PG&E (PCG) 10-Q 2 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 24, 2017
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Trading Symbol	PCG
Entity Registrant Name	PG&E CORP
Entity Central Index Key	1,004,980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		514,422,806
Pacific Gas And Electric Company [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Trading Symbol	PCG
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	75,488
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		264,374,809

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Operating Revenues
Electric	$ 3,648	$ 3,994	$ 10,036	$ 10,590
Natural gas	869	816	2,999	2,363
Total operating revenues	4,517	4,810	13,035	12,953
Operating Expenses
Cost of electricity	1,466	1,613	3,436	3,719
Cost of natural gas	78	80	524	377
Operating and maintenance	1,364	1,783	4,414	5,631
Depreciation, amortization, and decommissioning	710	694	2,134	2,090
Total operating expenses	3,618	4,170	10,508	11,817
Operating Income	899	640	2,527	1,136
Interest income	9	8	22	17
Interest expense	(220)	(211)	(663)	(621)
Other income, net	25	24	59	74
Income Before Income Taxes	713	461	1,945	606
Income tax provision (benefit)	160	70	403	(105)
Net Income	553	391	1,542	711
Preferred stock dividend requirement of subsidiary	3	3	10	10
Income Available for Common Shareholders	$ 550	$ 388	$ 1,532	$ 701
Weighted Average Common Shares Outstanding, Basic	513	501	511	497
Weighted Average Common Shares Outstanding, Diluted	516	503	514	500
Net Earnings Per Common Share, Basic	$ 1.07	$ 0.77	$ 3	$ 1.41
Net Earnings Per Common Share, Diluted	1.07	0.77	2.98	1.40
Dividends Declared Per Common Share	$ 0.53	$ 0.49	$ 1.55	$ 1.44
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	$ 3,647	$ 3,993	$ 10,038	$ 10,590
Natural gas	869	816	2,999	2,363
Total operating revenues	4,516	4,809	13,037	12,953
Operating Expenses
Cost of electricity	1,466	1,613	3,436	3,719
Cost of natural gas	78	80	524	377
Operating and maintenance	1,428	1,782	4,477	5,630
Depreciation, amortization, and decommissioning	710	694	2,134	2,090
Total operating expenses	3,682	4,169	10,571	11,816
Operating Income	834	640	2,466	1,137
Interest income	10	8	22	16
Interest expense	(217)	(209)	(655)	(614)
Other income, net	24	23	52	68
Income Before Income Taxes	651	462	1,885	607
Income tax provision (benefit)	138	73	394	(99)
Net Income	513	389	1,491	706
Preferred stock dividend requirement	3	3	10	10
Income Available for Common Shareholders	$ 510	$ 386	$ 1,481	$ 696

Condensed Consolidated Stateme3

Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net income	$ 553	$ 391	$ 1,542	$ 711
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	0	0	1	0
Total other comprehensive income (loss)	0	0	1	0
Comprehensive Income	553	391	1,543	711
Preferred stock dividend requirement of subsidiary	3	3	10	10
Comprehensive Income Attributable to Common Shareholders	550	388	1,533	701
Pacific Gas And Electric Company [Member]
Net income	513	389	1,491	706
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	0	0	1	1
Total other comprehensive income (loss)	0	0	1	1
Comprehensive Income	$ 513	$ 389	$ 1,492	$ 707

Condensed Consolidated Stateme4

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 191	$ 177
Restricted cash	7	7
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 at both periods)	1,368	1,252
Accrued unbilled revenue	972	1,098
Regulatory balancing accounts	1,478	1,500
Other	992	801
Regulatory assets	573	423
Inventories
Gas stored underground and fuel oil	138	117
Materials and supplies	360	346
Income taxes receivable	25	160
Other	279	283
Total current assets	6,383	6,164
Property, Plant, and Equipment
Electric	54,148	52,556
Gas	18,938	17,853
Construction work in progress	2,421	2,184
Other	2	2
Total property, plant, and equipment	75,509	72,595
Accumulated depreciation	(22,986)	(22,014)
Net property, plant, and equipment	52,523	50,581
Other Noncurrent Assets
Regulatory assets	8,546	7,951
Nuclear decommissioning trusts	2,793	2,606
Income taxes receivable	52	70
Other	1,229	1,226
Total other noncurrent assets	12,620	11,853
TOTAL ASSETS	71,526	68,598
Current Liabilities
Short-term borrowings	869	1,516
Long-term debt, classified as current	700	700
Accounts payable
Trade creditors	1,419	1,495
Regulatory balancing accounts	1,328	645
Other	483	433
Disputed claims and customer refunds	240	236
Interest payable	163	216
Other	2,271	2,323
Total current liabilities	7,473	7,564
Noncurrent Liabilities
Long-term debt	16,619	16,220
Regulatory liabilities	7,265	6,805
Pension and other postretirement benefits	2,707	2,641
Asset retirement obligations	4,758	4,684
Deferred income taxes	11,085	10,213
Other	2,333	2,279
Total noncurrent liabilities	44,767	42,842
Commitments and Contingencies (Note 9)
Shareholders' Equity
Common stock	12,560	12,198
Reinvested earnings	6,482	5,751
Accumulated other comprehensive income (loss)	(8)	(9)
Total shareholders' equity	19,034	17,940
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	19,286	18,192
TOTAL LIABILITIES AND EQUITY	71,526	68,598
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	70	71
Restricted cash	7	7
Accounts receivable
Customers (net of allowance for doubtful accounts of $58 at both periods)	1,368	1,252
Accrued unbilled revenue	972	1,098
Regulatory balancing accounts	1,478	1,500
Other	992	801
Regulatory assets	573	423
Inventories
Gas stored underground and fuel oil	138	117
Materials and supplies	360	346
Income taxes receivable	24	159
Other	279	282
Total current assets	6,261	6,056
Property, Plant, and Equipment
Electric	54,148	52,556
Gas	18,938	17,853
Construction work in progress	2,421	2,184
Total property, plant, and equipment	75,507	72,593
Accumulated depreciation	(22,984)	(22,012)
Net property, plant, and equipment	52,523	50,581
Other Noncurrent Assets
Regulatory assets	8,546	7,951
Nuclear decommissioning trusts	2,793	2,606
Income taxes receivable	52	70
Other	1,104	1,110
Total other noncurrent assets	12,495	11,737
TOTAL ASSETS	71,279	68,374
Current Liabilities
Short-term borrowings	869	1,516
Long-term debt, classified as current	700	700
Accounts payable
Trade creditors	1,419	1,494
Regulatory balancing accounts	1,328	645
Other	502	453
Disputed claims and customer refunds	240	236
Interest payable	163	214
Other	1,999	2,072
Total current liabilities	7,220	7,330
Noncurrent Liabilities
Long-term debt	16,270	15,872
Regulatory liabilities	7,265	6,805
Pension and other postretirement benefits	2,612	2,548
Asset retirement obligations	4,758	4,684
Deferred income taxes	11,377	10,510
Other	2,279	2,230
Total noncurrent liabilities	44,561	42,649
Commitments and Contingencies (Note 9)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,455	8,050
Reinvested earnings	9,460	8,763
Accumulated other comprehensive income (loss)	3	2
Total shareholders' equity	19,498	18,395
TOTAL LIABILITIES AND EQUITY	$ 71,279	$ 68,374

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Allowance for doubtful accounts	$ 58	$ 58
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	513,773,072	506,891,874
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$ 58	$ 58
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	264,374,809	264,374,809

Condensed Consolidated Stateme7

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash Flows from Operating Activities
Net income	$ 1,542	$ 711
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,134	2,090
Allowance for equity funds used during construction	(63)	(84)
Deferred income taxes and tax credits, net	848	644
Disallowed capital expenditures	47	517
Other	204	293
Effect of changes in operating assets and liabilities:
Accounts receivable	(58)	(283)
Inventories	(35)	(38)
Accounts payable	76	189
Income taxes receivable/payable	135	(63)
Other current assets and liabilities	23	(32)
Regulatory assets, liabilities, and balancing accounts, net	(30)	(634)
Other noncurrent assets and liabilities	68	(85)
Butte-related insurance receivable	(166)	(263)
Butte-related third-party claims	12	321
Net cash provided by operating activities	4,737	3,283
Cash Flows from Investing Activities
Capital expenditures	(3,938)	(4,128)
Decrease in restricted cash	0	66
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,043	1,019
Purchases of nuclear decommissioning trust investments	(1,071)	(1,050)
Other	16	10
Net cash used in investing activities	(3,950)	(4,083)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $4 and $5 at respective dates	(652)	(128)
Short-term debt financing	250	250
Short-term debt matured	(250)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates	734	594
Long-term debt matured or repurchased	(345)	0
Common stock issued	345	727
Common stock dividends paid	(754)	(678)
Other	(101)	(17)
Net cash provided by financing activities	(773)	748
Net change in cash and cash equivalents	14	(52)
Cash and cash equivalents at January 1	177	123
Cash and cash equivalents at September 30	191	71
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(644)	(611)
Income taxes, net	158	154
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	272	248
Capital expenditures financed through accounts payable	301	325
Noncash common stock issuances	16	15
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	1,491	706
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,134	2,090
Allowance for equity funds used during construction	(63)	(84)
Deferred income taxes and tax credits, net	848	648
Disallowed capital expenditures	47	517
Other	196	234
Effect of changes in operating assets and liabilities:
Accounts receivable	(58)	(283)
Inventories	(35)	(38)
Accounts payable	76	194
Income taxes receivable/payable	135	(64)
Other current assets and liabilities	36	(28)
Regulatory assets, liabilities, and balancing accounts, net	(30)	(634)
Other noncurrent assets and liabilities	69	(75)
Butte-related insurance receivable	(166)	(263)
Butte-related third-party claims	12	321
Net cash provided by operating activities	4,692	3,241
Cash Flows from Investing Activities
Capital expenditures	(3,938)	(4,128)
Decrease in restricted cash	0	66
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,043	1,019
Purchases of nuclear decommissioning trust investments	(1,071)	(1,050)
Other	16	10
Net cash used in investing activities	(3,950)	(4,083)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $4 and $5 at respective dates	(652)	(293)
Short-term debt financing	250	250
Short-term debt matured	(250)	0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates	734	594
Long-term debt matured or repurchased	(345)	0
Preferred stock dividends paid	(10)	(10)
Common stock dividends paid	(784)	(423)
Equity contribution from PG&E Corporation	405	740
Other	(91)	(7)
Net cash provided by financing activities	(743)	851
Net change in cash and cash equivalents	(1)	9
Cash and cash equivalents at January 1	71	59
Cash and cash equivalents at September 30	70	68
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(636)	(602)
Income taxes, net	158	151
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	0	244
Capital expenditures financed through accounts payable	$ 301	$ 325

