Pacific Gas & Electric (PCG+A) 10-K 10 Feb 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Jan. 27, 2015	Jun. 30, 2014	Feb. 03, 2014
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	PG&E CORP
Entity Central Index Key	1004980
Current Fiscal Year End Date	-19
Document Fiscal Year Focus	2014
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$22,602
Entity Common Stock, Shares Outstanding		476,399,910
Pacific Gas And Electric Company [Member]
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Entity Filer Category	Non-accelerated Filer
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	75488
Current Fiscal Year End Date	-19
Document Fiscal Year Focus	2014
Entity Current Reporting Status	Yes
Trading Symbol	PCG
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Common Stock, Shares Outstanding				264,374,809

Consolidated_Statements_Of_Inc

Consolidated Statements Of Income (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues
Electric	$13,658	$12,494	$12,019
Natural gas	3,432	3,104	3,021
Total operating revenues	17,090	15,598	15,040
Operating Expenses
Cost of electricity	5,615	5,016	4,162
Cost of natural gas	954	968	861
Operating and maintenance	5,638	5,775	6,052
Depreciation, amortization, and decommissioning	2,433	2,077	2,272
Total operating expenses	14,640	13,836	13,347
Operating Income	2,450	1,762	1,693
Interest income	9	9	7
Interest expense	-734	-715	-703
Other income, net	70	40	70
Income Before Income Taxes	1,795	1,096	1,067
Income tax benefit	345	268	237
Net Income	1,450	828	830
Preferred stock dividend requirement of subsidiary	14	14	14
Preferred stock dividend requirement	14	14	14
Income Available for Common Shareholders	1,436	814	816
Weighted Average Common Shares Outstanding, Basic	468	444	424
Weighted Average Common Shares Outstanding, Diluted	470	445	425
Net earnings per common share, basic	$3.07	$1.83	$1.92
Net Earnings Per Common Share, Diluted	$3.06	$1.83	$1.92
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	13,656	12,489	12,014
Natural gas	3,432	3,104	3,021
Total operating revenues	17,088	15,593	15,035
Operating Expenses
Cost of electricity	5,615	5,016	4,162
Cost of natural gas	954	968	861
Operating and maintenance	5,635	5,742	6,045
Depreciation, amortization, and decommissioning	2,432	2,077	2,272
Total operating expenses	14,636	13,803	13,340
Operating Income	2,452	1,790	1,695
Interest income	8	8	6
Interest expense	-720	-690	-680
Other income, net	77	84	88
Income Before Income Taxes	1,817	1,192	1,109
Income tax benefit	384	326	298
Net Income	1,433	866	811
Preferred stock dividend requirement	14	14	14
Income Available for Common Shareholders	$1,419	$852	$797

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$1,450	$828	$830
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $10, $80 and $72 and related to the Utility of $6, $75, and $73, at respective dates)	-14	113	108
Net change in investments (net of taxes $17, $26, and $3, at respective dates)	-25	38	4
Total other comprehensive income (loss)	-39	151	112
Comprehensive Income	1,411	979	942
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income Net Of Tax Attributable To Noncontrolling Interest	1,397	965	928
Pacific Gas And Electric Company [Member]
Net income	1,433	866	811
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $10, $80 and $72 and related to the Utility of $6, $75, and $73, at respective dates)	-8	106	109
Total other comprehensive income (loss)	-8	106	109
Comprehensive Income	$1,425	$972	$920

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension and other postretirement benefit plans obligations tax	$10	$80	$72
Change in investments tax	17	26	3
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$6	$75	$73

