PG&E (PCG) 10-Q 3 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	Apr. 24, 2018
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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 Common Stock, Shares Outstanding		516,427,502
Pacific Gas & Electric Co
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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 Common Stock, Shares Outstanding		264,374,809

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues
Electric	$ 2,951	$ 3,065
Natural gas	1,105	1,203
Total operating revenues	4,056	4,268
Operating Expenses
Cost of electricity	819	847
Cost of natural gas	289	325
Operating and maintenance	1,597	1,517
Depreciation, amortization, and decommissioning	752	712
Total operating expenses	3,457	3,401
Operating Income	599	867
Interest income	9	5
Interest expense	(220)	(218)
Other income, net	108	34
Income Before Income Taxes	496	688
Income tax provision	51	109
Net Income	445	579
Preferred stock dividend requirement of subsidiary	3	3
Preferred stock dividend requirement	0
Income Available for Common Stock	$ 442	$ 576
Weighted Average Common Shares Outstanding, Basic (in shares)	515	508
Weighted Average Common Shares Outstanding, Diluted (in shares)	516	511
Net Earnings Per Common Share, Basic (in dollars per share)	$ 0.86	$ 1.13
Net Earnings Per Common Share, Diluted (in dollars per share)	0.86	1.13
Dividends Declared Per Common Share (in dollars per share)	$ 0	$ 0.49
Pacific Gas & Electric Co
Operating Revenues
Electric	$ 2,951	$ 3,067
Natural gas	1,105	1,204
Total operating revenues	4,056	4,271
Operating Expenses
Cost of electricity	819	847
Cost of natural gas	289	325
Operating and maintenance	1,597	1,518
Depreciation, amortization, and decommissioning	752	712
Total operating expenses	3,457	3,402
Operating Income	599	869
Interest income	9	5
Interest expense	(217)	(216)
Other income, net	109	31
Income Before Income Taxes	500	689
Income tax provision	48	120
Net Income	452	569
Preferred stock dividend requirement of subsidiary	0
Preferred stock dividend requirement	3	3
Income Available for Common Stock	$ 449	$ 566

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net Income	$ 445	$ 579
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, at respective dates)	0	0
Total other comprehensive income (loss)	0	0
Comprehensive Income	445	579
Comprehensive income	445
Preferred stock dividend requirement of subsidiary	3	3
Comprehensive Income Attributable to Common Shareholders	442	576
Pacific Gas & Electric Co
Net Income	452	569
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0 and $0, at respective dates)	0	1
Total other comprehensive income (loss)	0	1
Comprehensive income	$ 452	$ 570

CONDENSED CONSOLIDATED STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0
Pacific Gas & Electric Co
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 144	$ 449
Accounts receivable:
Customers (net of allowance for doubtful accounts of $59 and $64 at respective dates)	1,222	1,243
Accrued unbilled revenue	851	946
Regulatory balancing accounts	1,367	1,222
Other	652	861
Regulatory assets	646	615
Inventories:
Gas stored underground and fuel oil	79	115
Materials and supplies	374	366
Other	520	464
Total current assets	5,855	6,281
Property, Plant, and Equipment
Electric	55,654	55,133
Gas	19,934	19,641
Construction work in progress	2,562	2,471
Other	2	3
Total property, plant, and equipment	78,152	77,248
Accumulated depreciation	(23,811)	(23,459)
Net property, plant, and equipment	54,341	53,789
Other Noncurrent Assets
Regulatory assets	3,724	3,793
Nuclear decommissioning trusts	2,842	2,863
Income taxes receivable	65	65
Other	1,327	1,221
Total other noncurrent assets	7,958	7,942
TOTAL ASSETS	68,154	68,012
Current Liabilities
Short-term borrowings	967	931
Long-term debt, classified as current	394	445
Accounts payable:
Trade creditors	1,231	1,646
Regulatory balancing accounts	1,264	1,120
Other	710	517
Disputed claims and customer refunds	245	243
Interest payable	145	217
Other	1,964	2,010
Total current liabilities	6,920	7,129
Noncurrent Liabilities
Long-term debt	17,407	17,753
Regulatory liabilities	8,586	8,679
Pension and other post-retirement benefits	2,094	2,128
Asset retirement obligations	4,946	4,899
Deferred income taxes	5,990	5,822
Other	2,228	2,130
Total noncurrent liabilities	41,251	41,411
Commitments and Contingencies (Note 9)
Shareholders' Equity
Common stock	12,701	12,632
Reinvested earnings	7,043	6,596
Accumulated other comprehensive income (loss)	(13)	(8)
Total shareholders' equity	19,731	19,220
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	19,983	19,472
TOTAL LIABILITIES AND EQUITY	68,154	68,012
Pacific Gas & Electric Co
Current Assets
Cash and cash equivalents	122	447
Accounts receivable:
Customers (net of allowance for doubtful accounts of $59 and $64 at respective dates)	1,222	1,243
Accrued unbilled revenue	851	946
Regulatory balancing accounts	1,367	1,222
Other	661	862
Regulatory assets	646	615
Inventories:
Gas stored underground and fuel oil	79	115
Materials and supplies	374	366
Other	519	465
Total current assets	5,841	6,281
Property, Plant, and Equipment
Electric	55,654	55,133
Gas	19,934	19,641
Construction work in progress	2,562	2,471
Total property, plant, and equipment	78,150	77,245
Accumulated depreciation	(23,808)	(23,456)
Net property, plant, and equipment	54,342	53,789
Other Noncurrent Assets
Regulatory assets	3,724	3,793
Nuclear decommissioning trusts	2,842	2,863
Income taxes receivable	64	64
Other	1,200	1,094
Total other noncurrent assets	7,830	7,814
TOTAL ASSETS	68,013	67,884
Current Liabilities
Short-term borrowings	846	799
Long-term debt, classified as current	45	445
Accounts payable:
Trade creditors	1,231	1,644
Regulatory balancing accounts	1,264	1,120
Other	760	538
Disputed claims and customer refunds	245	243
Interest payable	145	214
Other	1,982	2,018
Total current liabilities	6,518	7,021
Noncurrent Liabilities
Long-term debt	17,407	17,403
Regulatory liabilities	8,586	8,679
Pension and other post-retirement benefits	1,990	2,026
Asset retirement obligations	4,946	4,899
Deferred income taxes	6,130	5,963
Other	2,240	2,146
Total noncurrent liabilities	41,299	41,116
Commitments and Contingencies (Note 9)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,505	8,505
Reinvested earnings	10,107	9,656
Accumulated other comprehensive income (loss)	4	6
Total shareholders' equity	20,196	19,747
Total equity	20,196	19,747
TOTAL LIABILITIES AND EQUITY	$ 68,013	$ 67,884

