018	Dec. 31, 2018	Sep. 30, 2018	Aug. 31, 2018	Apr. 30, 2018	Mar. 31, 2018	Feb. 28, 2018	Feb. 28, 2017
Senior Notes Two Point Four Zero Percent Due 2019
Debt [Line Items]
Senior notes			$ 350,000,000
Debt instrument, interest rate	2.40%		2.40%
Redemption of debt	$ 350,000,000
Floating Rate Unsecured Term Loan, Due 2020 | Unsecured Debt
Debt [Line Items]
Debt instrument, face amount					$ 350,000,000
Senior Notes Due 2018 | Senior Notes | Forecast
Debt [Line Items]
Redemption of debt		$ 500,000,000
Senior Notes Due 2019 | Senior Notes | Forecast
Debt [Line Items]
Redemption of debt		$ 250,000,000
Pacific Gas & Electric Co
Debt [Line Items]
Floating rate unsecured term loan, matured 2018								$ 250,000,000
Pacific Gas & Electric Co | Pollution Control Bonds Series 1996 C, E, F, And 1997 B
Debt [Line Items]
Debt instrument, face amount			$ 613,550,000
Pacific Gas & Electric Co | Pollution Control Bonds Series 1996 C, E, F, And 1997 B | Minimum
Debt [Line Items]
Debt instrument, interest rate			1.55%
Pacific Gas & Electric Co | Pollution Control Bonds Series 1996 C, E, F, And 1997 B | Maximum
Debt [Line Items]
Debt instrument, interest rate			1.68%
Pacific Gas & Electric Co | Pollution Control Bonds Series 2009 A-B
Debt [Line Items]
Debt instrument, face amount			$ 148,550,000
Pacific Gas & Electric Co | Pollution Control Bonds Series 2009 A-B | Maximum
Debt [Line Items]
Debt instrument, interest rate			1.60%
Pacific Gas & Electric Co | Senior Notes Eight Point Two Five Percent Due 2018
Debt [Line Items]
Senior notes						$ 400,000,000
Debt instrument, interest rate						8.25%
Pacific Gas & Electric Co | Senior Notes Due 2023 | Senior Notes
Debt [Line Items]
Debt instrument, face amount				$ 500,000,000
Debt instrument, interest rate				4.25%
Pacific Gas & Electric Co | Senior Notes Due 2028 | Senior Notes
Debt [Line Items]
Debt instrument, face amount				$ 300,000,000
Debt instrument, interest rate				4.65%
Pacific Gas & Electric Co | Unsecured Debt | Floating Rate Unsecured Term Loan, Due 2019
Debt [Line Items]
Debt instrument, face amount							$ 250,000,000

EQUITY (Changes in Equity) (Det

EQUITY (Changes in Equity) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance			$ 19,472
Comprehensive income	$ 568	$ 553	33	$ 1,543
Common stock issued			137
Share-based compensation			64
Preferred stock dividend requirement			0
Preferred stock dividend requirement of subsidiary	(3)	(3)	(10)	(10)
Ending balance	19,696		19,696
Pacific Gas & Electric Co
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance			19,747
Comprehensive income	571	513	48	1,492
Common stock issued			0
Share-based compensation			0
Preferred stock dividend requirement	(3)	$ (3)	(10)	$ (10)
Preferred stock dividend requirement of subsidiary			0
Ending balance	$ 19,785		$ 19,785

EQUITY (Narrative) (Details)

EQUITY (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Schedule Of Changes In Equity [Line Items]
Common stock dividends declared (in dollars per share)	$ 0	$ 0.53	$ 0	$ 1.55
Equity Contract
Schedule Of Changes In Equity [Line Items]
Remaining equity distribution agreement amount	$ 246.3		$ 246.3
401K Plan, DRSPP, and Shared Based Compensation Plans
Schedule Of Changes In Equity [Line Items]
Stock issued during period for stock options exercised and under 401(K) plan and DRSPP (in shares)			3.6
Proceeds from stock issuance			$ 136.7