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current Assets
Cash and cash equivalents	$151	$296
Restricted cash	298	301
Accounts receivable
Customers (net of allowance for doubtful accounts of $66 and $80 at December 31, 2014 and 2013, respectively)	960	1,091
Accrued unbilled revenue	776	766
Regulatory balancing accounts	2,266	1,124
Other	377	312
Regulatory assets	444	448
Inventories
Gas stored underground and fuel oil	172	137
Materials and supplies	304	317
Income taxes receivable	198	574
Other	443	611
Total current assets	6,389	5,977
Property, Plant, and Equipment
Electric	45,162	42,881
Gas	15,678	14,379
Construction work in progress	2,220	1,834
Other	2	2
Total property, plant, and equipment	63,062	59,096
Accumulated depreciation	-19,121	-17,844
Net property, plant, and equipment	43,941	41,252
Other Noncurrent Assets
Regulatory assets	6,322	4,913
Nuclear decommissioning trusts	2,421	2,342
Income taxes receivable	91	85
Other	963	1,036
Total other noncurrent assets	9,797	8,376
TOTAL ASSETS	60,127	55,605
Current Liabilities
Short-term borrowings	633	1,174
Long-term debt, classified as current	0	889
Accounts payable
Trade creditors	1,244	1,293
Regulatory balancing accounts	1,090	1,008
Other	476	471
Disputed claims and customer refunds	434	154
Interest payable	197	892
Other	1,846	1,612
Total current liabilities	5,920	7,493
Noncurrent Liabilities
Long-term debt	15,050	12,717
Regulatory liabilities	6,290	5,660
Pension and other postretirement benefits	2,561	1,601
Asset retirement obligations	3,575	3,539
Deferred income taxes	8,513	7,823
Other	2,218	2,178
Total noncurrent liabilities	38,207	33,518
Commitments and Contingencies (Note 14)
Shareholders' Equity
Common stock	10,421	9,550
Reinvested earnings	5,316	4,742
Accumulated other comprehensive income (loss)	11	50
Total shareholders' equity	15,748	14,342
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	16,000	14,594
TOTAL LIABILITIES AND EQUITY	60,127	55,605
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	55	65
Restricted cash	298	301
Accounts receivable
Customers (net of allowance for doubtful accounts of $66 and $80 at December 31, 2014 and 2013, respectively)	960	1,091
Accrued unbilled revenue	776	766
Regulatory balancing accounts	2,266	1,124
Other	375	313
Regulatory assets	444	448
Inventories
Gas stored underground and fuel oil	172	137
Materials and supplies	304	317
Income taxes receivable	168	563
Other	409	523
Total current assets	6,227	5,648
Property, Plant, and Equipment
Electric	45,162	42,881
Gas	15,678	14,379
Construction work in progress	2,220	1,834
Total property, plant, and equipment	63,060	59,094
Accumulated depreciation	-19,120	-17,843
Net property, plant, and equipment	43,940	41,251
Other Noncurrent Assets
Regulatory assets	6,322	4,913
Nuclear decommissioning trusts	2,421	2,342
Income taxes receivable	91	81
Other	864	814
Total other noncurrent assets	9,698	8,150
TOTAL ASSETS	59,865	55,049
Current Liabilities
Short-term borrowings	633	914
Long-term debt, classified as current	0	539
Accounts payable
Trade creditors	1,243	1,293
Regulatory balancing accounts	1,090	1,008
Other	444	432
Disputed claims and customer refunds	434	154
Interest payable	195	887
Other	1,604	1,382
Total current liabilities	5,643	6,609
Noncurrent Liabilities
Long-term debt	14,700	12,717
Regulatory liabilities	6,290	5,660
Pension and other postretirement benefits	2,477	1,530
Asset retirement obligations	3,575	3,539
Deferred income taxes	8,773	8,042
Other	2,178	2,111
Total noncurrent liabilities	37,993	33,599
Commitments and Contingencies (Note 14)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	6,514	5,821
Reinvested earnings	8,130	7,427
Accumulated other comprehensive income (loss)	5	13
Total shareholders' equity	16,229	14,841
TOTAL LIABILITIES AND EQUITY	$59,865	$55,049

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Allowance for doubtful accounts	$66	$80
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	475,913,404	456,670,424
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$66	$80
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