CONDENSED CONSOLIDATED BALANCE6

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Allowance for doubtful accounts	$ 59	$ 64
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	516,003,957	514,755,845
Pacific Gas & Electric Co
Allowance for doubtful accounts	$ 59	$ 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 STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities
Net income	$ 445	$ 579
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	752	712
Allowance for equity funds used during construction	(32)	(19)
Deferred income taxes and tax credits, net	178	252
Other	30	8
Effect of changes in operating assets and liabilities:
Accounts receivable	120	373
Butte-related insurance receivable	197	(7)
Inventories	28	(2)
Accounts payable	24	(13)
Butte-related third-party claims	(118)	(44)
Other current assets and liabilities	(145)	(137)
Regulatory assets, liabilities, and balancing accounts, net	114	(176)
Other noncurrent assets and liabilities	(81)	48
Net cash provided by operating activities	1,512	1,574
Cash Flows from Investing Activities
Capital expenditures	(1,470)	(1,216)
Proceeds from sales and maturities of nuclear decommissioning trust investments	494	470
Purchases of nuclear decommissioning trust investments	(505)	(493)
Other	6	4
Net cash used in investing activities	(1,475)	(1,235)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $0 and $2 at respective dates	36	(755)
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 $0 and $10 at respective dates	0	590
Long-term debt matured or repurchased	(400)	0
Common stock issued	35	146
Common stock dividends paid	0	(243)
Other	(13)	(90)
Net cash used in financing activities	(342)	(352)
Net change in cash and cash equivalents	(305)	(13)
Cash and cash equivalents at January 1	449	177
Cash and cash equivalents at March 31	144	164
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(268)	(246)
Income taxes, net	0	1
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	0	250
Capital expenditures financed through accounts payable	255	237
Noncash common stock issuances	0	4
Terminated capital leases	137	0
Pacific Gas & Electric Co
Cash Flows from Operating Activities
Net income	452	569
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	752	712
Allowance for equity funds used during construction	(32)	(19)
Deferred income taxes and tax credits, net	175	264
Other	(1)	57
Effect of changes in operating assets and liabilities:
Accounts receivable	112	322
Butte-related insurance receivable	197	(7)
Inventories	28	(2)
Accounts payable	55	(3)
Butte-related third-party claims	(118)	(44)
Other current assets and liabilities	(131)	(113)
Regulatory assets, liabilities, and balancing accounts, net	114	(176)
Other noncurrent assets and liabilities	(87)	38
Net cash provided by operating activities	1,516	1,598
Cash Flows from Investing Activities
Capital expenditures	(1,470)	(1,216)
Proceeds from sales and maturities of nuclear decommissioning trust investments	494	470
Purchases of nuclear decommissioning trust investments	(505)	(493)
Other	6	4
Net cash used in investing activities	(1,475)	(1,235)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $0 and $2 at respective dates	47	(755)
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 $0 and $10 at respective dates	0	590
Long-term debt matured or repurchased	(400)	0
Preferred stock dividends paid	0	(3)
Common stock dividends paid	0	(244)
Equity contribution from PG&E Corporation	0	125
Other	(13)	(87)
Net cash used in financing activities	(366)	(374)
Net change in cash and cash equivalents	(325)	(11)
Cash and cash equivalents at January 1	447	71
Cash and cash equivalents at March 31	122	60
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(259)	(242)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	255	237
Terminated capital leases	$ 137	$ 0

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Discount on net issuances of commercial paper	$ 0	$ 2
Premium, discount, and issuance costs on proceeds from long-term debt	0	10
Pacific Gas & Electric Co
Discount on net issuances of commercial paper	0	2
Premium, discount, and issuance costs on proceeds from long-term debt	$ 0	$ 10

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 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, Del Norte, 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 also resulted in 44 fatalities. The Northern California wildfires are under investigation by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed. Further, the CPUC's SED is conducting investigations to assess the compliance of electric and communication companies' facilities with applicable rules and regulations in fire-impacted areas. See "Northern California Wildfires" in Note 9 below.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 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 months ended March 31, 2018 and 2017 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2018 2017 2018 2017 Service cost for benefits earned $ 128 $ 118 $ 16 $ 15 Interest cost 172 179 17 19 Expected return on plan assets (255 ) (193 ) (33 ) (24 ) Amortization of prior service cost (1 ) (2 ) 4 4 Amortization of net actuarial loss 1 6 (1 ) 1 Net periodic benefit cost 45 108 3 15 Regulatory account transfer (1) 39 (23 ) — — Total $ 84 $ 85 $ 3 $ 15 (1) 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. 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 March 31, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) 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) — (2 ) (2 ) Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively) (5 ) — (5 ) Net current period other comprehensive gain (loss) (5 ) — (5 ) Ending balance $ (30 ) $ 17 $ (13 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended March 31, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1 ) 2 1 Amortization of net actuarial loss (net of taxes of $3, and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $2 and $2, respectively) (2 ) (3 ) (5 ) Net current period other comprehensive gain (loss) — — — Ending balance $ (25 ) $ 16 $ (9 ) (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 months ended March 31, 2018. A majority of the Utility's revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. 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 as a result of seasonality, weather, and customer usage patterns. The FERC authorizes the Utility’s revenue requirements in periodic (often annual) 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 March 31, Electric 2018 Revenue from contracts with customers Residential $ 1,336 Commercial 1,073 Industrial 324 Agricultural 125 Public street and highway lighting 20 Other (1) (201 ) Total revenue from contracts with customers - electric 2,677 Regulatory balancing accounts (2) 274 Total electric operating revenue $ 2,951 Natural gas Revenue from contracts with customers Residential $ 958 Commercial 196 Transportation service only 297 Other (1) (52 ) Total revenue from contracts with customers - gas 1,399 Regulatory balancing accounts (2) (294 ) Total natural gas operating revenue 1,105 Total operating revenues $ 4,056 (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 March 31, 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 actuaries. The capitalization of service costs only will result in higher rate base and will lead to 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. 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. In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. 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 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.

REGULATORY ASSETS, LIABILITIES,

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS	REGULATORY A SSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Current Regulatory Assets At March 31, 2018 and December 31, 2017, the Utility had current regulatory assets of $646 million and $615 million , which included $444 million and $426 million , respectively, of costs related to CEMA fire prevention and vegetation management. Long-Term Regulatory Assets Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) March 31, 2018 December 31, 2017 Pension benefits $ 1,915 $ 1,954 Environmental compliance costs 749 837 Utility retained generation 308 319 Price risk management 68 65 Unamortized loss, net of gain, on reacquired debt 88 79 Catastrophic event memorandum account 314 274 Other 282 265 Total long-term regulatory assets $ 3,724 $ 3,793 Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) March 31, 2018 December 31, 2017 Cost of removal obligations $ 5,674 $ 5,547 Deferred income taxes 873 1,021 Recoveries in excess of AROs 533 624 Public purpose programs 591 590 Other 915 897 Total long-term regulatory liabilities $ 8,586 $ 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) March 31, 2018 December 31, 2017 Electric distribution $ 176 $ — Electric transmission 125 139 Utility generation 203 — Gas distribution and transmission 269 486 Energy procurement 1 71 Public purpose programs 115 103 Other 478 423 Total regulatory balancing accounts receivable $ 1,367 $ 1,222 Payable Balance at (in millions) March 31, 2018 December 31, 2017 Electric distribution $ — $ 72 Electric transmission 108 120 Utility generation — 14 Energy procurement 265 149 Public purpose programs 491 452 Other 400 313 Total regulatory balancing accounts payable $ 1,264 $ 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	3 Months Ended
	Mar. 31, 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 March 31, 2018 : (in millions) Termination Date Facility Limit Letters of Credit Outstanding Commercial Paper Facility Availability PG&E Corporation April 2022 $ 300 (1) $ — $ 121 $ 179 Utility April 2022 3,000 (2) 48 97 2,855 Total revolving credit facilities $ 3,300 $ 48 $ 218 $ 3,034 (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 In January 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% Senior Notes due October 15, 2018. On January 31, 2018, the Utility deposited with the trustee funds sufficient to effect the early redemption of these bonds and satisfy and discharge its remaining obligation of $400 million on February 18, 2018. In April 2018, PG&E Corporation entered into a $350 million floating rate unsecured term loan. The term loan matures 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 16, 2018, PG&E Corporation issued a notice of early redemption of these bonds, with a redemption date of April 26, 2018. Variable Rate Interest At March 31, 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 1.52% to 1.65% . At March 31, 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	3 Months Ended
	Mar. 31, 2018
Stockholders' Equity Note [Abstract]
EQUITY	EQUITY PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 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 445 452 Common stock issued 35 — Share-based compensation 34 — Preferred stock dividend requirement — (3 ) Preferred stock dividend requirement of subsidiary (3 ) — Balance at March 31, 2018 $ 19,983 $ 20,196 There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the three months ended March 31, 2018 . As of March 31, 2018 , the remaining gross sales available under this agreement were $ 246.3 million. PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans. During the three months ended March 31, 2018 , 1.2 million shares were issued for cash proceeds of $ 35.1 million under these plans.