Condensed Consolidated Stateme8

Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Discount on net issuances of commercial paper	$ 4	$ 5
Premium, discount, and issuance costs on proceeds from long-term debt	11	6
Pacific Gas And Electric Company [Member]
Discount on net issuances of commercial paper	4	5
Premium, discount, and issuance costs on proceeds from long-term debt	$ 11	$ 6

Organization And Basis Of Prese

Organization And Basis Of Presentation	9 Months Ended
	Sep. 30, 2017
Organization And Basis Of Presentation	NOTE 1: 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 gen eration 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 t o 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). T he 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 adjustment s) 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, 2016 in the Condensed Consoli dated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2016 Form 10-K. This quarterly report should be read in conjunction with the 2016 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 assump tions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes tha t 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 Corporat ion’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 California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures. The causes of these fires are being investigated by Cal Fire and the CPUC, including the possible role of t he Utility’s power lines and other facilities. See Note 10 below.

New And Significant Accounting

New And Significant Accounting Policies	9 Months Ended
	Sep. 30, 2017
New And Significant Accounting Policies	NOTE 2: SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial S tatements in the 2016 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 a ny of these VIEs at September 30, 2017 , 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 te rms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2017 , it did not consolidate any of them. Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large compon ent removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condens ed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.4 billion at September 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepare d in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets. 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 incl uded in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2017 and 2016 were as fo llows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 118 $ 113 $ 14 $ 13 Interest cost 178 179 20 19 Expected return on plan assets (193) (207) (24) (26) Amortization of prior service cost (1) 2 4 3 Amortization of net actuarial loss 6 6 1 1 Net periodic benefit cost 108 93 15 10 Regulatory account transfer (1) (23) (8) - - Total $ 85 $ 85 $ 15 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 354 $ 339 $ 44 $ 39 Interest cost 535 537 58 57 Expected return on plan assets (578) (621) (73) (80) Amortization of prior service cost (5) 6 12 11 Amortization of net actuarial loss 17 18 3 3 Net periodic benefit cost 323 279 44 30 Regulatory account transfer (1) (69) (25) - - Total $ 254 $ 254 $ 44 $ 30 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. 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 Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ (25) $ 17 $ (8) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $2 and $2, respectively) (3) (3) (6) Net current period other comprehensive gain (loss) - - - Ending balance $ (25) $ 17 $ (8) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) 2 1 3 Amortization of net actuarial loss (net of taxes of $3, and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (2) (7) Net current period other comprehensive gain (loss) - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) (3) 7 4 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 10 2 12 Regulatory account transfer (net of taxes of $5 and $6, respectively) (7) (8) (15) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) 4 6 10 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 11 2 13 Regulatory account transfer (net of taxes of $9 and $6, respectively) (15) (8) (23) Net current period other comprehensive gain (loss) - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement 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 Guidance Share-Based Payment Accounting In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718) , which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classifi cation of awards as either equity or liabilities, and classification on the statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires, on a retrospective basis, that emp loyee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $ 35 million for the nine months ended Septem ber 30, 2016. Accounting Standards Issued But Not Yet Adopted Presentation of Net Periodic Pension Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715) , which amends the existing guidance relating to the prese ntation of net periodic pension cost and net periodic postretirement benefit cost. On a retrospective basis, the amendment requires an employer to disaggregate 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. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU will be effecti ve for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. Although PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it is not expected to have a material impact to financial results. Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. PG&E Corporation and the Utility will adopt th is ASU in the first quarter of 2018 and do not expect a material impact to the Condensed Consolidated Statements of Cash Flows and related disclosures as a result of this ASU. Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the existing 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 a bout leasing arrangements. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utili ty on January 1, 2019, with early adoption permitted. PG&E Corporation and the Utility plan to early adopt this guidance in the fourth quarter of 2018 using a modified retrospective approach. The modified retrospective approach includes a number of optio nal practical expedients that entities may elect to apply. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets, and are still evaluating the impact the guidance will have on the Condensed Consolidated Statements of Income, Statements of Cash Flows and lease disclosures. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instrume nts – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which amends the existing 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. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU will be effective for PG&E Corporation and th e Utility on January 1, 2018. PG&E Corporation and the Utility do not expect a material impact to the Condensed Consolidated Financial Statements and related disclosures as a result of this ASU. Revenue Recognition Standard In May 2014, the FASB issue d ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) , which amends existing revenue recognition guidance, effective January 1, 2018 . 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. The majori ty of the Utility’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Utility generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue reco gnition for such sales. PG&E Corporation and the Utility intend to use the modified retrospective method when adopting the new standard on January 1, 2018. PG&E Corporation and the Utility expect that the impact of the new guidance will be immaterial to the Condensed Consolidated Financial Statements. Upon adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenue and disaggregate customer contract revenue by customer class.

Regulatory Assets, Liabilities,

Regulatory Assets, Liabilities, And Balancing Accounts	9 Months Ended
	Sep. 30, 2017
Regulatory Assets, Liabilities, And Balancing Accounts	NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Current Regulatory Assets At September 30, 2017, the Utility had current regulatory assets of $573 million, which included $392 million of costs related to CEMA fire prevention and vegetation management. In 2014, the CPUC directed the Utility to perform additional vegetation manag ement work in response to the severe drought in California. Long-Term Regulatory Assets Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2017 December 31, 2016 Deferred income taxes $ 4,373 $ 3,859 Pension benefits 2,487 2,429 Environmental compliance costs 779 778 Utility retained generation 331 364 Price risk management 77 92 Unamortized loss, net of gain, on reacquired debt 65 76 Other 434 353 Total long-term regulatory assets $ 8,546 $ 7,951 At September 30, 2017, other long-term regulatory assets included $189 million of catastrophic event-related costs incurred 2012 through 2017 that the Utility believes is recoverable through CEMA based on historical experience in recovering costs for these types of events. Long-Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2017 December 31, 2016 Cost of removal obligations $ 5,456 $ 5,060 Recoveries in excess of AROs 622 626 Public purpose programs 573 567 Other 614 552 Total long-term regulatory liabilities $ 7,265 $ 6,805 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K. Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ - $ 132 Electric transmission 182 244 Utility generation - 48 Gas distribution and transmission 654 541 Energy procurement 135 132 Public purpose programs 116 106 Other 391 297 Total regulatory balancing accounts receivable $ 1,478 $ 1,500 Payable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ 197 $ - Utility generation 150 - Electric transmission 142 99 Gas distribution and transmission - 48 Energy procurement 131 13 Public purpose programs 426 264 Other 282 221 Total regulatory balancing accounts payable $ 1,328 $ 645 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

Debt

Debt	9 Months Ended
	Sep. 30, 2017
Debt	NOTE 4: DEBT Revolving Credit Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2017 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2022 $ 300 (1) $ - $ - $ 300 Utility April 2022 3,000 (2) 50 369 2,581 Total revolving credit facilities $ 3,300 $ 50 $ 369 $ 2,881 (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. In May 2017, PG&E Corpor ation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022. Other Short-term Borrowings In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid. Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 22, 2018. The proceeds were used for general corporate purposes, i ncluding the repayment of a portion of the Utility’s outstanding commercial paper. Senior Notes Issuances In March 2017, the Utility issued $400 million principal amount of 3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, 2046. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Pollution Control Bonds In June 2017, the Utility repurchased and retired $34 5 million principal amount of pollution control bonds Series 2004 A through D. Additionally in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018. At September 30, 2017, 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 0.88 % to 0.95 %. At September 30, 2017, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the relat ed loan agreements, were 0.89 %.