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities
Net income	$1,450	$828	$830
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,433	2,077	2,272
Allowance for equity funds used during construction	-100	-101	-107
Deferred income taxes and tax credits, net	690	1,075	648
PSEP disallowed capital expenditures	116	196	353
Other	286	355	290
Effect of changes in operating assets and liabilities:
Accounts receivable	13	-152	-40
Inventories	-22	-10	-24
Accounts payable	-61	113	-4
Income taxes receivable/payable	376	-363	-132
Other current assets and liabilities	205	-469	262
Regulatory assets, liabilities, and balancing accounts, net	-1,642	-202	291
Other noncurrent assets and liabilities	-67	80	243
Net cash provided by operating activities	3,677	3,427	4,882
Cash Flows from Investing Activities
Capital expenditures	-4,833	-5,207	-4,624
Decrease in restricted cash	3	29	50
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,336	1,619	1,133
Purchases of nuclear decommissioning trust investments	-1,334	-1,604	-1,189
Other	114	56	104
Net cash provided by (used in) investing activities	-4,714	-5,107	-4,526
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	0	140	120
Repayments under revolving credit facilities	-260	0	0
Net issuances (repayments) of commercial paper, net of discount of $2, $2, and $3 at respective dates	-583	542	-1,021
Proceeds from issuance of short-term debt	300	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $18, and $13 and for the Utility $14, $18, and $13, at respective dates)	2,308	1,532	1,137
Short-term debt matured	0	0	-250
Repayments of long-term debt	-889	-861	-50
Energy recovery bonds matured	0	0	-423
Common stock issued	802	1,045	751
Common stock dividends paid	-828	-782	-746
Other	42	-41	14
Net cash provided by (used in) financing activities	892	1,575	-468
Net change in cash and cash equivalents	-145	-105	-112
Cash and cash equivalents at January 1	296	401	513
Cash and cash equivalents at December 31	151	296	401
Cash received (paid) for:
Interest, net of amounts capitalized	-633	-623	-594
Income taxes, net	501	-41	114
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	217	-208	-196
Capital expenditures financed through accounts payable	339	-322	-362
Noncash common stock issuances	21	22	22
Terminated Capital Leases	71	0	136
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	1,433	866	811
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,432	2,077	2,272
Allowance for equity funds used during construction	-100	-101	-107
Deferred income taxes and tax credits, net	731	1,103	684
PSEP disallowed capital expenditures	116	196	353
Other	226	299	236
Effect of changes in operating assets and liabilities:
Accounts receivable	16	-152	-40
Inventories	-22	-10	-24
Accounts payable	-55	99	-26
Income taxes receivable/payable	395	-377	-50
Other current assets and liabilities	155	-404	272
Regulatory assets, liabilities, and balancing accounts, net	-1,642	-202	291
Other noncurrent assets and liabilities	-66	22	256
Net cash provided by operating activities	3,619	3,416	4,928
Cash Flows from Investing Activities
Capital expenditures	-4,833	-5,207	-4,624
Decrease in restricted cash	3	29	50
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,336	1,619	1,133
Purchases of nuclear decommissioning trust investments	-1,334	-1,604	-1,189
Other	29	21	16
Net cash provided by (used in) investing activities	-4,799	-5,142	-4,614
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $2, $2, and $3 at respective dates	-583	542	-1,021
Proceeds from issuance of short-term debt	300	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $17, $18, and $13 and for the Utility $14, $18, and $13, at respective dates)	1,961	1,532	1,137
Short-term debt matured	0	0	-250
Repayments of long-term debt	-539	-861	-50
Energy recovery bonds matured	0	0	-423
Preferred stock dividends paid	-14	-14	-14
Common stock dividends paid	-716	-716	-716
Equity contribution	705	1,140	885
Other	56	-26	28
Net cash provided by (used in) financing activities	1,170	1,597	-424
Net change in cash and cash equivalents	-10	-129	-110
Cash and cash equivalents at January 1	65	194	304
Cash and cash equivalents at December 31	55	65	194
Cash received (paid) for:
Interest, net of amounts capitalized	-618	-600	-574
Income taxes, net	500	-62	174
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	339	322	362
Terminated Capital Leases	$71	$0	$136

Consolidated_Statements_Of_Cas1

Consolidated Statements Of Cash Flows (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	$2	$2	$3
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	17	18	13
Pacific Gas And Electric Company [Member]
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	2	2	3
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	$14	$18	$13