EARNINGS PER SHARE

EARNINGS PER SHARE	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
EARNINGS PER SHARE	EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended March 31, (in millions, except per share amounts) 2018 2017 Income available for common shareholders $ 442 $ 576 Weighted average common shares outstanding, basic 515 508 Add incremental shares from assumed conversions: Employee share-based compensation 1 3 Weighted average common shares outstanding, diluted 516 511 Total earnings per common share, diluted $ 0.86 $ 1.13 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	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVES	DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at Underlying Product Instruments March 31, December 31, Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 184,948,051 228,768,745 Options 31,481,247 60,736,806 Electricity (Megawatt-hours) Forwards, Futures and Swaps 2,602,376 2,872,013 Congestion Revenue Rights (3) 304,484,831 312,272,177 (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 March 31, 2018 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance Current assets – other $ 30 $ (2 ) $ 6 $ 34 Other noncurrent assets – other 98 (1 ) — 97 Current liabilities – other (52 ) 2 19 (31 ) Noncurrent liabilities – other (68 ) 1 12 (55 ) Total commodity risk $ 8 $ — $ 37 $ 45 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 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended March 31, (in millions) 2018 2017 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (12 ) $ (48 ) Realized loss - cost of electricity (2) (18 ) (5 ) Realized loss - cost of natural gas (2) (1 ) (1 ) Net commodity risk $ (31 ) $ (54 ) (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. 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 contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At March 31, 2018 , the Utility’s credit rating was investment grade. If the Utility’s 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 additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows: Balance at (in millions) March 31, December 31, Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (1 ) $ (1 ) Related derivatives in an asset position — — Collateral posting in the normal course of business related to these derivatives — — Net position of derivative contracts/additional collateral posting requirements (1) $ (1 ) $ (1 ) (1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 – Other inputs that are directly or indirectly observable in the marketplace. • Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements March 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Nuclear decommissioning trusts Short-term investments $ 28 — — — $ 28 Global equity securities 1,862 — — — 1,862 Fixed-income securities 776 599 — — 1,375 Assets measured at NAV — — — — 17 Total nuclear decommissioning trusts (2) 2,666 599 — — 3,282 Price risk management instruments (Note 7) Electricity — 2 125 3 130 Gas — 1 — — 1 Total price risk management instruments — 3 125 3 131 Rabbi trusts Fixed-income securities — 74 — — 74 Life insurance contracts — 69 — — 69 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 162 Total long-term disability trust 5 — — — 167 TOTAL ASSETS $ 2,671 $ 745 $ 125 $ 3 $ 3,723 Liabilities: Price risk management instruments (Note 7) Electricity $ 8 $ 25 $ 85 $ (33 ) $ 85 Gas — 2 — (1 ) 1 TOTAL LIABILITIES $ 8 $ 27 $ 85 $ (34 ) $ 86 (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. 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 three months ended March 31, 2018 and 2017 . Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the 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) March 31, 2018 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 125 $ 25 Market approach CRR auction prices $ (7.44) - 13.91 Power purchase agreements $ — $ 60 Discounted cash flow Forward prices $ 18.81 - 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 table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2018 and 2017 : 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) (2 ) (6 ) Asset (liability) balance as of March 31 $ 40 $ 49 (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 March 31, 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 March 31, 2018 At December 31, 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 348 $ 350 $ 350 Utility 16,693 17,723 17,090 19,128 Nuclear Decommissioning Trust Investments The following table provides a summary of equity securities and available-for-sale debt securities: (in millions) As of March 31, 2018 Amortized Total Total Total Fair Nuclear decommissioning trusts Short-term investments $ 28 $ — $ — $ 28 Global equity securities 475 1,405 (1 ) 1,879 Fixed-income securities 1,355 39 (19 ) 1,375 Total (1) $ 1,858 $ 1,444 $ (20 ) $ 3,282 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 $440 million for the periods ended March 31, 2018 and December 31, 2017 , primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) March 31, 2018 Less than 1 year $ 42 1–5 years 438 5–10 years 374 More than 10 years 521 Total maturities of fixed-income securities $ 1,375 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended March 31, (in millions) 2018 2017 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 494 $ 470 Gross realized gains on securities 37 29 Gross realized losses on securities (4 ) (5 )