Equity

Equity	9 Months Ended
	Sep. 30, 2017
Equity	NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2017 were as follo ws: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2016 $ 18,192 $ 18,395 Comprehensive income 1,543 1,492 Equity contributions - 405 Common stock issued 361 - Share-based compensation 2 - Common stock dividends declared (802) (784) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2017 $ 19,286 $ 19,498 In February 2017, PG& E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate price of up to $275 million. During the nine months ended September 30, 2017, PG&E Corporation sold 0.4 million shares of its common stock under the February 2017 EDA for cash proceeds of $ 28.4 million, net of commissions paid of $ 0.2 million. There were no issuances under the February 2017 EDA for the three months ended September 30, 2017. As of September 30, 2017, the remaining sales available under this agreement were $ 246.3 m illion. PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2017 , 6.4 million shares were issued for cash proceeds of $ 316 million under these plans.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2017
Earnings Per Share	NOTE 6: 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 me thod 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 outstandi ng for calculating diluted EPS: Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2017 2016 2017 2016 Income available for common shareholders $ 550 $ 388 $ 1,532 $ 701 Weighted average common shares outstanding, basic 513 501 511 497 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 3 3 Weighted average common shares outstanding, diluted 516 503 514 500 Total earnings per common share, diluted $ 1.07 $ 0.77 $ 2.98 $ 1.40 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

Derivatives

Derivatives	9 Months Ended
	Sep. 30, 2017
Derivatives	NOTE 7: 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 deriv ative 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 excha nge 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 instr uments 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 PG&E Corporation’s and the Utility’s 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 applicab le 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 def erred 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 correspon ding 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 qu antities 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 September 30, December 31, Underlying Product Instruments 2017 2016 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 300,594,593 323,301,331 Options 79,640,435 96,602,785 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,505,504 3,287,397 Congestion Revenue Rights (3) 249,876,873 278,143,281 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At September 30, 2017 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 47 $ (7) $ 9 $ 49 Other noncurrent assets – other 121 (3) - 118 Current liabilities – other (54) 7 11 (36) Noncurrent liabilities – other (81) 3 7 (71) Total commodity risk $ 33 $ - $ 27 $ 60 At December 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (6) $ (29) $ (58) $ 30 Realized loss - cost of electricity (2) (4) (7) (8) (48) Realized loss - cost of natural gas (2) (1) (9) (5) (15) Net commodity risk $ (11) $ (45) $ (71) $ (33) (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 o f 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 operati ng 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 September 30, 2017 , the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility woul d 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 trigger ed was as follows: Balance at September 30, December 31, (in millions) 2017 2016 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (16) $ (24) Related derivatives in an asset position 3 19 Collateral posting in the normal course of business related to these derivatives 11 4 Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (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	9 Months Ended
	Sep. 30, 2017
Fair Value Measurements	NOTE 8: 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 Ut ility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At September 30, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 120 $ - $ - $ - $ 120 Nuclear decommissioning trusts Short-term investments 23 - - - 23 Global equity securities 1,875 - - - 1,875 Fixed-income securities 697 569 - - 1,266 Assets measured at NAV - - - - 16 Total nuclear decommissioning trusts (2) 2,595 569 - - 3,180 Price risk management instruments (Note 7) Electricity 4 7 153 (1) 163 Gas - 4 - - 4 Total price risk management instruments 4 11 153 (1) 167 Rabbi trusts Fixed-income securities - 64 - - 64 Life insurance contracts - 71 - - 71 Total rabbi trusts - 135 - - 135 Long-term disability trust Short-term investments 5 - - - 5 Assets measured at NAV - - - - 148 Total long-term disability trust 5 - - - 153 TOTAL ASSETS $ 2,724 $ 715 $ 153 $ (1) $ 3,755 Liabilities: Price risk management instruments (Note 7) Electricity $ 11 $ 17 $ 105 $ (28) $ 105 Gas - 2 - - 2 TOTAL LIABILITIES $ 11 $ 19 $ 105 $ (28) $ 107 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 387 million, primarily related to deferred taxes on appreciat ion of investment value. Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management instruments 30 29 181 (18) 222 Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $333 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 l evels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the nine months ended September 30, 2017 and 2016 . 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 an d 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-in come 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 securit ies 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 sh are 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 investme nts 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 identic al 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 cla ssified 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 Leve l 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 aucti on 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 Corpora tion’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 cla ssification 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 resul t 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) At September 30, 2017 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 153 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 70 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Po wer purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 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 and nine months ended September 30, 2017 and 2016 : Price Risk M anagement Instruments (in millions) 2017 2016 Asset (liability) balance as of July 1 $ 48 $ 66 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) - (10) Asset (liability) balance as of September 30 $ 48 $ 56 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of January 1 $ 55 $ 89 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (7) (33) Asset (liability) balance as of September 30 $ 48 $ 56 (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, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2017 and December 31, 2016 , as they are short-term in nature or have interest rates that reset daily. The fair values of the Utility’s fixed-rate senior notes and fixed-ra te pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at September 30, 2017 and December 31, 2016 . The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2017 At December 31, 2016 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 349 $ 352 $ 348 $ 352 Utility 16,211 18,672 15,813 17,790 Available for Sale Investments The following table provides a summary of available-for-sale investments: Total Total Amortized Unrealized Unrealized Total Fair (in millions) Cost Gains Losses Value As of September 30, 2017 Nuclear decommissioning trusts Short-term investments $ 23 $ - $ - $ 23 Global equity securities 540 1,353 (2) 1,891 Fixed-income securities 1,216 56 (6) 1,266 Total (1) $ 1,779 $ 1,409 $ (8) $ 3,180 As of December 31, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 (1) Represents amounts before deducting $ 387 million and $333 million at September 30, 2017 and December 31, 2016 , respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) September 30, 2017 Less than 1 year $ 27 1–5 years 403 5–10 years 340 More than 10 years 496 Total maturities of fixed-income securities $ 1,266 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 249 $ 257 $ 1,043 $ 1,019 Gross realized gains on securities held as available-for-sale 8 6 50 15 Gross realized losses on securities held as available-for-sale - (14) (8) (17)