Consolidated_Statements_Of_Equ

Consolidated Statements Of Equity (USD $)	Total	Pacific Gas And Electric Company [Member]	Common Stock Shares [Member]	Common Stock Shares [Member]	Preferred Stock [Member]	Common Stock Amount [Member]	Additional Paid-In Capital [Member]	Reinvested Earnings [Member]	Reinvested Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total Shareholders' Equity [Member]	Total Shareholders' Equity [Member]	Noncontrolling Interest - Preferred Stock Of Subsidiary [Member]
In Millions, except Share data	USD ($)	USD ($)		Pacific Gas And Electric Company [Member]	Pacific Gas And Electric Company [Member]	USD ($)	Pacific Gas And Electric Company [Member]	USD ($)	Pacific Gas And Electric Company [Member]	USD ($)	Pacific Gas And Electric Company [Member]	USD ($)	Pacific Gas And Electric Company [Member]	USD ($)
				USD ($)	USD ($)		USD ($)		USD ($)		USD ($)		USD ($)
Balance at Dec. 31, 2011	$12,353			$1,322	$258	$7,602	$3,796	$4,712	$7,210	($213)	($202)	$12,101	$12,384	$252
Balance, in shares at Dec. 31, 2011			412,257,082
Net income	830	811						830	811			830	811
Other comprehensive income (loss)	112	109								112	109	112	109
Equity contribution		885					885						885
Common stock issued, net	773					773						773
Common stock issued, net, shares			18,461,211
Stock-based compensation amortization	52					52						52
Common stock dividends declared	-781							-781	-716			-781	-716
Tax benefit (expense) from employee stock plans	1					1	1					1	1
Preferred stock dividend									-14				-14
Preferred stock dividend requirement of subsidiary	-14							-14				-14
Balance at Dec. 31, 2012	13,326			1,322	258	8,428	4,682	4,747	7,291	-101	-93	13,074	13,460	252
Balance, in shares at Dec. 31, 2012			430,718,293
Net income	828	866						828	866			828	866
Other comprehensive income (loss)	151	106								151	106	151	106
Equity contribution		1,140					1,140						1,140
Common stock issued, net	1,067					1,067						1,067
Common stock issued, net, shares			25,952,131
Stock-based compensation amortization	56					56						56
Common stock dividends declared	-819							-819	-716			-819	-716
Tax benefit (expense) from employee stock plans	-1					-1	-1					-1	-1
Preferred stock dividend									-14				-14
Preferred stock dividend requirement of subsidiary	-14							-14				-14
Balance at Dec. 31, 2013	14,594			1,322	258	9,550	5,821	4,742	7,427	50	13	14,342	14,841	252
Balance, in shares at Dec. 31, 2013	456,670,424	264,374,809	456,670,424
Net income	1,450	1,433						1,450	1,433			1,450	1,433
Other comprehensive income (loss)	-39	-8								-39	-8	-39	-8
Equity contribution		705					705						705
Common stock issued, net	823					823						823
Common stock issued, net, shares			19,242,980
Stock-based compensation amortization	65					65						65
Common stock dividends declared	-862							-862	-716			-862	-716
Tax benefit (expense) from employee stock plans	-17					-17	-12					-17	-12
Preferred stock dividend									-14				-14
Preferred stock dividend requirement of subsidiary	-14							-14				-14
Balance at Dec. 31, 2014	$16,000			$1,322	$258	$10,421	$6,514	$5,316	$8,130	$11	$5	$15,748	$16,229	$252
Balance, in shares at Dec. 31, 2014	475,913,404	264,374,809	475,913,404