CONTINGENCIES AND COMMITMENTS

CONTINGENCIES AND COMMITMENTS	3 Months Ended
	Mar. 31, 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 be reasonably estimated. 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 Northern California Wildfires Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, 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 also resulted in 44 fatalities. The Utility incurred costs of $259 million for service restoration and repair to the Utility’s facilities (including $108 million in capital expenditures) through March 31, 2018 , in connection with these fires. 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 Northern California wildfires are under investigation by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed. Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. (For example, on February 3, 2018, it was reported that investigators with the Santa Rosa Fire Department had completed their investigation of two small fires that reportedly destroyed two homes and damaged one outbuilding and had concluded that the Utility’s facilities, along with high wind and other factors, contributed to those fires.) It is uncertain when the investigations will be complete and whether Cal Fire will release any preliminary findings before its investigations are complete. As of April 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. The investigations into the fires are ongoing. 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 other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations. Given the incomplete investigations and the uncertainty as to the causes of the fires, PG&E Corporation and the Utility do not believe a loss is probable at this time. However, it is reasonably possible that facts could emerge through the course of the various investigations that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in an accrued liability in the future, the amount of which could be substantial. PG&E Corporation and the Utility currently are unable to reasonably estimate the amount of potential losses (or range of amounts) that they could incur given the preliminary stages of the investigations and the uncertainty regarding the extent and magnitude of potential damages. On January 31, 2018, the California Department of Insurance issued a press release announcing an update on property losses in connection with the October and December wildfires in California, stating that, as of such date, “insurers have received nearly 45,000 insurance claims totaling more than $11.79 billion in losses,” of which approximately $10 billion relates to statewide claims from the October 2017 wildfires. The remaining amount relates to claims from the Southern California December 2017 wildfires. According to the California Department of Insurance, as of the date of the press release, more than 21,000 homes, 3,200 businesses, and more than 6,100 vehicles, watercraft, farm vehicles, and other equipment were damaged or destroyed by the October 2017 wildfires. PG&E Corporation and the Utility have not independently verified these estimates. The California Department of Insurance did not state in its press release whether it intends to provide updated estimates of losses in the future. If the Utility’s facilities are determined to be the cause of one or more of the Northern California wildfires, PG&E Corporation and the Utility could be liable for the related property losses and other damages. The California Department of Insurance January 31, 2018 press release reflects insured property losses only. The press release does not account for uninsured losses, interest, attorneys’ fees, fire suppression costs, evacuation costs, medical expenses, personal injury and wrongful death damages or other costs. If the Utility were to be found liable for certain or all of such other costs and expenses, the amount of PG&E Corporation’s and the Utility’s liability could be higher than the approximately $10 billion in estimated insured property losses with respect to the wildfires that occurred in October 2017, depending on the extent of the damage in connection with such fire or fires. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. As of May 1, 2018, PG&E Corporation and the Utility are aware of more than 150 lawsuits representing approximately 2,500 plaintiffs, 6 of which seek to be certified as class actions, that have been filed against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the fires. The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages. In addition, insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed 8 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. Various government entities, including Mendocino, Napa and Sonoma Counties, have also asserted claims against PG&E Corporation and the Utility in the San Francisco County Superior Court 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 April 16, 2018, PG&E Corporation and the Utility submitted notices of claims against, among other government entities, Mendocino, Napa and Sonoma Counties, reserving their rights to pursue claims against these entities for contribution and equitable indemnity stemming from these entities’ actions and inactions before and during the Northern California wildfires. On October 31, 2017, a group of plaintiffs submitted a petition for coordination to the Chair of the Judicial Council of California and requested coordination of the litigation in the San Francisco Superior Court. On November 9, 2017, PG&E Corporation and the Utility submitted a petition for coordination to the Chair of the Judicial Council of California, and requested separate coordination in the counties in which the fires occurred. On January 4, 2018, the coordination motion judge of the San Francisco Superior Court entered an order granting coordination of the litigation in connection with the Northern California wildfires and recommending that the coordinated proceeding take place in the San Francisco Superior Court. On January 12, 2018, the Judicial Council of California accepted the coordination motion judge’s recommendation and assigned the coordinated proceeding to San Francisco. The first case management conference took place on February 27, 2018. The individual plaintiffs, subrogation insurance carriers and certain government entities filed Master Complaints on March 12, 2018, and PG&E Corporation and the Utility filed Master Answers to those Master Complaints on March 16, 2018. PG&E Corporation and the Utility also filed on March 16, 2018, a legal challenge to the inverse condemnation causes of action in the Master Complaints. The court set a hearing on that challenge for May 18, 2018. The next case management conference will be scheduled at the May 18, 2018 hearing. In addition, two derivative lawsuits 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. The first lawsuit is filed against the members of the Board of Directors and certain officers of PG&E Corporation. PG&E Corporation is identified as a nominal defendant in that action. The second lawsuit is filed against the members of the Board of Directors, certain former members of the Board of Directors, and certain officers of both PG&E Corporation and the Utility. PG&E Corporation and the Utility are identified as nominal defendants in that action. On February 14, 2018, the Court consolidated the two lawsuits, and, 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 discovery. 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. The Utility has 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 the Utility's 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. If the Utility were to be found liable for one or more fires, the Utility's insurance could be insufficient to cover that liability, depending on the extent of the damage in connection with such fire or fires. Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of approximately $630 million for any potential future event. In addition, it could take a number of years before the Utility’s final liability is known. The Utility may be unable to recover costs in excess of insurance through regulatory mechanisms and, even if such recovery is possible, it could take a number of years to resolve and a number of years thereafter to collect. PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Litigation and Regulatory Citations in Connection with the 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 had previously authorized the coordination of all cases in Sacramento County. As of March 31, 2018 , 79 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 3,770 individual plaintiffs representing approximately 2,000 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. 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. Prior to March 31, 2018 , several plaintiffs dismissed the Utility's two vegetation management contractors from their complaints. The number of individual complaints and plaintiffs may still increase in the future, because the statute of limitations for property damage in connection with the Butte fire has not yet expired. (The statute of limitations for personal injury in connection with the Butte fire has expired.) The Utility continues mediating and settling cases. In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility's vegetation contractors. The Utility and Cal Fire are currently engaged in a mediation process. Further, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates to be approximately $190 million . This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors. The County seeks to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also seeks punitive damages. It had previously indicated that it intended to bring a claim against the Utility that it estimated to be approximately $85 million . On March 2, 2018, the County served a mediation demand seeking in excess of $167 million . This claim includes costs that the County of Calaveras allegedly incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. The Utility and the County of Calaveras are currently engaged in a mediation process. On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. On August 10, 2017, the Court denied the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hire and train qualified employees. On August 16, 2017, the Utility filed a writ with the Court of Appeal challenging the trial court's ruling on punitive damages. The Court of Appeal accepted the writ on September 15, 2017, and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ was completed as of January 2, 2018. The Utility sought expedited review of the motion. On April 4, 2018, the Court of Appeal indicated that it is prepared to issue a decision without oral argument. On April 13, 2018 and April 16, 2018, respectively, the plaintiffs and the Utility requested oral argument, which is now scheduled for June 22, 2018. 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 condemnation applies to the Utility with respect to the Butte fire. The Court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could file lawsuits and make similar claims. On January 4, 2018, the Utility filed with the Court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases. On May 1, 2018, the Court issued its ruling on the Utility's renewed motion in which the Court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The Court determined that it is bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell . Further, the Court stated that the Utility's constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raises the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The next case management conference is scheduled for June 7, 2018. The Utility intends to file a writ seeking review of this decision. No trial date is pending. Estimated Losses from Third-Party Claims In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion in connection with the Butte fire. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages, but does not include punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility's early assumptions about fire suppression costs (including its assessment of the Cal Fire loss) and the County of Calaveras claim, it does not include any significant portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim. The Utility currently is unable to reasonably estimate the upper end of the range of losses due to uncertainties related to the applicability of inverse condemnation and punitive damages and because it has insufficient information on the claims of over 600 households who have asserted claims, the claim from the OES, as well as claims from any other households that may be brought before the statute of limitations for property damage expires. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of the potential claim from the OES, outcomes of future court or jury decisions, and information about damages, including punitive damages, for which the Utility could be liable, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. 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 Other current liabilities 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) (118 ) Balance at March 31, 2018 $ 443 (1) As of March 31, 2018 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $734 million of which $657 million has been paid by the Utility. In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $99 million in connection with the Butte fire. For the three months ended March 31, 2018 , the Utility incurred legal expenses in connection with the Butte fire of $12 million . Loss Recoveries The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of $922 million . The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. Through March 31, 2018 , the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors (excluded from the table below), including $7 million received in the three months ended March 31, 2018 . Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain. 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 (197 ) Balance at March 31, 2018 $ 399 In April 2018, the Utility received another $31 million in insurance reimbursements. If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded. Regulatory Citations On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million . The SED's investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent a gray pine tree from leaning and contacting the Utility's electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017. Enforcement Matters In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. It is uncertain whether any charges will be brought against the Utility as a result of these investigations. Regulatory Proceedings Order Instituting an Investigation into Compliance with Ex Parte Communication Rules On April 26, 2018, the CPUC approved the revised proposed decision issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the "settlement agreement") by the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN. The decision results in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ( $31.75 million ) and 2019 ( $31.75 million ), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ( $6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above. The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017 violate the CPUC ex-parte rules. The Utility is unable to predict the timing and outcome of the second phase in this proceeding. At March 31, 2018 , PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $8 million accrual for a portion of the 2018 GT&S revenue requirement reduction and an accrual of the $24 million payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred. For more information about the proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K. Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties. Potential Safety Citations The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED

SUMMARY OF SIGNIFICANT ACCOUN18

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 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.
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 months ended March 31, 2018. A majority of the Utility's revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. 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 as a result of seasonality, weather, and customer usage patterns. The FERC authorizes the Utility’s revenue requirements in periodic (often annual) 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 March 31, Electric 2018 Revenue from contracts with customers Residential $ 1,336 Commercial 1,073 Industrial 324 Agricultural 125 Public street and highway lighting 20 Other (1) (201 ) Total revenue from contracts with customers - electric 2,677 Regulatory balancing accounts (2) 274 Total electric operating revenue $ 2,951 Natural gas Revenue from contracts with customers Residential $ 958 Commercial 196 Transportation service only 297 Other (1) (52 ) Total revenue from contracts with customers - gas 1,399 Regulatory balancing accounts (2) (294 ) Total natural gas operating revenue 1,105 Total operating revenues $ 4,056 (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 March 31, 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 actuaries. The capitalization of service costs only will result in higher rate base and will lead to 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. 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. In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that entities may elect not to restate their comparative periods in the period of adoption. 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 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.
Earnings Per Share	PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.
Derivative Instruments	The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting.
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 be reasonably estimated. 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 ACCOUN19