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2017
Commitments And Contingencies	NOTE 9: CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. A gain contingency is recorded in the period in which all uncertainties have been resolved. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. 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 Litigation and Regulatory Citations in Connection with the Butte Fire In September 2015, a wildfire (known as the “Butte fire”) ignited and spr ead 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 fatal ities, 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 for Sacramento County. Subrogation insurers also filed a separate master complai nt on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of September 30, 2017, 77 known complaints have been filed against the Utility and its two vegetation management contrac tors 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 2,080 households and their insurance companies. Thes e 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 inverse condemnation and negligence theories of liability. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases . In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, Co unty of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, e rosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include co sts that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. 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 Appeals challenging this novel theory of punitive damages liability. The Court of Appeals accepted the writ on September 15, 2017 and ordered the trial court a nd plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ should be completed by early 2018. In the third quarter of 2017, the Utility reached settlements with plaintiffs in the “preference” trial inv olving six households and with the plaintiffs in the representative trial that had been scheduled for August 2017 and October 2017, respectively. While there are no trials related to the Butte fire currently scheduled, one plaintiff has moved for a prefer ence trial involving one household. The motion is set for hearing on December 1, 2017. On October 25, 2017, the Utility filed a motion to stay the trial court proceedings pending a decision by the Court of Appeals on the pending writ of mandate regarding punitive damages. A hearing on the stay motion is calendared for December 1, 2017. 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 bee n found negligent, through the theory of inverse condemnation. On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the Utility is liable for inverse condemnation. While the ruling is bin ding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utili ty were 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, increased from the $750 million previously estimated as of December 31, 2016, in connection with the Butte fire. The Utility’s updated estimate resulted primarily from an increase in the number of claims filed against the Utility and experi ence to date in resolving claims. This amount is based on updated 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 f ire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility still does not have sufficient information to reasonably estima te any liability it may have for these additional claims. The Utility currently is unable to reasonably estimate the upper end of the range of losses because it has insufficient information on the claims of over 1,000 households, including all of the rece ntly filed claims, as well as the claims from the OES and the County of Calaveras. 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 potential claims from the OES and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, that the Utility could be liable for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss acc rued. 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 Consolidat ed 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) (338) Balance at September 30, 2017 $ 702 (1) As of September 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $515 million of which $398 million has been paid by the Utility. In addition to the amounts reflected in the table ab ove, the Utility has incurred cumulative legal expenses of $72 million in connection with the Butte fire. For the three and nine months ended September 30, 2017, the Utility has incurred legal expenses in connection with the Butte fire of $18 million and $45 million, respectively. 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 September 30, 2017, the Utility recorded $922 million for probable insurance recoveries in connection with losses rel ated 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, in the three and nine months ended September 30, 2017, the Utility r eceived $21 million and $53 million, respectively, of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). 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 (131) Balance at September 30, 2017 $ 741 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, depending on wheth er the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals. 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 the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous cond ition 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. “Ghost Ship” Fire On December 2, 2016, 36 people died in a fire that occurred in the “Ghost Ship” wareh ouse in Oakland, California, during a music event. The families of 34 people who died in the fire have filed lawsuits against the property owner, the master tenant and neighboring tenants, and others, alleging defective electrical wiring and violations of fire safety codes. On May 16, 2017, a master complaint was filed, and added both PG& E Corporation and the Utility as defendants. The master complaint alleges that the Utility violated the California Labor Code and various electric rules in that it (1) should have inspected the premises to evaluate potential workplace hazards to Utility e mployees installing/maintaining its meters there, (2) should not have permitted sub-meters in the building or should have inspected those sub-meters, and (3) should have known that the building’s sub-meters and electrical system as a whole were dangerous a nd should have terminated service. The Utility filed a demurrer to the master complaint on June 30, 2017, on multiple grounds, including that the Utility has no duty to inspect its customers’ electrical equipment. On September 12, 2017, Alameda County Su perior Court (the “court”) denied the Utility’s demurrer and on October 6, 2017, the Utility filed its answer with the court. The governmental entities (City of Oakland, County of Alameda and State of California) filed demurrers on September 12, 2017. On October 9, 2017, the plaintiffs dismissed, without prejudice, the State of California as a party to the case. On October 13, 2017, the plaintiffs filed opposition briefs to the demurrers filed by the City of Oakland and the County of Alameda. A hearing i s scheduled for November 7, 2017. Several investigations regarding the origin and cause of the fire were conducted, including by the City of Oakland and the County of Alameda, the CPUC, and a third-party consulting and engineering firm. In June 2017, th e City of Oakland released Oakland Fire Department’s report of the investigation stating that the cause of the fire was undetermined. The other investigations remain underway. PG&E Corporation and the Utility are uncertain when and how the Ghost Ship Fir e lawsuit will be resolved and believe there is a remote possibility a material loss will occur. Valero Refinery Outage On June 30, 2017, Valero Energy Corp. filed a lawsuit against the Utility after an electric outage occurred in its Benicia refinery i n May 2017. Valero’s complaint alleges causes of action for breach of contract, breach of implied contract, breach of implied warranty, breach of covenant of good faith and fair dealing, negligence and gross negligence and seeks $75 million in damages fro m the Utility, resulting from refinery equipment damage, lost revenue and punitive damages. The Utility retained a third-party consulting and engineering firm to perform a causal evaluation of this outage. On September 11, 2017, Valero filed a first amen ded complaint removing its gross negligence and punitive damage claims. On October 23, 2017, the Utility filed with the court its response to Valero’s amended complaint. On October 27, 2017, Valero served the Utility with initial disclosures stating Vale ro’s total claim is $114 million in damages associated with equipment damage and lost profits. PG&E Corporation and the Utility believe it is reasonably possible that they will incur a material loss as a result of this lawsuit, but is unable to reasonabl y estimate the amount or range because it is in early stages of litigation. Federal Investigations 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 alle gedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern Distric t of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016. The Utility is cooperating with this investigation. It is uncertain whether any charges will be brought against the Utility as a result of these investigations. CPUC Matters Order Instituting an Investigation into Compliance with Ex Parte Communication Rules On September 1, 2017, the assigned ALJ issued a PD in this proceeding adopting, with one modification, the settlement agreement jointly submitted to the CPUC on March 28, 2017, by the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and T URN. If adopted, the PD would increase the payment to the California General Fund from $1 million to $12 million resulting 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., th e 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. On September 21, 2017, the Utility submitted a motion to the CPUC accepting the proposed modification of the settlement agreement to increase the Utility’s payment to the California General Fund from $1 million to $12 million. Further, the Utility also rep orted that it has identified several communications that appear to raise issues similar to other communications that are part of this proceeding. On November 1, 2017, the Utility filed a status report advising the CPUC that the Utility and the parties to the settlement agreement were unable to reach an agreement with respect to how to proceed regarding communications that the Utility reported to the CPUC on September 21, 2017. Also on November 1, 2017, the non-Utility parties to the settlement requested that the CPUC approve the settlement, as modified by the PD, and open a second phase of the OII to investigate and consider appropriate sanctions for the new communications reported by the Utility on September 21, 2017, and others that may be discovered. The statutory deadline for this proceeding previously was extended to December 29, 2017. The Utility is unable to predict the outcome of this proceeding. At September 30, 2017, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets in clude a $24 million accrual for the amounts 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 would be recorded in the periods in which they are incurred. For more information about the proceeding, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Order Instituting an Investigation into the Utility’s Safety Culture On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and stan dards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety inciden ts. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment. On May 8, 2017, the CPUC President released the consultant’s report, accompanied by a scoping m emo and ruling. The scoping memo establishes a second phase in this OII in which the CPUC will evaluate the safety recommendations of the consultant that may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phas e of the proceeding will also consider all necessary measures, including, but not limited to, a reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented. The Utility plans to adopt and implement the vast ma jority of the consultant’s recommendations by the middle of 2018. A workshop took place in September 2017 at which the consultant presented its report and answered stakeholders’ questions. The Utility’s testimony is expected to be filed with the CPUC in the fourth quarter of 2017 with other parties’ testimony and evidentiary hearings expected in the first quarter of 2018. PG&E Corporation and the Utility are unable to predict the outcome of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity for the Utility be dependent on making safety progress as the CPUC may define in this proceeding. 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 p roperly 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 exp ected 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 syste m 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 CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations id entified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. This includes the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will impose penalties or take other enforcement action with respect to some or all of these violations. The Utility is unable to reasonably e stimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED and other CPUC staff have in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines. The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, wi th an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to deter mine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in atte mpting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED historically has exercised broad discretion in determining w hether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even after the SED has issued a citation. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 mill ion for violations of electric and natural gas laws and regulations. On January 12, 2017, a residential structure fire occurred in Yuba City, California resulting in the collapse of the house and injuries to two persons inside the house. The CPUC, a thir d-party engineering firm engaged by the Utility, and local fire and police officials have investigated the incident. Following SED’s investigation which included a review of the third-party engineering firm’s report, on October 20, 2017, the SED issued a notice of probable violations against the Utility. The SED found two violations, for which the SED could issue a penalty of up to $8 million per violation. The Utility may incur material costs, including as a result of these investigations or any proceed ings that could be commenced in connection with this incident. Other Matters PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material. Accruals for contingencies re lated to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $39 million at September 30, 2017, and $45 million at December 31, 2016. These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. Disallowance of Plant Costs In May 2017, the Utility filed a settlement agreement with the CPUC related to the recovery of license renewal costs and cancelled project costs within its pending application to retire Diablo Canyon Power Plant. The settlement agreement allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the nine months ended September 30, 2017, the Utility incurred charges of $47 million related to settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs. In addition, the Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. Charges may be requir ed in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending related to its 2015 GT&S rate case. PG&E Corporation and the Utility would record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operating and maintenanc e expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Environmental Remediation Contingencies The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following: Balance at September 30, December 31, (in millions) 2017 2016 Topock natural gas compressor station (1) $ 310 $ 299 Hinkley natural gas compressor station (1) 147 135 Former manufactured gas plant sites owned by the Utility or third parties 306 285 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 124 131 Fossil fuel-fired generation facilities and sites 131 108 Total environmental remediation liability $ 1,018 $ 958 (1) See “Natural Gas Compressor Station Sites” below. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the federal Resource Conservation and Recovery Act and/or other state hazardous waste laws. The Utility has a comprehensive program in place d esigned to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors, on an ongoing basis, measures that may be necessar y to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, st ate, and local agencies. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and the Utility can reasonably estimate the loss or a range of possible losses. Key factors in estimated costs inclu de site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. The Utility’s environme ntal remediation liability at September 30, 2017 reflects its best estimate of probable future costs associated with its remediation plans. Future costs will depend on many factors, inclu ding the extent of work necessary to implement final remediation plans and the time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on the Utility’s future financial condition and cash flows. At September 30, 2017 , the Utility expected to recover $ 698 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation costs, such as the remediation costs associated with the Hinkley natural gas compressor site, fossil fuel-fired generation sites, and certain facilities formerly owned by the Utility, are not recoverable through rates. For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 F orm 10-K. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Needles, California and is referred to below as the “Topock site.” Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamina tion on the environment. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utilit

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2017
Subsequent Events [Text Block]	NOTE 10: SUBSEQUENT EVENTS Investigation of Recent 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 Ca lifornia Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures. The cause s of these fires are being investigated 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 way that they progressed. 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 in formation made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. It is uncertain when the investigations will be complete and whether Cal Fire will release preliminary findings before its investigation is complete. As of October 31, 2017, the Utility had submitted 20 electric incident reports to the CPUC involving the Utility’s facilities in and around the areas impacted by the Northern California wildfires. Electric utilities must report to the CPUC incidents that are attributable or allegedly attributable to utility-owned facilities and (1) result in fatality or personal injury rising to the level of in-patient hospitalization; or (2) are the subject of significant public attention or media coverage; or (3) involve damage to property of the Utility or others estimated to exceed $50,000. The information contained in these reports is factual and does not include a determination of the ca uses of the fires. The investigations into the causes of the fires are ongoing. The Utility estimates that it will incur costs in the range of $160 million to $200 million for service restoration and repairs to the Utility’s facilities (including an esti mated $60 million to $80 million in capital expenditures) 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 adversely affected if the Utility were unable to recover such costs. If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theory of inverse condemnation applies, the Utility could be liable for property damages, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. Courts have impose d liability under inverse condemnation policy to actions 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 benefitted from such undertaking and based on the assumption that utilities have the ability to recover these costs from their customers. In addition to such claims for property damage, interest and attorneys’ fees, as well as claims under other theories of liabilit y, the Utility could be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. The Utility also 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. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigations and uncertainty as to the causes of the fires and the extent and magnitude of damages. As of October 31, 2017, the Utility is aware of nine lawsuits, one of which seeks to be designated as a class action, that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties ' Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespas s, and private nuisance. They principally assert that PG&E Corporation 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 cause of the fires. The plaintiffs seek damages that include personal injury, property damage, evacuation costs, medical expenses, and other damages. PG&E Corporation and the Utility may be subject of additional lawsuits in connection with the Northern Califo rnia wildfires. The Utility has approximately $800 million in liability insurance for potential losses that may result from the Northern California wildfires. If the Utility were held liable for one or more fires and the Utility’s insurance were insuffi cient to cover that liability or the Utility were unable to recover costs in excess of insurance through regulatory mechanisms, either of which could take a number of years to resolve, PG&E Corporation’s and the Utility’s financial condition, results of op erations, liquidity and cash flows could be materially adversely affected. Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of $630 million for any potential future event .