EARNINGS PER SHARE (Reconciliat

EARNINGS PER SHARE (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Income available for common shareholders	$ 564	$ 550	$ 22	$ 1,532
Weighted average common shares outstanding, basic (in shares)	517	513	516	511
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	0	3	1	3
Weighted average common shares outstanding, diluted (in shares)	517	516	517	514
Total earnings per common share, diluted (in dollars per share)	$ 1.09	$ 1.07	$ 0.04	$ 2.98

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Sep. 30, 2018MWhMMBTU	Dec. 31, 2017MWhMMBTU
Forwards, Futures and Swaps | Natural gas
Derivative [Line Items]
Contract Volume | MMBTU	250,021,802	228,768,745
Forwards, Futures and Swaps | Electric
Derivative [Line Items]
Contract Volume | MWh	3,939,691	2,872,013
Options | Natural gas
Derivative [Line Items]
Contract Volume | MMBTU	29,534,224	60,736,806
Congestion Revenue Rights | Electric
Derivative [Line Items]
Contract Volume | MWh	316,451,690	312,272,177

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ 16	$ 20
Derivative Asset, Netting	0	0
Cash Collateral	21	31
Total Derivative Balance, Assets	37	51
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	34	30
Derivative Asset, Netting	(2)	(3)
Cash Collateral	5	10
Total Derivative Balance, Assets	37	37
Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	88	103
Derivative Asset, Netting	0	(1)
Cash Collateral	0	0
Total Derivative Balance, Assets	88	102
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(39)	(47)
Derivative Liability, Netting	2	3
Cash Collateral	12	13
Total Derivative Balance, Liabilities	(25)	(31)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(67)	(66)
Derivative Liability, Netting	0	1
Cash Collateral	4	8
Total Derivative Balance, Liabilities	$ (63)	$ (57)

DERIVATIVES (Narrative) (Detail

DERIVATIVES (Narrative) (Details) - Utility - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative [Line Items]
Derivative liabilities offset by asset position	$ 44	$ 1
Net position of derivative contracts/additional collateral posting requirements	$ 12

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets:
Short-term investments	$ 377	$ 385
Price risk management instruments, netting	3	6
Derivative Asset	125	139
TOTAL ASSETS	4,137	4,145
Liabilities:
Price risk management instruments, netting	(18)	(25)
TOTAL LIABILITIES	88	88
Amount primarily related to deferred taxes on appreciation of investment value	455	440
Nuclear decommissioning trusts
Assets:
Short-term investments	14	23
Global equity securities	1,970	1,967
Fixed-income securities	1,369	1,295
TOTAL ASSETS	3,372	3,303
Rabbi trusts
Assets:
Fixed-income securities	75	72
Life insurance contracts	68	71
TOTAL ASSETS	143	143
Long-term disability trust
Assets:
Short-term investments	8	8
TOTAL ASSETS	120	175
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	2	6
Derivative Asset	118	138
Liabilities:
Price risk management instruments, netting	(17)	(25)
Derivative Liability	86	87
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	1	0
Derivative Asset	7	1
Liabilities:
Price risk management instruments, netting	(1)	0
Derivative Liability	2	1
Level 1
Assets:
Short-term investments	377	385
Price risk management instruments, gross subject to netting	1	0
TOTAL ASSETS	3,108	3,116
Liabilities:
TOTAL LIABILITIES	5	10
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	14	23
Global equity securities	1,970	1,967
Fixed-income securities	738	733
TOTAL ASSETS	2,722	2,723
Level 1 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 1 | Long-term disability trust
Assets:
Short-term investments	8	8
TOTAL ASSETS	8	8
Level 1 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	1	0
Liabilities:
Price risk management instruments, gross subject to netting	5	10
Level 1 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 2
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	11	4
TOTAL ASSETS	785	709
Liabilities:
TOTAL LIABILITIES	15	16
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	631	562
TOTAL ASSETS	631	562
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	75	72
Life insurance contracts	68	71
TOTAL ASSETS	143	143
Level 2 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 2 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	5	3
Liabilities:
Price risk management instruments, gross subject to netting	12	15
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	6	1
Liabilities:
Price risk management instruments, gross subject to netting	3	1
Level 3
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	110	129
TOTAL ASSETS	110	129
Liabilities:
TOTAL LIABILITIES	86	87
Level 3 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	0	0
TOTAL ASSETS	0	0
Level 3 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 3 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 3 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	110	129
Liabilities:
Price risk management instruments, gross subject to netting	86	87
Level 3 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Fair Value Measured at Net Asset Value | Nuclear decommissioning trusts
Assets:
Assets measured at NAV	19	18
Fair Value Measured at Net Asset Value | Long-term disability trust
Assets:
Assets measured at NAV	$ 112	$ 167