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	3 Months Ended
	Mar. 31, 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 months ended March 31, 2018 and 2017 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2018 2017 2018 2017 Service cost for benefits earned $ 128 $ 118 $ 16 $ 15 Interest cost 172 179 17 19 Expected return on plan assets (255 ) (193 ) (33 ) (24 ) Amortization of prior service cost (1 ) (2 ) 4 4 Amortization of net actuarial loss 1 6 (1 ) 1 Net periodic benefit cost 45 108 3 15 Regulatory account transfer (1) 39 (23 ) — — Total $ 84 $ 85 $ 3 $ 15 (1) 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 March 31, 2018 Beginning balance $ (25 ) $ 17 $ (8 ) 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) — (2 ) (2 ) Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively) (5 ) — (5 ) Net current period other comprehensive gain (loss) (5 ) — (5 ) Ending balance $ (30 ) $ 17 $ (13 ) (1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. (See the “Pension and Other Post-Retirement Benefits” table above for additional details.) Pension Benefits Other Total (in millions, net of income tax) Three Months Ended March 31, 2017 Beginning balance $ (25 ) $ 16 $ (9 ) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1 ) 2 1 Amortization of net actuarial loss (net of taxes of $3, and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $2 and $2, respectively) (2 ) (3 ) (5 ) Net current period other comprehensive gain (loss) — — — Ending balance $ (25 ) $ 16 $ (9 ) (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 March 31, Electric 2018 Revenue from contracts with customers Residential $ 1,336 Commercial 1,073 Industrial 324 Agricultural 125 Public street and highway lighting 20 Other (1) (201 ) Total revenue from contracts with customers - electric 2,677 Regulatory balancing accounts (2) 274 Total electric operating revenue $ 2,951 Natural gas Revenue from contracts with customers Residential $ 958 Commercial 196 Transportation service only 297 Other (1) (52 ) Total revenue from contracts with customers - gas 1,399 Regulatory balancing accounts (2) (294 ) Total natural gas operating revenue 1,105 Total operating revenues $ 4,056 (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, LIABILITIE20

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) March 31, 2018 December 31, 2017 Pension benefits $ 1,915 $ 1,954 Environmental compliance costs 749 837 Utility retained generation 308 319 Price risk management 68 65 Unamortized loss, net of gain, on reacquired debt 88 79 Catastrophic event memorandum account 314 274 Other 282 265 Total long-term regulatory assets $ 3,724 $ 3,793
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) March 31, 2018 December 31, 2017 Cost of removal obligations $ 5,674 $ 5,547 Deferred income taxes 873 1,021 Recoveries in excess of AROs 533 624 Public purpose programs 591 590 Other 915 897 Total long-term regulatory liabilities $ 8,586 $ 8,679
Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) March 31, 2018 December 31, 2017 Electric distribution $ 176 $ — Electric transmission 125 139 Utility generation 203 — Gas distribution and transmission 269 486 Energy procurement 1 71 Public purpose programs 115 103 Other 478 423 Total regulatory balancing accounts receivable $ 1,367 $ 1,222
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) March 31, 2018 December 31, 2017 Electric distribution $ — $ 72 Electric transmission 108 120 Utility generation — 14 Energy procurement 265 149 Public purpose programs 491 452 Other 400 313 Total regulatory balancing accounts payable $ 1,264 $ 1,120

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 : (in millions) Termination Date Facility Limit Letters of Credit Outstanding Commercial Paper Facility Availability PG&E Corporation April 2022 $ 300 (1) $ — $ 121 $ 179 Utility April 2022 3,000 (2) 48 97 2,855 Total revolving credit facilities $ 3,300 $ 48 $ 218 $ 3,034 (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)	3 Months Ended
	Mar. 31, 2018
Stockholders' Equity Note [Abstract]
Changes in Equity	PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 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 445 452 Common stock issued 35 — Share-based compensation 34 — Preferred stock dividend requirement — (3 ) Preferred stock dividend requirement of subsidiary (3 ) — Balance at March 31, 2018 $ 19,983 $ 20,196

EARNINGS PER SHARE (Tables)

EARNINGS PER SHARE (Tables)	3 Months Ended
	Mar. 31, 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 March 31, (in millions, except per share amounts) 2018 2017 Income available for common shareholders $ 442 $ 576 Weighted average common shares outstanding, basic 515 508 Add incremental shares from assumed conversions: Employee share-based compensation 1 3 Weighted average common shares outstanding, diluted 516 511 Total earnings per common share, diluted $ 0.86 $ 1.13

DERIVATIVES (Tables)

DERIVATIVES (Tables)	3 Months Ended
	Mar. 31, 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 March 31, December 31, Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 184,948,051 228,768,745 Options 31,481,247 60,736,806 Electricity (Megawatt-hours) Forwards, Futures and Swaps 2,602,376 2,872,013 Congestion Revenue Rights (3) 304,484,831 312,272,177 (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 March 31, 2018 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance Current assets – other $ 30 $ (2 ) $ 6 $ 34 Other noncurrent assets – other 98 (1 ) — 97 Current liabilities – other (52 ) 2 19 (31 ) Noncurrent liabilities – other (68 ) 1 12 (55 ) Total commodity risk $ 8 $ — $ 37 $ 45 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 March 31, 2018 , the Utility’s outstanding derivative balances were as follows: Commodity Risk (in millions) Gross Derivative Balance Netting Cash Collateral Total Derivative Balance Current assets – other $ 30 $ (2 ) $ 6 $ 34 Other noncurrent assets – other 98 (1 ) — 97 Current liabilities – other (52 ) 2 19 (31 ) Noncurrent liabilities – other (68 ) 1 12 (55 ) Total commodity risk $ 8 $ — $ 37 $ 45 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
Gains And Losses On Derivative Instruments	Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended March 31, (in millions) 2018 2017 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (12 ) $ (48 ) Realized loss - cost of electricity (2) (18 ) (5 ) Realized loss - cost of natural gas (2) (1 ) (1 ) Net commodity risk $ (31 ) $ (54 ) (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered	The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows: Balance at (in millions) March 31, December 31, Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (1 ) $ (1 ) Related derivatives in an asset position — — Collateral posting in the normal course of business related to these derivatives — — Net position of derivative contracts/additional collateral posting requirements (1) $ (1 ) $ (1 ) (1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on a Recurring Basis	Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements March 31, 2018 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Nuclear decommissioning trusts Short-term investments $ 28 — — — $ 28 Global equity securities 1,862 — — — 1,862 Fixed-income securities 776 599 — — 1,375 Assets measured at NAV — — — — 17 Total nuclear decommissioning trusts (2) 2,666 599 — — 3,282 Price risk management instruments (Note 7) Electricity — 2 125 3 130 Gas — 1 — — 1 Total price risk management instruments — 3 125 3 131 Rabbi trusts Fixed-income securities — 74 — — 74 Life insurance contracts — 69 — — 69 Total rabbi trusts — 143 — — 143 Long-term disability trust Short-term investments 5 — — — 5 Assets measured at NAV — — — — 162 Total long-term disability trust 5 — — — 167 TOTAL ASSETS $ 2,671 $ 745 $ 125 $ 3 $ 3,723 Liabilities: Price risk management instruments (Note 7) Electricity $ 8 $ 25 $ 85 $ (33 ) $ 85 Gas — 2 — (1 ) 1 TOTAL LIABILITIES $ 8 $ 27 $ 85 $ (34 ) $ 86 (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. 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) March 31, 2018 Fair Value Measurement Assets Liabilities Valuation Unobservable Range (1) Congestion revenue rights $ 125 $ 25 Market approach CRR auction prices $ (7.44) - 13.91 Power purchase agreements $ — $ 60 Discounted cash flow Forward prices $ 18.81 - 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 table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2018 and 2017 : 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) (2 ) (6 ) Asset (liability) balance as of March 31 $ 40 $ 49 (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 March 31, 2018 At December 31, 2017 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 348 $ 350 $ 350 Utility 16,693 17,723 17,090 19,128
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 March 31, 2018 Amortized Total Total Total Fair Nuclear decommissioning trusts Short-term investments $ 28 $ — $ — $ 28 Global equity securities 475 1,405 (1 ) 1,879 Fixed-income securities 1,355 39 (19 ) 1,375 Total (1) $ 1,858 $ 1,444 $ (20 ) $ 3,282 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 $440 million for the periods ended March 31, 2018 and December 31, 2017 , primarily related to deferred taxes on appreciation of investment value.
Schedule of Maturities on Debt Instruments	The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) March 31, 2018 Less than 1 year $ 42 1–5 years 438 5–10 years 374 More than 10 years 521 Total maturities of fixed-income securities $ 1,375
Schedule of Activity for Debt and Equity Securities	The following table provides a summary of activity for fixed income and equity securities: Three Months Ended March 31, (in millions) 2018 2017 Proceeds from sales and maturities of nuclear decommissioning trust investments $ 494 $ 470 Gross realized gains on securities 37 29 Gross realized losses on securities (4 ) (5 )