New And Significant Accountin19

New And Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2017
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 a ny of these VIEs at September 30, 2017 , 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 te rms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2017 , it did not consolidate any of them.
Asset Retirement Obligations	Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large compon ent removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condens ed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.4 billion at September 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepare d in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.
Recently Adopted Accounting Guidance	Recently Adopted Accounting Guidance Share-Based Payment Accounting In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718) , which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classifi cation of awards as either equity or liabilities, and classification on the statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires, on a retrospective basis, that emp loyee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $ 35 million for the nine months ended Septem ber 30, 2016.

New And Significant Accountin20

New And Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2017
Components Of Net Periodic Benefit Cost	The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2017 and 2016 were as fo llows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 118 $ 113 $ 14 $ 13 Interest cost 178 179 20 19 Expected return on plan assets (193) (207) (24) (26) Amortization of prior service cost (1) 2 4 3 Amortization of net actuarial loss 6 6 1 1 Net periodic benefit cost 108 93 15 10 Regulatory account transfer (1) (23) (8) - - Total $ 85 $ 85 $ 15 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 354 $ 339 $ 44 $ 39 Interest cost 535 537 58 57 Expected return on plan assets (578) (621) (73) (80) Amortization of prior service cost (5) 6 12 11 Amortization of net actuarial loss 17 18 3 3 Net periodic benefit cost 323 279 44 30 Regulatory account transfer (1) (69) (25) - - Total $ 254 $ 254 $ 44 $ 30 (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 Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2017 Beginning balance $ (25) $ 17 $ (8) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) (1) 2 1 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $2 and $2, respectively) (3) (3) (6) Net current period other comprehensive gain (loss) - - - Ending balance $ (25) $ 17 $ (8) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) 2 1 3 Amortization of net actuarial loss (net of taxes of $3, and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (2) (7) Net current period other comprehensive gain (loss) - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) (3) 7 4 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 10 2 12 Regulatory account transfer (net of taxes of $5 and $6, respectively) (7) (8) (15) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) 4 6 10 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 11 2 13 Regulatory account transfer (net of taxes of $9 and $6, respectively) (15) (8) (23) Net current period other comprehensive gain (loss) - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)

Regulatory Assets, Liabilitie21

Regulatory Assets, Liabilities, And Balancing Accounts (Tables)	9 Months Ended
	Sep. 30, 2017
Long-Term Regulatory Assets	Long-term regulatory assets are comprised of the following: Asset Balance at (in millions) September 30, 2017 December 31, 2016 Deferred income taxes $ 4,373 $ 3,859 Pension benefits 2,487 2,429 Environmental compliance costs 779 778 Utility retained generation 331 364 Price risk management 77 92 Unamortized loss, net of gain, on reacquired debt 65 76 Other 434 353 Total long-term regulatory assets $ 8,546 $ 7,951
Long-Term Regulatory Liabilities	Long-term regulatory liabilities are comprised of the following: Liability Balance at (in millions) September 30, 2017 December 31, 2016 Cost of removal obligations $ 5,456 $ 5,060 Recoveries in excess of AROs 622 626 Public purpose programs 573 567 Other 614 552 Total long-term regulatory liabilities $ 7,265 $ 6,805
Regulatory Balancing Accounts Receivable	Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ - $ 132 Electric transmission 182 244 Utility generation - 48 Gas distribution and transmission 654 541 Energy procurement 135 132 Public purpose programs 116 106 Other 391 297 Total regulatory balancing accounts receivable $ 1,478 $ 1,500
Regulatory Balancing Accounts Payable	Payable Balance at (in millions) September 30, 2017 December 31, 2016 Electric distribution $ 197 $ - Utility generation 150 - Electric transmission 142 99 Gas distribution and transmission - 48 Energy procurement 131 13 Public purpose programs 426 264 Other 282 221 Total regulatory balancing accounts payable $ 1,328 $ 645

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2017
Disclosure Debt [Abstract]
Schedule Of Debt	The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2017 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2022 $ 300 (1) $ - $ - $ 300 Utility April 2022 3,000 (2) 50 369 2,581 Total revolving credit facilities $ 3,300 $ 50 $ 369 $ 2,881 (1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans.

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2017
Changes In Equity	PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2017 were as follo ws: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2016 $ 18,192 $ 18,395 Comprehensive income 1,543 1,492 Equity contributions - 405 Common stock issued 361 - Share-based compensation 2 - Common stock dividends declared (802) (784) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2017 $ 19,286 $ 19,498

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2017
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted	Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2017 2016 2017 2016 Income available for common shareholders $ 550 $ 388 $ 1,532 $ 701 Weighted average common shares outstanding, basic 513 501 511 497 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 3 3 Weighted average common shares outstanding, diluted 516 503 514 500 Total earnings per common share, diluted $ 1.07 $ 0.77 $ 2.98 $ 1.40

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Sep. 30, 2017
Volumes Of Outstanding Derivative Contracts	The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at September 30, December 31, Underlying Product Instruments 2017 2016 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 300,594,593 323,301,331 Options 79,640,435 96,602,785 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,505,504 3,287,397 Congestion Revenue Rights (3) 249,876,873 278,143,281 (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 Derivative Instruments in Statement of Financial Position, Fair Value	At September 30, 2017 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 47 $ (7) $ 9 $ 49 Other noncurrent assets – other 121 (3) - 118 Current liabilities – other (54) 7 11 (36) Noncurrent liabilities – other (81) 3 7 (71) Total commodity risk $ 33 $ - $ 27 $ 60 At December 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95
Gains And Losses On Derivative Instruments	Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended Nine Months Ended September 30, September 30, (in millions) 2017 2016 2017 2016 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (6) $ (29) $ (58) $ 30 Realized loss - cost of electricity (2) (4) (7) (8) (48) Realized loss - cost of natural gas (2) (1) (9) (5) (15) Net commodity risk $ (11) $ (45) $ (71) $ (33) (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 o f 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 trigger ed was as follows: Balance at September 30, December 31, (in millions) 2017 2016 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (16) $ (24) Related derivatives in an asset position 3 19 Collateral posting in the normal course of business related to these derivatives 11 4 Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (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)	9 Months Ended
	Sep. 30, 2017
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 Ut ility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At September 30, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 120 $ - $ - $ - $ 120 Nuclear decommissioning trusts Short-term investments 23 - - - 23 Global equity securities 1,875 - - - 1,875 Fixed-income securities 697 569 - - 1,266 Assets measured at NAV - - - - 16 Total nuclear decommissioning trusts (2) 2,595 569 - - 3,180 Price risk management instruments (Note 7) Electricity 4 7 153 (1) 163 Gas - 4 - - 4 Total price risk management instruments 4 11 153 (1) 167 Rabbi trusts Fixed-income securities - 64 - - 64 Life insurance contracts - 71 - - 71 Total rabbi trusts - 135 - - 135 Long-term disability trust Short-term investments 5 - - - 5 Assets measured at NAV - - - - 148 Total long-term disability trust 5 - - - 153 TOTAL ASSETS $ 2,724 $ 715 $ 153 $ (1) $ 3,755 Liabilities: Price risk management instruments (Note 7) Electricity $ 11 $ 17 $ 105 $ (28) $ 105 Gas - 2 - - 2 TOTAL LIABILITIES $ 11 $ 19 $ 105 $ (28) $ 107 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 387 million, primarily related to deferred taxes on appreciat ion of investment value. Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management instruments 30 29 181 (18) 222 Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.
Level 3 Measurements And Sensitivity Analysis	Fair Value at (in millions) At September 30, 2017 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 153 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 70 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Po wer purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 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 and nine months ended September 30, 2017 and 2016 : Price Risk M anagement Instruments (in millions) 2017 2016 Asset (liability) balance as of July 1 $ 48 $ 66 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) - (10) Asset (liability) balance as of September 30 $ 48 $ 56 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of January 1 $ 55 $ 89 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (7) (33) Asset (liability) balance as of September 30 $ 48 $ 56 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.
Carrying Amount And Fair Value Of Financial Instruments	The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values): At September 30, 2017 At December 31, 2016 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 349 $ 352 $ 348 $ 352 Utility 16,211 18,672 15,813 17,790
Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments	The following table provides a summary of available-for-sale investments: Total Total Amortized Unrealized Unrealized Total Fair (in millions) Cost Gains Losses Value As of September 30, 2017 Nuclear decommissioning trusts Short-term investments $ 23 $ - $ - $ 23 Global equity securities 540 1,353 (2) 1,891 Fixed-income securities 1,216 56 (6) 1,266 Total (1) $ 1,779 $ 1,409 $ (8) $ 3,180 As of December 31, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 (1) Represents amounts before deducting $ 387 million and $333 million at September 30, 2017 and December 31, 2016 , respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule Of Maturities On Debt Instruments	The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) September 30, 2017 Less than 1 year $ 27 1–5 years 403 5–10 years 340 More than 10 years 496 Total maturities of fixed-income securities $ 1,266
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 Nine Months Ended September 30, September 30, 2017 2016 2017 2016 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 249 $ 257 $ 1,043 $ 1,019 Gross realized gains on securities held as available-for-sale 8 6 50 15 Gross realized losses on securities held as available-for-sale - (14) (8) (17)