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)$ / MWh	Dec. 31, 2017USD ($)$ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 4,137	$ 4,145
Liabilities, Fair Value	88	88
Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	110	129
Liabilities, Fair Value	$ 44	$ 24
Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	(18.61)	(16.03)
Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	32.26	11.99
Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 0	$ 0
Liabilities, Fair Value	$ 42	$ 63
Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	19.81	18.81
Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / 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	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset (liability) balance	$ 34	$ 48	$ 42	$ 55
Included in regulatory assets and liabilities or balancing accounts	(10)	0	(18)	(7)
Ending asset (liability) balance	$ 24	$ 48	$ 24	$ 48

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($)	Apr. 26, 2018	Sep. 30, 2018	Apr. 30, 2018	Dec. 31, 2017
Senior Notes Two Point Four Zero Percent Due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Redemption of debt	$ 350,000,000
Debt instrument, interest rate	2.40%	2.40%
Unsecured Debt | Floating Rate Unsecured Term Loan, Due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, face amount			$ 350,000,000
Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		$ 350,000,000		$ 350,000,000
Pacific Gas & Electric Co | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		16,413,000,000		19,128,000,000
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		350,000,000		350,000,000
Carrying Amount | Pacific Gas & Electric Co
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		$ 17,491,000,000		$ 17,090,000,000

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 1,861	$ 1,799
Total Unrealized Gains	1,541	1,514
Total Unrealized Losses	(30)	(10)
Total Fair Value	3,372	3,303
Amount primarily related to deferred taxes on appreciation of investment value	455	440
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	14	23
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	14	23
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	478	524
Total Unrealized Gains	1,513	1,463
Total Unrealized Losses	(2)	(2)
Total Fair Value	1,989	1,985
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,369	1,252
Total Unrealized Gains	28	51
Total Unrealized Losses	(28)	(8)
Total Fair Value	$ 1,369	$ 1,295

FAIR VALUE MEASUREMENTS (Sche_2

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 3,372	$ 3,303
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	69
1–5 years	401
5–10 years	386
More than 10 years	513
Total maturities of fixed-income securities	$ 1,369	$ 1,295

FAIR VALUE MEASUREMENTS (Sche_3

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 319	$ 249	$ 1,121	$ 1,043
Gross realized gains on securities	3	8	51	50
Gross realized losses on securities	$ (5)	$ 0	$ (14)	$ (8)

CONTINGENCIES AND COMMITMENTS_2

CONTINGENCIES AND COMMITMENTS (Summary of Estimated Losses Related to Wildfire-Related Claims) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Loss Contingencies [Line Items]
Total wildfire-related claims, net of insurance recoveries	$ (10)		$ 53	$ 2,108	$ 0
Nothern California Wild Fire
Loss Contingencies [Line Items]
Third-Party Claims		$ 2,500
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Total wildfire-related claims, net of insurance recoveries	(10)		53	2,108	0
Pacific Gas & Electric Co | Butte Fire
Loss Contingencies [Line Items]
Third-Party Claims	0		350	0	350
Insurance recoveries	0		(297)	(7)	(350)
Total wildfire-related claims, net of insurance recoveries	0		53	(7)	0
Pacific Gas & Electric Co | Nothern California Wild Fire
Loss Contingencies [Line Items]
Third-Party Claims	0		0	2,500	0
Insurance recoveries	(10)		0	(385)	0
Total wildfire-related claims, net of insurance recoveries	$ (10)		$ 0	$ 2,115	$ 0