CONTINGENCIES AND COMMITMENTS (

CONTINGENCIES AND COMMITMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
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 Other current liabilities 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) (118 ) Balance at March 31, 2018 $ 443 (1) As of March 31, 2018 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $734 million of which $657 million has been paid by the Utility.
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 (197 ) Balance at March 31, 2018 $ 399
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 March 31, December 31, (in millions) 2018 2017 Topock natural gas compressor station $ 342 $ 334 Hinkley natural gas compressor station 144 147 Former manufactured gas plant sites owned by the Utility or third parties (1) 329 320 Utility-owned generation facilities (other than fossil fuel-fired), (2) 113 115 Fossil fuel-fired generation facilities and sites (3) 157 123 Total environmental remediation liability $ 1,085 $ 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 Shell Pond site. (3) Primarily driven by the San Francisco Potrero Power Plant

ORGANIZATION AND BASIS OF PRE27

ORGANIZATION AND BASIS OF PRESENTATION (Narrative) (Details) a in Thousands	3 Months Ended
	Mar. 31, 2018segmentfatality	Oct. 30, 2017awildfirestructure
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		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 ACCOUN28

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 128	$ 118
Interest cost	172	179
Expected return on plan assets	(255)	(193)
Amortization of prior service cost	(1)	(2)
Amortization of net actuarial loss	1	6
Net periodic benefit cost	45	108
Regulatory account transfer	39	(23)
Total	84	85
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	16	15
Interest cost	17	19
Expected return on plan assets	(33)	(24)
Amortization of prior service cost	4	4
Amortization of net actuarial loss	(1)	1
Net periodic benefit cost	3	15
Regulatory account transfer	0	0
Total	$ 3	$ 15

SUMMARY OF SIGNIFICANT ACCOUN29

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 19,472
Ending balance	19,983
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(8)	$ (9)
Net current period other comprehensive gain (loss)	(5)	0
Ending balance	(13)	(9)
AOCI Attributable to Parent | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(25)	(25)
Net current period other comprehensive gain (loss)	(5)	0
Ending balance	(30)	(25)
AOCI Attributable to Parent | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	16
Net current period other comprehensive gain (loss)	0	0
Ending balance	17	16
Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	1
Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(1)
Amount attributable to tax	0	1
Amortization of prior service cost (net of taxes of $0 and $1, respectively) (1) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	3	2
Amount attributable to tax	1	2
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	4
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	3
Amount attributable to tax	0	3
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) (1) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	1
Amount attributable to tax	0	0
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(5)
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	(2)
Amount attributable to tax	0	2
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(3)
Amount attributable to tax	1	$ 2
Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(5)
Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(5)
Amount attributable to tax	0
Reclassification of stranded income tax to retained earnings (net of taxes of $0 and $0, respectively) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0
Amount attributable to tax	$ 0

SUMMARY OF SIGNIFICANT ACCOUN30

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenue from contracts with customers
Total operating revenues	$ 4,056	$ 4,268
Electric
Revenue from contracts with customers
Total revenue from contracts with customers	2,677
Regulatory balancing accounts	274
Total operating revenues	2,951
Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	1,336
Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,073
Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	324
Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	125
Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	20
Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	(201)
Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	1,399
Regulatory balancing accounts	(294)
Total operating revenues	1,105
Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	958
Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	196
Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	297
Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ (52)

SUMMARY OF SIGNIFICANT ACCOUN31

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Increase in operating and maintenance expense	$ 1,597	$ 1,517
Increase in other income	$ 108	34
Accounting Standards Update 2017-07
Public Utility, Property, Plant and Equipment [Line Items]
Increase in operating and maintenance expense		13
Increase in other income		$ 14

REGULATORY ASSETS, LIABILITIE32

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory assets, current	$ 646	$ 615
Catastrophic Event Memorandum Account
Regulatory Assets [Line Items]
Regulatory assets, current	$ 444	$ 426

REGULATORY ASSETS, LIABILITIE33

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 3,724	$ 3,793
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,915	1,954
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	749	837
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	308	319
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	68	65
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	88	79
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	314	274
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 282	$ 265

REGULATORY ASSETS, LIABILITIE34

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 8,586	$ 8,679
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	5,674	5,547
Deferred income taxes
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	873	1,021
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	533	624
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	591	590
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 915	$ 897

REGULATORY ASSETS, LIABILITIE35

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,367	$ 1,222
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	176	0
Total regulatory balancing accounts receivable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	125	139
Total regulatory balancing accounts receivable | Utility generation
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	203	0
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	269	486
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1	71
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	115	103
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	478	423
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1,264	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	108	120
Total regulatory balancing accounts payable | Utility generation
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	14
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	265	149
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	491	452
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 400	$ 313

DEBT (Schedule of Line of Credi

DEBT (Schedule of Line of Credit) (Details)	3 Months Ended
	Mar. 31, 2018USD ($)
Debt [Line Items]
Facility Limit	$ 300,000,000
Letters of Credit Outstanding	0
Commercial Paper	121,000,000
Facility Availability	179,000,000
Letters of credit sublimit	50,000,000
Swingline loans sublimit	$ 100,000,000
Swingline loan repay term	7 days
Utility
Debt [Line Items]
Facility Limit	$ 3,000,000,000
Letters of Credit Outstanding	48,000,000
Commercial Paper	97,000,000
Facility Availability	2,855,000,000
Letters of credit sublimit	500,000,000
Swingline loans sublimit	75,000,000
Credit Facilities
Debt [Line Items]
Facility Limit	3,300,000,000
Letters of Credit Outstanding	48,000,000
Commercial Paper	218,000,000
Facility Availability	$ 3,034,000,000

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($)	Apr. 30, 2018	Mar. 31, 2018	Feb. 28, 2018	Feb. 18, 2018	Jan. 31, 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%
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		$ 614,000,000
Pacific Gas & Electric Co | Pollution Control Bonds Series 1996 C, E, F, And 1997 B | Minimum
Debt [Line Items]
Debt instrument, interest rate		1.52%
Pacific Gas & Electric Co | Pollution Control Bonds Series 1996 C, E, F, And 1997 B | Maximum
Debt [Line Items]
Debt instrument, interest rate		1.65%
Pacific Gas & Electric Co | Pollution Control Bonds Series 2009 A-B
Debt [Line Items]
Debt instrument, face amount		$ 149,000,000
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	$ 400,000,000
Debt instrument, interest rate					8.25%
Subsequent Event | Floating Rate Unsecured Term Loan, Due 2020 | Unsecured Debt
Debt [Line Items]
Debt instrument, face amount	$ 350,000,000
Unsecured Debt | Pacific Gas & Electric Co | 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
	Mar. 31, 2018	Mar. 31, 2017
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 19,472
Comprehensive income	445
Common stock issued	35
Share-based compensation	34
Preferred stock dividend requirement	0
Preferred stock dividend requirement of subsidiary	(3)	$ (3)
Ending balance	19,983
Pacific Gas & Electric Co
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	19,747
Comprehensive income	452	570
Common stock issued	0
Share-based compensation	0
Preferred stock dividend requirement	(3)	$ (3)
Preferred stock dividend requirement of subsidiary	0
Ending balance	$ 20,196