Commitments And Contingencies (

Commitments And Contingencies (Tables)	9 Months Ended
	Sep. 30, 2017
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 Consolidat ed 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) (338) Balance at September 30, 2017 $ 702 (1) As of September 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $515 million of which $398 million has been paid by the Utility.
Schedule Of Environmental Remediation Liability	Balance at September 30, December 31, (in millions) 2017 2016 Topock natural gas compressor station (1) $ 310 $ 299 Hinkley natural gas compressor station (1) 147 135 Former manufactured gas plant sites owned by the Utility or third parties 306 285 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 124 131 Fossil fuel-fired generation facilities and sites 131 108 Total environmental remediation liability $ 1,018 $ 958 (1) See “Natural Gas Compressor Station Sites” below.
Insurance Receivable [Text Block]	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 (131) Balance at September 30, 2017 $ 741

Organization And Basis of Pre28

Organization And Basis of Presentation (Narrative) (Details) - Nothern California Wild Fire [Member]	Sep. 30, 2017
Organization And Basis Of Presentation [Line Items]
Number Of Acres Burned	245,000
Number Of Deaths	43
Number Of Houses Destroyed	8,900
Number Of Fires	21

New And Significant Accountin29

New And Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Total nuclear decommissioning asset retirement obligation	$ 3,400,000		$ 3,500,000
Reduction to ARO	66,000
Decrease to cash flow from financing activities	(101,000)	$ (17,000)
2015 NDCTP Adopted Amounts	3,500,000
2015 NDCTP Requested Amounts	4,800,000
Diablo Canyon [Member]
Public Utility, Property, Plant and Equipment [Line Items]
2015 NDCTP Adopted Amounts	2,400,000
2015 NDCTP Requested Amounts	$ 3,800,000
Percentage Of Decommissioning Cost Estimate Approved	64.00%
Humboldt Bay Unit [Member]
Public Utility, Property, Plant and Equipment [Line Items]
2015 NDCTP Adopted Amounts	$ 1,100,000
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Decrease to cash flow from financing activities	$ (91,000)	(7,000)
New Accounting Pronouncement [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Decrease to cash flow from financing activities		$ 35,000

New And Significant Accountin30

New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 118		$ 113		$ 354	$ 339
Interest cost	178		179		535	537
Expected return on plan assets	(193)		(207)		(578)	(621)
Amortization of prior service cost	(1)		2		(5)	6
Amortization of net actuarial loss	6		6		17	18
Net periodic benefit cost	108		93		323	279
Regulatory account transfer	(23)	[1]	(8)	[1]	(69)	(25)
Total	85		85		254	254
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	14		13		44	39
Interest cost	20		19		58	57
Expected return on plan assets	(24)		(26)		(73)	(80)
Amortization of prior service cost	4		3		12	11
Amortization of net actuarial loss	1		1		3	3
Net periodic benefit cost	15		10		44	30
Regulatory account transfer	0	[1]	0	[1]	0	0
Total	$ 15		$ 10		$ 44	$ 30
[1]	The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in futures rates.

New And Significant Accountin31

New And Significant Accounting Policies (Reclassifications Out Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	$ (8)		$ (7)		$ (9)	$ (7)
Net current period other comprehensive income (loss)	0		0		1	0
Ending balance	(8)		(7)		(8)	(7)
Net actuarial loss tax	0		0		0	0
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	1	[1]	3	[1]	4	10
Amortization of net actuarial loss	5	[1]	4	[1]	12	13
Regulatory account transfer	(6)	[1]	(7)	[1]	(15)	(23)
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	(25)		(23)		(25)	(23)
Amortization of prior service cost	(1)		2		(5)	6
Amortization of net actuarial loss	6		6		17	18
Net current period other comprehensive income (loss)	0		0		0	0
Ending balance	(25)		(23)		(25)	(23)
Pension Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	(1)	[1]	2	[1]	(3)	4
Amortization of net actuarial loss	4	[1]	3	[1]	10	11
Regulatory account transfer	(3)	[1]	(5)	[1]	(7)	(15)
Amortization of prior service cost tax	0		0		2	2
Net actuarial loss tax	2		3		7	7
Regulatory account transfer tax	2		3		5	9
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	17		16		16	16
Amortization of prior service cost	4		3		12	11
Amortization of net actuarial loss	1		1		3	3
Net current period other comprehensive income (loss)	0		0		1	0
Ending balance	17		16		17	16
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	2	[1]	1	[1]	7	6
Amortization of net actuarial loss	1	[1]	1	[1]	2	2
Regulatory account transfer	(3)	[1]	(2)	[1]	(8)	(8)
Amortization of prior service cost tax	2		2		5	5
Net actuarial loss tax	0		0		1	1
Regulatory account transfer tax	$ 2		$ 2		$ 6	$ 6
[1]	These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the Pension and Other Postretirement Benefits table above for additional details.)

Regulatory Assets, Liabilitie32

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 8,546	$ 7,951
Current regulatory assets	573	423
Pension Benefits [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,487	2,429
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	4,373	3,859
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	331	364
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	779	778
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	77	92
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	65	76
Other Long Term Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	434	$ 353
CEMA [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	189
Current regulatory assets	$ 392
Percent Recoverable	100.00%

Regulatory Assets, Liabilitie33

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 7,265	$ 6,805
Cost Of Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	5,456	5,060
Recoveries In Excess Of AROs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	622	626
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	573	567
Other Long Term Regulatory Assets (Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 614	$ 552

Regulatory Assets, Liabilitie34

Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,478	$ 1,500
Regulatory Balancing Accounts Receivable [Member] | Electric Distribution [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	132
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	48
Regulatory Balancing Accounts Receivable [Member] | Gas Distribution and Transmission [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	654	541
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	135	132
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	116	106
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	391	297
Regulatory Balancing Accounts Receivable [Member] | Electric Transmission [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	182	244
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1,328	645
Regulatory Balancing Accounts Payable [Member] | Electric Distribution [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	197	0
Regulatory Balancing Accounts Payable [Member] | Utility Generation [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	150	0
Regulatory Balancing Accounts Payable [Member] | Gas Distribution and Transmission [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	0	48
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	131	13
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	426	264
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	282	221
Regulatory Balancing Accounts Payable [Member] | Electric Transmission [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 142	$ 99

Debt (Narrative) (Details)

Debt (Narrative) (Details) - Utility [Member] - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Jun. 30, 2017
Debt [Line Items]
Short term borrowing outstanding	$ 250
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, face amount	614
Pollution Control Bonds Series 2009 A-B [Member]
Debt [Line Items]
Debt instrument, face amount	149
Pollution Control Bonds Series 2004 A-D [Member]
Debt [Line Items]
Repayments Of Pollution Control Bond	345
Pollution Control Bonds Series 2008 F, G, and 2010 E [Member]
Debt [Line Items]
Debt instrument, face amount	$ 145
Pollution Control Bonds Series 2008 G [Member]
Debt [Line Items]
Debt instrument, interest rate	1.05%
Pollution Control Bonds Series Two Thousand Eight F And Two Thousand Ten E [Member]
Debt [Line Items]
Debt instrument, interest rate	1.75%
Senior Notes, 4.00%, Due 2046 [Member]
Debt [Line Items]
Debt instrument, interest rate	4.00%
Senior Notes	$ 200
Senior Notes, 3.30%, Due 2027 [Member]
Debt [Line Items]
Debt instrument, interest rate	3.30%
Senior Notes	$ 400
Minimum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.88%
Minimum [Member] | Pollution Control Bonds Series 2009 A-B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.89%
Maximum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.95%
Maximum [Member] | Pollution Control Bonds Series 2009 A-B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.89%
Floating Rate Senior Notes [Member]
Debt [Line Items]
Floating rate unsecured term loan, matured 2017		$ 250