CONTINGENCIES AND COMMITMENTS_3

CONTINGENCIES AND COMMITMENTS (Wildfire-Related Claims Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018
Pacific Gas & Electric Co | Nothern California Wild Fire
Loss Contingencies [Line Items]
Legal and other costs	$ 53	$ 120

CONTINGENCIES AND COMMITMENTS_4

CONTINGENCIES AND COMMITMENTS (Summary of Wildfire-Related Claims Reported on Consolidated Balance Sheets) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Butte Fire And Northern California Wildfires
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 2,794	$ 561
Butte Fire
Loss Contingencies [Line Items]
Total wildfire-related claims	294	561
Nothern California Wild Fire
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 2,500	$ 0

CONTINGENCIES AND COMMITMENTS_5

CONTINGENCIES AND COMMITMENTS (Northern California Wildfires) (Details) insurance_claim in Thousands, a in Thousands, $ in Thousands	Oct. 30, 2018USD ($)lawsuitcomplaintplaintiffincident_report	Sep. 06, 2018USD ($)insurance_claim	Oct. 31, 2018USD ($)	Sep. 30, 2018USD ($)wildfire	Jun. 30, 2018USD ($)wildfirelawsuit	Sep. 30, 2018USD ($)wildfire	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Nov. 20, 2017lawsuit	Oct. 30, 2017awildfirefatalitystructure
Loss Contingencies [Line Items]
Regulatory assets				$ 4,429,000		$ 4,429,000		$ 3,793,000
Capital expenditures						348,000	$ 301,000
Regulatory assets, current				229,000		229,000		615,000
Wildfire expense memorandum account
Loss Contingencies [Line Items]
Regulatory assets				77,000		77,000		0
Catastrophic Event Memorandum Account
Loss Contingencies [Line Items]
Regulatory assets				$ 760,000		$ 760,000		$ 274,000
Securities Class Actions Filed in United States District Court for the Northern District of California
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit					2
Nothern California Wild Fire
Loss Contingencies [Line Items]
Number wildfires (wildfire) | wildfire				17		17				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) | wildfire				17	16	17
Number of fires cause by trees contact with power lines (wildfire) | wildfire					4
Number of fires caused by electric power and distribution lines, conductors and the failure of power poles (wildfire) | wildfire					12
Number of fires with probable losses (wildfire) | wildfire				14		14
Loss from claims related to wildfire					$ 2,500,000
Nothern California Wild Fire | Catastrophic Event Memorandum Account
Loss Contingencies [Line Items]
Regulatory assets, current				$ 101,000		$ 101,000
Decrease current regulatory assets				40,000
Breach of Fiduciary Duties | Derivative Lawsuits Filed in the San Francisco County Superior Court
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit									2
Nothern California Wild Fire
Loss Contingencies [Line Items]
Insurance claims received by insurers (insurance claim) | insurance_claim		55
Total insurance claims received by insurers		$ 12,280,000
Statewide insurance claims related to wildfire		$ 10,000,000
Liability insurance coverage				840,000		840,000
Initial self-insured retention per occurrence				10,000		10,000
Further retention per occurrence				$ 40,000		40,000
Probable insurance recoveries						385,000
Service restoration and repair costs						308,000
Capital expenditures						$ 145,000
Subsequent Event | Loss from Catastrophes | Complaints Against PG&E Corporation and the Utility in San Francisco Counties Superior Courts
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | complaint	500
Number of plaintiffs in lawsuit (plaintiff) | plaintiff	3,100
Subsequent Event | Loss from Catastrophes | Lawsuits Against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts, Classified As Class Actions
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit	5
Subsequent Event | Loss from Catastrophes | Complaints Brought By Butte County District Attorney [Member]
Loss Contingencies [Line Items]
Settlement expense			$ 1,500
Settlement agreement term			4 years
Subsequent Event | Loss from Catastrophes | Subrogation Complaints Against PG&E Corporation and the Utility in San Francisco County Superior Courts
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | complaint	36
Subsequent Event | Nothern California Wild Fire
Loss Contingencies [Line Items]
Number of electric incident reports submitted (incident report) | incident_report	23
Property damage coverage per incident	$ 50