EQUITY (Narrative) (Details)

EQUITY (Narrative) (Details) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)shares
Equity Contract
Schedule Of Changes In Equity [Line Items]
Remaining equity distribution agreement amount	$ 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) | shares	1.2
Proceeds from stock issuance	$ 35.1

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
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Income available for common shareholders	$ 442	$ 576
Weighted average common shares outstanding, basic (in shares)	515	508
Employee share-based compensation (in shares)	1	3
Weighted average common shares outstanding, diluted (in shares)	516	511
Total earnings per common share, diluted (in dollars per share)	$ 0.86	$ 1.13

DERIVATIVES (Volumes of Outstan

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Mar. 31, 2018MWhMMBTU	Dec. 31, 2017MWhMMBTU
Forwards, Futures and Swaps | Natural gas
Derivative [Line Items]
Contract Volume | MMBTU	184,948,051	228,768,745
Forwards, Futures and Swaps | Electricity
Derivative [Line Items]
Contract Volume | MWh	2,602,376	2,872,013
Options | Natural gas
Derivative [Line Items]
Contract Volume | MMBTU	31,481,247	60,736,806
Congestion Revenue Rights | Electricity
Derivative [Line Items]
Contract Volume | MWh	304,484,831	312,272,177

DERIVATIVES (Outstanding Deriva

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ 8	$ 20
Derivative Asset, Netting	0	0
Cash Collateral	37	31
Total Derivative Balance, Assets	45	51
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	30	30
Derivative Asset, Netting	(2)	(3)
Cash Collateral	6	10
Total Derivative Balance, Assets	34	37
Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	98	103
Derivative Asset, Netting	(1)	(1)
Cash Collateral	0	0
Total Derivative Balance, Assets	97	102
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(52)	(47)
Derivative Liability, Netting	2	3
Cash Collateral	19	13
Total Derivative Balance, Liabilities	(31)	(31)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(68)	(66)
Derivative Liability, Netting	1	1
Cash Collateral	12	8
Total Derivative Balance, Liabilities	$ (55)	$ (57)

DERIVATIVES (Gains And Losses O

DERIVATIVES (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unrealized gain (loss) - regulatory assets and liabilities	$ (12)	$ (48)
Realized loss - cost of electricity	(18)	(5)
Realized loss - cost of natural gas	(1)	(1)
Net commodity risk	$ (31)	$ (54)

DERIVATIVES (Additional Cash Co

DERIVATIVES (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$ (1)	$ (1)
Related derivatives in an asset position	0	0
Collateral posting in the normal course of business related to these derivatives	0	0
Net position of derivative contracts/additional collateral posting requirements	$ (1)	$ (1)

FAIR VALUE MEASUREMENTS (Assets

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Assets:
Short-term investments		$ 385
Derivative Asset	$ 131	139
TOTAL ASSETS	3,723	4,145
Liabilities:
Price risk management instruments, netting	(34)
TOTAL LIABILITIES	86	88
Amount primarily related to deferred taxes on appreciation of investment value	440	440
Nuclear decommissioning trusts
Assets:
Short-term investments	28	23
Global equity securities	1,862	1,967
Fixed-income securities	1,375	1,295
Assets measured at NAV	17	18
TOTAL ASSETS	3,282	3,303
Rabbi trusts
Assets:
Fixed-income securities	74	72
Life insurance contracts	69	71
TOTAL ASSETS	143	143
Long-term disability trust
Assets:
Short-term investments	5	8
Assets measured at NAV	162	167
TOTAL ASSETS	167	175
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	3	6
Derivative Asset	130	138
Liabilities:
Price risk management instruments, netting	(33)	(25)
Derivative Liability	85	87
Price Risk Derivative, Gas
Assets:
Derivative Asset	1	1
Liabilities:
Price risk management instruments, netting	(1)	0
Derivative Liability	1	1
Level 1
Assets:
Short-term investments		385
Derivative Asset	0	0
TOTAL ASSETS	2,671	3,116
Liabilities:
TOTAL LIABILITIES	8	10
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	28	23
Global equity securities	1,862	1,967
Fixed-income securities	776	733
TOTAL ASSETS	2,666	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	5	8
TOTAL ASSETS	5	8
Level 1 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	8	10
Level 1 | Price Risk Derivative, Gas
Assets:
Derivative Asset	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Level 2
Assets:
Short-term investments		0
Derivative Asset	3	4
TOTAL ASSETS	745	709
Liabilities:
TOTAL LIABILITIES	27	16
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	599	562
TOTAL ASSETS	599	562
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	74	72
Life insurance contracts	69	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	2	3
Liabilities:
Price risk management instruments, gross subject to netting	25	15
Level 2 | Price Risk Derivative, Gas
Assets:
Derivative Asset	1	1
Liabilities:
Price risk management instruments, gross subject to netting	2	1
Level 3
Assets:
Short-term investments		0
Derivative Asset	125	129
TOTAL ASSETS	125	129
Liabilities:
TOTAL LIABILITIES	85	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	125	129
Liabilities:
Price risk management instruments, gross subject to netting	85	87
Level 3 | Price Risk Derivative, Gas
Assets:
Derivative Asset	0	0
Liabilities:
Price risk management instruments, gross subject to netting	$ 0	$ 0

FAIR VALUE MEASUREMENTS (Level

FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)$ / MWh	Dec. 31, 2017USD ($)$ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 3,723	$ 4,145
Liabilities, Fair Value	86	88
Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	125	129
Liabilities, Fair Value	25	24
Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	0	0
Liabilities, Fair Value	$ 60	$ 63
Minimum | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	(7.44)	(16.03)
Minimum | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	18.81	18.81
Maximum | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	13.91	11.99
Maximum | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range | $ / MWh	38.80	38.80

FAIR VALUE MEASUREMENTS (Leve47

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset (liability) balance	$ 42	$ 55
Included in regulatory assets and liabilities or balancing accounts	(2)	(6)
Ending asset (liability) balance	$ 40	$ 49

FAIR VALUE MEASUREMENTS (Carryi

FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 348	$ 350
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	350	350
Pacific Gas & Electric Co | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	17,723	19,128
Pacific Gas & Electric Co | Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 16,693	$ 17,090

FAIR VALUE MEASUREMENTS (Schedu

FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 1,858	$ 1,799
Total Unrealized Gains	1,444	1,514
Total Unrealized Losses	(20)	(10)
Total Fair Value	3,282	3,303
Amount primarily related to deferred taxes on appreciation of investment value	440	440
Short-term investments
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	28	23
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	28	23
Global equity securities
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	475	524
Total Unrealized Gains	1,405	1,463
Total Unrealized Losses	(1)	(2)
Total Fair Value	1,879	1,985
Fixed-income securities
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,355	1,252
Total Unrealized Gains	39	51
Total Unrealized Losses	(19)	(8)
Total Fair Value	$ 1,375	$ 1,295

FAIR VALUE MEASUREMENTS (Sche50

FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) $ in Millions	Mar. 31, 2018USD ($)
Fair Value Disclosures [Abstract]
Less than 1 year	$ 42
1–5 years	438
5–10 years	374
More than 10 years	521
Total maturities of fixed-income securities	$ 1,375

FAIR VALUE MEASUREMENTS (Sche51

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 494	$ 470
Gross realized gains on securities	37	29
Gross realized losses on securities	$ (4)	$ (5)