Debt (Schedule Of Line Of Credi

Debt (Schedule Of Line Of Credit) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement	Apr. 27, 2022
Letters of Credit Sublimit	$ 500
Utility [Member]
Debt [Line Items]
Facility limit	3,000	[1]
Letters Of Credit Outstanding Amount	50
Commercial Paper	369
Facility Availability	2,581
Swingline Loans Sublimit	$ 75
P G E Corporation [Member]
Debt [Line Items]
Expiration date for credit agreement	Apr. 27, 2022
Facility limit	$ 300	[2]
Letters Of Credit Outstanding Amount	0
Commercial Paper	0
Facility Availability	300
Letters of Credit Sublimit	50
Swingline Loans Sublimit	$ 100
Swingline Loan Repay Term	7 days
Credit Facilities [Member]
Debt [Line Items]
Facility limit	$ 3,300
Letters Of Credit Outstanding Amount	50
Commercial Paper	369
Facility Availability	$ 2,881
[1]	Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.
[2]	Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

Equity (Narrative) (Detail)

Equity (Narrative) (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Common Stock Value	$ 12,560,000	$ 12,198,000
Pacific Gas And Electric Company [Member]
Common Stock Value	$ 1,322,000	$ 1,322,000
Equity Contract [Member]
Equity Distribution Agreement, shares issued	400,000
Remaining equity distribution agreement amount	$ 246,000
Fees and commissions	200
Stock Issued During Period Value Under Equity Distribution Agreement	28,000
Equity Distribution Agreement Total Contract Value	$ 275,000
401K Plan, DRSPP, and Shared Based Compensation Plans [Member]
Stock issued during period for stock options exercised and under 401(K) plan and DRSPP, shares	6,400,000
Stock Issued During Period Value Stock Options Exercised	$ 316,000

Equity (Changes In Equity) (Det

Equity (Changes In Equity) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Balance at December 31, 2016			$ 17,940
Balance at December 31, 2016			18,192
Comprehensive Income Net Of Tax	$ 553	$ 391	1,543	$ 711
Common stock issued			361
Share-based compensation			(2)
Common stock dividends declared			(802)
Preferred stock dividend requirement of subsidiary	(3)	(3)	(10)	(10)
Balance at September 30, 2017	19,286		19,286
Balance at September 30, 2017	19,034		19,034
Pacific Gas And Electric Company [Member]
Balance at December 31, 2016			18,395
Comprehensive Income Net Of Tax	513	389	1,492	707
Common stock issued			0
Share-based compensation			0
Common stock dividends declared			(784)
Preferred stock dividend requirement	(3)	$ (3)	(10)	(10)
Equity contributions			405	$ 740
Balance at September 30, 2017	$ 19,498		$ 19,498

Earnings Per Share (Reconciliat

Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income available for common shareholders	$ 550	$ 388	$ 1,532	$ 701
Weighted average common shares outstanding, basic	513	501	511	497
Employee share-based compensation	3	2	3	3
Weighted average common shares outstanding, diluted	516	503	514	500
Total earnings per common share, diluted	$ 1.07	$ 0.77	$ 2.98	$ 1.40

Derivatives (Volumes Of Outstan

Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details)		Sep. 30, 2017	Dec. 31, 2016
Forwards And Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[1],[2]	300,594,593	323,301,331
Forwards And Swaps [Member] | Electricity [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held		3,505,504	3,287,397
Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[1],[2]	79,640,435	96,602,785
Congestion Revenue Rights [Member] | Electricity [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[3]	249,876,873	278,143,281
[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.

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ 47	$ 91
Cash Collateral	9	1
Total Derivative Balance	49	82
Netting	(7)	(10)
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	121	149
Cash Collateral	0	0
Total Derivative Balance	118	140
Netting	(3)	(9)
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(54)	(48)
Cash Collateral	11	0
Total Derivative Balance	(36)	(38)
Netting	7	10
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(81)	(101)
Cash Collateral	7	3
Total Derivative Balance	(71)	(89)
Netting	3	9
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	33	91
Netting [Member]
Derivatives And Hedging Activities [Line Items]
Netting	0	0
Cash Collateral [Member]
Derivatives And Hedging Activities [Line Items]
Cash Collateral	27	4
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balance	$ 60	$ 95

Derivatives (Gains And Losses O

Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Net unrealized loss - regulatory assets and liabilities	$ (6)	[1]	$ (29)	$ (58)	$ 30
Realized loss - cost of electricity	(4)	[2]	(7)	(8)	(48)
Realized loss - cost of natural gas	(1)		(9)	(5)	(15)
Total commodity risk	$ (11)		$ (45)	$ (71)	$ (33)
[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.

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		Sep. 30, 2017	Dec. 31, 2016
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized		$ (16)	$ (24)
Related derivatives in an asset position		3	19
Collateral posting in the normal course of business related to these derivatives		11	4
Net position of derivative contracts/additional collateral posting requirements	[1]	$ (2)	$ (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 (Assets

Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions	Sep. 30, 2017		Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	$ 120		$ 105
Total assets	3,755		3,575
Electricity	105		126
Natural Gas	2		1
Total liabilities	107		127
Amount primarily related to deferred taxes on appreciation of investment value	387	[1]	333	[2]
Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	23		9
Total assets	3,180	[1]	2,939	[2]
Fixed-income securities	1,266		1,192
Global equity securities	1,875		1,724
Financial Instruments Measured At NAV	16		14
Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	167		222
Electricity	163		211
Natural Gas	4		11
Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	135		131
Fixed-income securities	64		61
Life insurance contracts	71		70
Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	5		8
Total assets	153		178
Financial Instruments Measured At NAV	148		170
Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	120		105
Total assets	2,724		2,541
Total liabilities	11		9
Fair Value Measurements, Level 1 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	23		9
Total assets	2,595	[1]	2,398	[2]
Fixed-income securities	697		665
Global equity securities	1,875		1,724
Financial Instruments Measured At NAV	0		0
Fair Value Measurements, Level 1 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	4		30
Electricity	4		30
Natural Gas	0		0
Electricity	11		9
Natural Gas	0		0
Fair Value Measurements, Level 1 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	0		0
Fixed-income securities	0		0
Life insurance contracts	0		0
Fair Value Measurements, Level 1 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	5		8
Total assets	5		8
Financial Instruments Measured At NAV	0		0
Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	715		687
Total liabilities	19		14
Fair Value Measurements, Level 2 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	569	[1]	527	[2]
Fixed-income securities	569		527
Global equity securities	0		0
Financial Instruments Measured At NAV	0		0
Fair Value Measurements, Level 2 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	11		29
Electricity	7		18
Natural Gas	4		11
Electricity	17		12
Natural Gas	2		2
Fair Value Measurements, Level 2 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	135		131
Fixed-income securities	64		61
Life insurance contracts	71		70
Fair Value Measurements, Level 2 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	0		0
Financial Instruments Measured At NAV	0		0
Fair Value Measurements, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	153		181
Total liabilities	105		126
Fair Value Measurements, Level 3 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	0	[1]	0	[2]
Fixed-income securities	0		0
Global equity securities	0		0
Financial Instruments Measured At NAV	0		0
Fair Value Measurements, Level 3 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	153		181
Electricity	153		181
Natural Gas	0		0
Electricity	105		126
Natural Gas	0		0
Fair Value Measurements, Level 3 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	0		0
Fixed-income securities	0		0
Life insurance contracts	0		0
Fair Value Measurements, Level 3 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0
Total assets	0		0
Financial Instruments Measured At NAV	0		0
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0	[3]
Total assets	(1)		(18)	[3]
Total liabilities	(28)		(22)	[3]
Netting [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0	[3]
Total assets	0	[1]	0	[2],[3]
Fixed-income securities	0		0	[3]
Global equity securities	0		0	[3]
Financial Instruments Measured At NAV	0		0	[3]
Netting [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	(1)		(18)	[3]
Electricity	(1)		(18)	[3]
Natural Gas	0		0	[3]
Electricity	(28)		(21)	[3]
Natural Gas	0		(1)	[3]
Netting [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	0		0	[3]
Fixed-income securities	0		0	[3]
Life insurance contracts	0		0	[3]
Netting [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term investments	0		0	[3]
Total assets	0		0	[3]
Financial Instruments Measured At NAV	$ 0		$ 0	[3]
[1]	Represents amount before deducting $387 million, primarily related to deferred taxes on appreciation of investment value.
[2]	Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.
[3]	Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Details) $ in Millions		3 Months Ended	12 Months Ended
		Sep. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 3,755	$ 3,575
Liabilities, Fair Value		107	127
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		153	181
Liabilities, Fair Value		$ 35	$ 35
Fair value measurement Valuation technique		Market approach	Market approach
Fair value measurement Unobservable Input		CRR auction prices	CRR auction prices
Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 0	$ 0
Liabilities, Fair Value		$ 70	$ 91
Fair value measurement Valuation technique		Discounted cash flow	Discounted cash flow
Fair value measurement Unobservable Input		Forward prices	Forward prices
Minimum [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	(11.88)	(11.88)
Minimum [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	18.81	18.07
Maximum [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	6.93	6.93
Maximum [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	38.8	38.8
[1]	Represents price per megawatt-hour

Fair Value Measurements (Leve46

Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value Measurements, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2017	Sep. 30, 2016
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning asset (liability) balance	$ 48		$ 66		$ 55	$ 89
Included in regulatory assets and liabilities or balancing accounts	0	[1]	(10)	[1]	(7)	(33)
Ending asset (liability) balance	$ 48		$ 56		$ 48	$ 56
[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.