CONTINGENCIES AND COMMITMENTS_6

CONTINGENCIES AND COMMITMENTS (Summary of Insurance Receivables Related to California Wildfires) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Loss Contingencies [Line Items]
Reimbursements	$ (64)	$ 166
Nothern California Wild Fire
Loss Contingencies [Line Items]
Accrued insurance recoveries	385
Reimbursements	13
Insurance receivable	$ 372

CONTINGENCIES AND COMMITMENTS_7

CONTINGENCIES AND COMMITMENTS (Butte Fire) (Details) $ in Millions

Oct. 30, 2018contractorhouseholdcomplaintplaintiff

Sep. 06, 2018plaintiff

Mar. 02, 2018USD ($)

Mar. 01, 2018USD ($)

Apr. 25, 2017USD ($)citation

Apr. 13, 2017USD ($)

Oct. 31, 2018USD ($)

May 31, 2017USD ($)

Sep. 30, 2018USD ($)plaintiff

Sep. 30, 2018USD ($)

Sep. 30, 2018USD ($)

May 23, 2016contractor

Apr. 28, 2016afatalitystructureoutbuildinghomecomercial_property

Butte Fire

Loss Contingencies [Line Items]

Number of acres burned (acre) | a

70,868

Number of fatalities caused by fire (fatality) | fatality

2

Number of homes destroyed by fire (home) | home

549

Number of outbuildings damaged by fire (outbuilding) | outbuilding

368

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

4

Number of structures damaged (structure) | structure

44

Number of vegetation management contractors (contractor) | contractor

2

Number of 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

Estimate of additional possible losses

$ 200

$ 200

$ 200

Cumulative legal expenses incurred

118

Legal expenses incurred

9

31

Coverage for third party liability

922

Probable insurance recoveries

922

Reimbursements from insurance policies

60

Reimbursements from insurance policies

7

Number of citations (citation) | citation

2

Value of citations issued

$ 8.3

Butte Fire | Minimum

Loss Contingencies [Line Items]

Probable loss to be incurred

1,100

1,100

1,100

Butte Fire | Maximum

Loss Contingencies [Line Items]

Probable loss to be incurred

$ 1,300

$ 1,300

$ 1,300

Butte Fire | Agreement Reached In Litigation To Stipulate To Judgment On Inverse Condemnation Grounds [Member]

Loss Contingencies [Line Items]

Number of plaintiffs in lawsuit (plaintiff) | plaintiff

2

Butte Fire | County of Calaveras

Loss Contingencies [Line Items]

Value of claims brought against company

$ 167

$ 85

Subsequent Event

Loss Contingencies [Line Items]

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

2

Subsequent Event | Butte Fire

Loss Contingencies [Line Items]

Number of vegetation management contractors (contractor) | contractor

2

Number of complaints filed (complaint) | complaint

95

Number of plaintiffs (plaintiff) | plaintiff

4,000

Number of households represented in court (household) | household

2,100

Reimbursements from insurance policies

$ 45

CONTINGENCIES AND COMMITMENTS_8

CONTINGENCIES AND COMMITMENTS (Schedule of Loss Accrual) (Details) - Butte Fire - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 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	(267)	(479)	(60)
Loss accrual, ending balance	294	$ 561	$ 690
Settlement agreements entered	832
Settlement agreement paid	$ 806

CONTINGENCIES AND COMMITMENTS_9

CONTINGENCIES AND COMMITMENTS (Schedule of Insurance Receivable) (Details) - USD ($) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Insurance Receivable [Roll Forward]
Reimbursements	$ (64)	$ 166
Butte Fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	596	$ 575	$ 575	$ 0
Accrued insurance recoveries	0		297	625
Reimbursements	(436)		(276)	(50)
Insurance Receivable, Ending Balance	$ 160		$ 596	$ 575