CONTINGENCIES AND COMMITMENTS52

CONTINGENCIES AND COMMITMENTS (Northern California Wildfires) (Details) insurance_claim in Thousands, a in Thousands, $ in Thousands	May 01, 2018lawsuitcomplaintplaintiff	Jan. 31, 2018USD ($)vehicleinsurance_claimhomebusiness	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)	Apr. 30, 2018USD ($)incident_report	Feb. 03, 2018wildfireoutbuildinghome	Nov. 20, 2017lawsuit	Oct. 30, 2017awildfirefatalitystructure
Loss Contingencies [Line Items]
Capital expenditures			$ 255,000	$ 237,000
Loss from Catastrophes | Lawsuits Against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts | Subsequent Event
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit	150
Number of plaintiffs in lawsuit (plaintiff) | plaintiff	2,500
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 | Subsequent Event
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | lawsuit	6
Loss from Catastrophes | Subrogation Complaints Against PG&E Corporation and the Utility in San Francisco County Superior Courts | Subsequent Event
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit) | complaint	8
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) | lawsuit							2
Nothern California Wild Fire
Loss Contingencies [Line Items]
Number wildfires (wildfire) | wildfire								21
Number of acres burned (acre) | a								245
Number structures destroyed (structure) | structure								8,900
Number of fatalities caused by fire (fatality) | fatality								44
Service restoration and repair costs			259,000
Capital expenditures			108,000
Insurance claims received by insurers (insurance claim) | insurance_claim		45
Total insurance claims received by insurers		$ 11,790,000
Statewide insurance claims related to wildfire		$ 10,000,000
Number homes damaged by wildfire (home) | home		21,000
Number of businesses damaged by wildfire (business) | business		3,200
Number of vehicles damaged by wildfire (vehicle) | vehicle		6,100
Liability insurance coverage			840,000
Initial self-insured retention per occurrence			10,000
Further retention per occurrence			40,000
Reinstated liability insurance			$ 630,000
Nothern California Wild Fire | Subsequent Event
Loss Contingencies [Line Items]
Number of electric incident reports submitted (incident report) | incident_report					23
Property damage coverage per incident					$ 50
Nothern California Wild Fire | Santa Rosa Investigations
Loss Contingencies [Line Items]
Number wildfires (wildfire) | wildfire						2
Number of homes destroyed by fire (home) | home						2
Number of outbuildings damaged by fire (outbuilding) | outbuilding						1

CONTINGENCIES AND COMMITMENTS53

CONTINGENCIES AND COMMITMENTS (Litigation and Regulatory Citations in Connection with the Butte Fire) (Details) $ in Millions	Mar. 30, 2018contractor	Mar. 02, 2018USD ($)	Feb. 20, 2018USD ($)	Apr. 25, 2017USD ($)citation	Apr. 13, 2017USD ($)	Apr. 30, 2018USD ($)	May 31, 2017USD ($)	Mar. 31, 2018USD ($)householdcontractorcomplaintplaintiff	May 23, 2016contractor	Apr. 28, 2016afatalitystructureoutbuildinghomecomercial_property
Loss Contingencies [Line Items]
Number of vegetation management contractors dismissed from complaints (contractor) | contractor	2
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	2
Number of complaints filed (complaint) | complaint								79
Number of plaintiffs (plaintiff) | plaintiff								3,770
Number of households represented in court (household) | household								2,000
Number of master complaints (complaint) | complaint								2
Fire fighting costs recovery requested					$ 87
Value of claims brought against the company							$ 190
Number of households with inestimable losses | household								600
Cumulative legal expenses incurred								$ 99
Legal expenses incurred								12
Coverage for third party liability								922
Probable insurance recoveries								922
Cumulative 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
Butte Fire | County Of Calaveras
Loss Contingencies [Line Items]
Value of claims brought against company		$ 167	$ 85
Subsequent Event | Butte Fire
Loss Contingencies [Line Items]
Cumulative reimbursements from insurance policies						$ 31

CONTINGENCIES AND COMMITMENTS54

CONTINGENCIES AND COMMITMENTS (Schedule of Loss Accrual) (Details) - Butte Fire - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Loss Contingency Accrual [Roll Forward]
Loss accrual, beginning balance	$ 561,000,000	$ 690,000,000	$ 0
Accrued losses	0	350,000,000	750,000,000
Payments	(118,000,000)	(479,000,000)	(60,000,000)
Loss accrual, ending balance	443,000,000	$ 561,000,000	$ 690,000,000
Settlement agreements entered	734,000,000
Settlement agreement paid	$ 657,000,000

CONTINGENCIES AND COMMITMENTS55

CONTINGENCIES AND COMMITMENTS (Schedule of Insurance Receivable) (Details) - Butte Fire - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	$ 596	$ 575	$ 0
Accrued insurance recoveries	0	297	625
Reimbursements	(197)	(276)	(50)
Insurance Receivable, Ending Balance	$ 399	$ 596	$ 575

CONTINGENCIES AND COMMITMENTS56

CONTINGENCIES AND COMMITMENTS (Regulatory Proceedings) (Details)	3 Months Ended
	Mar. 31, 2018USD ($)
Potential Safety Citations
Loss Contingencies [Line Items]
Safety and enforcement division maximum statutory penalty per violation	$ 50,000
Safety and enforcement division administrative limit per citation	8,000,000
Potential Safety Citations | Minimum
Loss Contingencies [Line Items]
S E D fines for self reported violations	50,000
Potential Safety Citations | Maximum
Loss Contingencies [Line Items]
S E D fines for self reported violations	16,800,000
Ex Parte Communications
Loss Contingencies [Line Items]
Payment to State General Fund	12,000,000
Proposed penalty	97,500,000
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
Payment to city of San Carlos	6,000,000
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Accrual for GTandS revenue requirement reduction	8,000,000
Payable to California General Fund and Cities of San Bruno and San Carlos
Loss Contingencies [Line Items]
Accrual for settlement payments	$ 24,000,000

CONTINGENCIES AND COMMITMENTS57

CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Accrued legal liabilities	$ 89	$ 86

CONTINGENCIES AND COMMITMENTS58

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 COMMITMENTS59

CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Liability) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Topock natural gas compressor station	$ 342	$ 334
Hinkley natural gas compressor station	144	147
Former manufactured gas plant sites owned by the Utility or third parties	329	320
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	113	115
Fossil fuel-fired generation facilities and sites	157	123
Total environmental remediation liability	$ 1,085	$ 1,039

CONTINGENCIES AND COMMITMENTS60

CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies) (Details) $ in Millions	Mar. 31, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Recorded third-party environmental recoveries receivable	$ 737
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	293
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	146
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	340
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	142
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 106
Pacific Gas & Electric Co | Topock Site
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Pacific Gas & Electric Co | Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Pacific Gas & Electric Co | Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%

CONTINGENCIES AND COMMITMENTS61

CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Potential premium obligation	$ 47
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Potential premium obligation	$ 3

CONTINGENCIES AND COMMITMENTS62

CONTINGENCIES AND COMMITMENTS (Resolution of Remaining Chapter 11 Disputed Claims) (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Disputed claims and customer refunds	$ 245	$ 243

CONTINGENCIES AND COMMITMENTS63

CONTINGENCIES AND COMMITMENTS (Tax Matters) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Disaggregation Of Revenue [Line Items]
Unrecognized tax benefits, decrease resulting from Settlements with taxing authorities	$ 20
Pacific Gas & Electric Co | Forecast | Rate Case 2015, 2017, 2019
Disaggregation Of Revenue [Line Items]
Reduction in revenue requirement			$ 325
Increase to rate base		$ 613	271
Pacific Gas & Electric Co | Forecast | Other Rate Cases, Including TO19
Disaggregation Of Revenue [Line Items]
Reduction in revenue requirement			125
Increase to rate base		$ 200	$ 100

CONTINGENCIES AND COMMITMENTS64

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