Fair Value Measurements (Carryi

Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Pacific Gas And Electric Company [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 18,672	$ 17,790
Pacific Gas And Electric Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	16,211	15,813
P G E Corporation [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	352	352
P G E Corporation [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 349	$ 348

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions		9 Months Ended		12 Months Ended
		Sep. 30, 2017		Dec. 31, 2016
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	[1]	$ 1,779		$ 1,749
Total Unrealized Gains	[1]	1,409		1,205
Total Unrealized Losses	[1]	(8)		(15)
Total Fair Value	[1]	3,180		2,939
Amount primarily related to deferred taxes on appreciation of investment value		387	[2]	333	[3]
Short-term investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		23		9
Total Unrealized Gains		0		0
Total Unrealized Losses		0		0
Total Fair Value		23		9
Other Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,216		1,156
Total Unrealized Gains		56		48
Total Unrealized Losses		(6)		(12)
Total Fair Value		1,266		1,192
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		540		584
Total Unrealized Gains		1,353		1,157
Total Unrealized Losses		(2)		(3)
Total Fair Value		$ 1,891		$ 1,738
[1]	Represents amounts before deducting $387 million and $333 million at September 30, 2017 and December 31, 2016, respectively, primarily related to deferred taxes on appreciation of investment value.
[2]	Represents amount before deducting $387 million, primarily related to deferred taxes on appreciation of investment value.
[3]	Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurements (Sche49

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions	Sep. 30, 2017USD ($)
Less than 1 year	$ 27
1-5 years	403
5-10 years	340
More than 10 years	496
Total maturities of fixed-income securities	$ 1,266

Fair Value Measurements (Sche50

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 249	$ 257	$ 1,043	$ 1,019
Gross realized gains on sales of securities held as available-for-sale	8	6	50	15
Gross realized losses on sales of securities held as available-for-sale	$ 0	$ 14	$ 8	$ 17

Commitments And Contingencies51

Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions	Dec. 31, 2016USD ($)
Long-term Purchase Commitment [Line Items]
Total	$ 47,000

Commitments And Contingencies52

Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)		Jun. 30, 2017USD ($)	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Unrecognized Tax Benefits	$ 70,000	$ 70,000
Disputed Claims Liability Balance				$ 236,000
Release of Escrow to California Power Exchange		0	$ (66,000)
Charge for disallowed capital		$ 47,000	517,000
Butte Fire [Member]
Loss Contingencies [Line Items]
Number of plaintiffs	3,770	3,770
Utility liability insurance for damages		$ 922,000
Number of Damaged Structures	44	44
Loss Contingency Range Of Possible Loss Minimum	$ 1,100,000	$ 1,100,000				$ 750,000
Number of complaints filed against utility	77	77
Fire Fighting Costs Recovery Requested By Cal Fire		$ 87,000
Number Of Acres Burned	70,868	70,868
Number Of Fatalities Caused By Fire	2	2
Number Of Homes Burned By Fire	549	549
Number Of Outbuildings Burned By Fire	368	368
Number Of Commerical Properties Burned By Fire	4	4
Number Of Households Represented In Court	2,080	2,080
Number Of Master Complaints	2	2
Cumulative Legal Expenses	$ 18,000	$ 45,000
Vegetation Management Contractors	2	2
Number Of Preference Households	1	1
Citation For Failing To Maintain Electric Line		$ 8,300
Office Of Emergency Services Claim		$ 190,000
Number of Citations		2
Probable Insurance Recoveries		$ 922,000
Settlement Agreements Entered By Utility		515,000
Settlement Agreement Paid By The Utility	$ 398,000
Claim Against The Utility		$ 85,000
NumberOf Preference Households Settled	6	6
Number Of Preference Plaintiffs	1	1
Insurance Recoveries	$ 21,000	$ 53,000
Number Of Households With Inestimable Losses	1,000	1,000
Potential Safety Citations [Member]
Loss Contingencies [Line Items]
SED Maximum Statutory Penalty Per Violaiton		$ 50
SED Administrative Limit Per Citation		8,000
Valero Refinery Outage [Member]
Loss Contingencies [Line Items]
Loss Contingency Range Of Possible Loss Minimum	$ 114,000	114,000
Initial Claim		$ 75,000
Ghost Ship Fire [Member]
Loss Contingencies [Line Items]
Number Of Fatalities Caused By Fire	36	36
Lawsuits Filed Against Property Owner	34	34
Yuba City [Member]
Loss Contingencies [Line Items]
Number of People Injured	2	2
Number Of Violations	2	2
Minimum [Member] | Potential Safety Citations [Member]
Loss Contingencies [Line Items]
SED fines for self-reported violations		$ 50
Maximum [Member] | Potential Safety Citations [Member]
Loss Contingencies [Line Items]
SED fines for self-reported violations		16,800
Maximum [Member] | Yuba City [Member]
Loss Contingencies [Line Items]
SED recommended penalty		8,000
Ex Parte Communications [Member]
Loss Contingencies [Line Items]
Payment To State General Fund		12,000
Payment To City Of San Bruno		6,000
Payment To City Of San Carlos		6,000
Revenue Requirement Reduction In Next GRC Cycle		10,000
2018 GT&S Revenue Requirement Reduction		31,750
2019 GT&S Revenue Requirement Reduction		31,750
Initial Payment To California General Fund		$ 1,000
Shareholder Derivative Lawsuits [Member]
Loss Contingencies [Line Items]
Number Of Unconsolidated Cases In Derivative Lawsuits	3	3
Estimated Cost Of Corporate Governance Therapeutics		$ 32,000
Payment Of Individual Defendant Costs		18,300
Number Of Years Of Corporate Governance Therapeutics	5 years
Number Of Years Of Gas Operations Therapeutics	3 years
Insurance Recoveries		65,000
Loss Accrual [Member] | Butte Fire [Member]
Loss Contingencies [Line Items]
Accrued Losses		350,000		750,000
Loss Contingency Accrual At Carrying Value	$ 702,000	702,000		690,000			$ 0
Payments For Claims		338,000		60,000	[1]
Insurance Receivable [Member] | Butte Fire [Member]
Loss Contingencies [Line Items]
Insurance Reimbursement From Contractors		131,000		50,000
Insurance Settlements Receivable	741,000	741,000		575,000			$ 0
Accrued Insurance Recoveries	$ 297,000	297,000		625,000
Cumulative Legal Expenses [Member] | Butte Fire [Member]
Loss Contingencies [Line Items]
Cumulative Legal Expenses		$ 72,000
Disallowance Of Plant Costs [Member]
Loss Contingencies [Line Items]
Percentage of Recoverable Costs Prior To Specific Date	100.00%	100.00%
Percentage of Recoverable Costs After Specific Date	25.00%	25.00%
Settlement Agreement Length	8 years
License Renewal Project Cost		$ 53,000
Recoverable Costs From Customers		18,600
Cancelled Capital Project Costs		24,000
Disallowed License Renewal Costs		23,000
Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Release of Escrow to California Power Exchange		0	(66,000)
Charge for disallowed capital		47,000	$ 517,000
Utility [Member]
Loss Contingencies [Line Items]
Accrued legal liabilities	$ 39,000	$ 39,000		$ 45,000
[1]	As of September 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $515 of which $398 million has been paid by the Utility.

Commitments And Contingencies53

Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions	3 Months Ended
	Sep. 30, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Maximum Aggregate Annual Retrospective Premium Obligation	$ 58
EMANI Policy Limit	$ 200

Commitments And Contingencies54

Commitments And Contingencies (Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions		Sep. 30, 2017	Dec. 31, 2016
Topock natural gas compressor station	[1]	$ 310	$ 299
Hinkley natural gas compressor station	[1]	147	135
Former manufactured gas plant sites owned by the Utility or third parties		306	285
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		124	131
Fossil fuel-fired generation facilities and sites		131	108
Total environmental remediation liability		$ 1,018	$ 958
[1]	See "Natural Gas Compressor Station Sites" below.

Commitments And Contingencies55

Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions	Sep. 30, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 698
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute	$ 1,000

Subsequent Events (Details)

Subsequent Events (Details) - Nothern California Wild Fire [Member] $ in Thousands	9 Months Ended
	Sep. 30, 2017USD ($)
Subsequent Event [Line Items]
Number Of Fires	21
Number Of Acres Burned	245,000
Number Of Deaths	43
Number Of Houses Destroyed	8,900
Subsequent Event [Member]
Subsequent Event [Line Items]
Liability Insurance Coverage	$ 800,000
Number Of Fires	21
Number Of Electric Incident Reports	20
Dollar Amount Requiring Electric Incident Report	$ 50
Lower End of Range to Repair Utility Facilities	160,000
Higher End of Range to Repair Utility Facilities	$ 200,000
Number Of Acres Burned	254,000
Number Of Deaths	43
Number Of Houses Destroyed	8,900
Number Of Class Action Lawsuits	1
Estimated Maximum Capital Expenditures	$ 80,000
Estimated Minimum Capital Expenditures	60,000
Reinstated Liability Insurance	$ 550,000
Number Of Lawsuits	9