CONTINGENCIES AND COMMITMENT_10

CONTINGENCIES AND COMMITMENTS (Regulatory Proceedings) (Details) - USD ($)	Jan. 01, 2019	Sep. 21, 2018	May 17, 2018	Apr. 26, 2018	Jun. 30, 2018	Sep. 30, 2018
Loss Contingencies [Line Items]
Maximum statutory penalty						$ 50,000
Administrative limit						8,000,000
Forecast
Loss Contingencies [Line Items]
Maximum statutory penalty	$ 100,000
Minimum
Loss Contingencies [Line Items]
Fines incurred in prior periods						50,000
Maximum
Loss Contingencies [Line Items]
Fines incurred in prior periods						$ 16,800,000
Pacific Gas & Electric Co | Electric
Loss Contingencies [Line Items]
Requested revenue rate		98.85%
Ex Parte Communications
Loss Contingencies [Line Items]
Proposed penalty				$ 97,500,000
Payment to State General Fund			$ 12,000,000	12,000,000
Gas transmission and storage revenue reduction				63,500,000
2018 GTandS revenue requirement reduction				31,750,000
2019 GTandS revenue requirement reduction				31,750,000
Revenue requirement reduction in Next GRC cycle				10,000,000
Payment to city of San Bruno			6,000,000	6,000,000
Payment to city of San Carlos			$ 6,000,000	$ 6,000,000
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Accrual for GTandS revenue requirement reduction					$ 24,000,000

CONTINGENCIES AND COMMITMENT_11

CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Accrued legal liabilities	$ 94	$ 86

CONTINGENCIES AND COMMITMENT_12

CONTINGENCIES AND COMMITMENTS (Disallowance of Plant Costs) (Details) - Disallowance of Plant Costs $ in Millions	Jun. 23, 2016USD ($)
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance	$ 696
Permanently disallowed capital	120
Amount subject to audit	$ 576

CONTINGENCIES AND COMMITMENT_13

CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Liability) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Topock natural gas compressor station	$ 362	$ 334
Hinkley natural gas compressor station	151	147
Former manufactured gas plant sites owned by the Utility or third parties	375	320
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	116	115
Fossil fuel-fired generation facilities and sites	136	123
Total environmental remediation liability	$ 1,140	$ 1,039

CONTINGENCIES AND COMMITMENT_14

CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Long-term Purchase Commitment [Line Items]
Topock natural gas compressor station	$ 362		$ 334
Hinkley natural gas compressor station	151		147
Former manufactured gas plant sites owned by the Utility or third parties	375		320
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	116		115
Fossil fuel-fired generation facilities and sites	136		123
Recorded third-party environmental recoveries receivable	797
Environmental Remediation Liability	1,140		$ 1,039
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	299
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	138
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 508
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	$ 136
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	$ 88

CONTINGENCIES AND COMMITMENT_15

CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) - USD ($)	3 Months Ended	6 Months Ended
	Sep. 30, 2018	Jun. 30, 2018
Loss Contingencies [Line Items]
Costs for insurance coverage	$ 360,000,000	$ 50,000,000
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage	1,400,000,000
Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage	700,000,000
Catastrophic bond reinsurance instrument	10,000,000
Insurance Coverage for Property Damages
Loss Contingencies [Line Items]
Liability insurance coverage	700,000,000
Catastrophic bond reinsurance instrument	$ 200,000,000

CONTINGENCIES AND COMMITMENT_16

CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions	6 Months Ended	9 Months Ended
	Jun. 30, 2018nuclear_generating_unit	Sep. 30, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation		$ 47
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Potential premium obligation		$ 3

CONTINGENCIES AND COMMITMENT_17

CONTINGENCIES AND COMMITMENTS (Resolution of Remaining Chapter 11 Disputed Claims) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Disputed claims and customer refunds	$ 217	$ 243

CONTINGENCIES AND COMMITMENT_18

CONTINGENCIES AND COMMITMENTS (Tax Matters and Tax Cuts and Jobs Act of 2017) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Disaggregation of Revenue [Line Items]
Unrecognized tax benefits, decrease resulting from Settlements with taxing authorities	$ 10
Adjustment of provisional tax expense	12
Reduction to regulatory liability	$ 80

CONTINGENCIES AND COMMITMENT_19

CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Billions	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
Recorded unconditional purchase obligation	$ 44