Organization_And_Basis_Of_Pres

Organization And Basis Of Presentation	12 Months Ended
	Dec. 31, 2014
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 operating in northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  The Utility is primarily regulated by the CPUC and the FERC.  In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility's nuclear generation facilities.
	This is a combined annual report of PG&E Corporation and the Utility.  PG&E Corporation's consolidated financial statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility's consolidated financial statements include the accounts of the Utility and its wholly owned and controlled subsidiaries.  All intercompany transactions have been eliminated in consolidation.  The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility operate in one segment.
	The consolidated financial statements have been prepared in accordance with GAAP and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.  The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities.  Some of the more significant estimates and assumptions relate to the Utility's regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations.  Management believes that its estimates and assumptions reflected in the consolidated financial statements are appropriate and reasonable.  Actual results could differ materially from those estimates.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies
	NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Regulation and Regulated Operations
	As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility's costs of service.  The Utility's ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility's electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
	The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below.
	Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility's operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
	Revenue Recognition
	The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements.
	The CPUC authorizes most of the Utility's revenues in the Utility's GRC and its GT&S rate cases, which generally occur every three years.  In general, the Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, revenue is recognized ratably over the year.
	The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.
	The FERC authorizes the Utility's revenue requirements in periodic (often annual) TO rate cases.  The Utility's ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility's electricity sales, and revenue is recognized only for amounts billed and unbilled.
	Cash and Cash Equivalents
	Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.
	Restricted Cash
	Restricted cash consists primarily of the Utility's cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code.  (See Note 12 below.)
	Allowance for Doubtful Accounts Receivable
	PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
	Inventories
	Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground represents gas that is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.
	The Utility also purchases GHG emission allowances that are recorded as inventory.  They are carried at weighted-average cost and included in current assets - other and other noncurrent assets - other on the Consolidated Balance Sheets.  The costs of the GHG emissions are expensed and recoverable through rates.
	Property, Plant, and Equipment
	Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.) The Utility's total estimated useful lives and balances of its property, plant, and equipment were as follows:
		Estimated Useful		Balance at December 31,
	(in millions, except estimated useful lives)	Lives (years)		2014			2013
	Electricity generating facilities (1)	10 to 100		$	9,374		$	9,116
	Electricity distribution facilities	10 to 55			26,633			25,333
	Electricity transmission facilities	10 to 70			9,155			8,429
	Natural gas distribution facilities	20 to 60			9,741			9,117
	Natural gas transportation and storage facilities	7 to 65			5,937			5,265
	Construction work in progress				2,220			1,834
	Total property, plant, and equipment				63,060			59,094
	Accumulated depreciation				(19,120	)		(17,843	)
	Net property, plant, and equipment			$	43,940		$	41,251
	(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it       is used based on the amount of energy output.  (See Note 14 below.)
	The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.77% in 2014, 3.51% in 2013, and 3.63% in 2012.  The useful lives of the Utility's property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
	AFUDC
	AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $45 million and $100 million during 2014, $47 million and $101 million during 2013, and $49 million and $107 million during 2012.
	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 Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.
	The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2014 and 2013.  The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear power plants was $3.5 billion at December 31, 2014 and 2013 (or $6.1 billion in future dollars).  These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.
	The following table summarizes the changes in ARO liability during 2014 and 2013:
	(in millions)		2014			2013
	ARO liability at beginning of year	$	3,538		$	2,919
	Revision in estimated cash flows		(16	)		596
	Accretion		163			130
	Liabilities settled		(110	)		(107	)
	ARO liability at end of year	$	3,575		$	3,538
	The Utility has not recorded a liability related to certain ARO's for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.
	Disallowance of Plant Costs
	PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  The Utility recorded charges of $116 million, $196 million and $353 million in 2014, 2013, and 2012, respectively, for PSEP capital costs that are expected to exceed the CPUC's authorized levels or that are specifically disallowed.  (See “Enforcement and Litigation Matters” in Note 14 below).
	Nuclear Decommissioning Trusts
	The Utility's nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
	The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since the Utility's nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments.  Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility's earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
	Gains and Losses on Debt Extinguishments
	Deferred gains and losses on debt extinguishments are recorded to regulatory assets in current assets and regulatory assets in other noncurrent assets on the Consolidated Balance Sheets. Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates.  PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $135 million, $157 million, and $163 million at December 31, 2014, 2013, and 2012, respectively.  The amortization expense related to this loss was $22 million in 2014 and $23 million in both 2013 and 2012.
	Variable Interest Entities
	A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
	Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2014, it assessed whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE's gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE's performance, such as dispatch rights and operating and maintenance activities.  The Utility's financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2014, it did not consolidate any of them.
	PG&E Corporation affiliates previously entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that were considered VIEs.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs, they were not consolidated.  On July 2, 2014, PG&E Corporation disposed of its interest in the tax equity agreements and has no remaining commitment to fund these agreements.
	Other Accounting Policies
	For other accounting policies impacting PG&E Corporation's and the Utility's consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies” in Note 14 of the Notes to the Consolidated Financial Statements.
	Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
	The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:
		Pension			Other			Other
(in millions, net of income tax)	Benefits			Benefits			Investments			Total
Beginning balance	$	(7	)		15			42			50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-			-			5			5
Unrecognized net actuarial loss
(net of taxes of $404, $19, and $0, respectively)		(588	)		(28	)		-			(616	)
Unrecognized prior service cost
(net of taxes of $0, $0, and $0, respectively)		1			-			-			1
Transfer to regulatory account
(net of taxes of $394, $19, and $0, respectively)		573			28			-			601
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $8, $9, and $0, respectively) (1)		12			14			-			26
Amortization of net actuarial loss
(net of taxes of $1, $1, and $0, respectively) (1)		1			1			-			2
Transfer to regulatory account
(net of taxes of $9, $10, and $0, respectively) (1)		(13	)		(15	)		-			(28	)
Realized gain on investments
(net of taxes of $0, $0, and $20, respectively)		-			-			(30	)		(30	)
Net current period other comprehensive loss		-14			-			-25			-39
Ending balance	$	-21			15			17			11
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)
The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income (loss) for the year ended December 31, 2013 consisted of the following:
	Pension			Other			Other
(in millions, net of income tax)	Benefits			Benefits			Investments			Total
Beginning balance	$	(28	)		(77	)		4			(101	)
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $26, respectively)		-			-			38			38
Unrecognized net actuarial loss
(net of taxes of $804, $35, and $0, respectively)		1,169			45			-			1,214
Transfer to regulatory account
(net of taxes of $790, $22, and $0, respectively)		(1,150	)		31			-			(1,119	)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $8, $10, and $0, respectively)		12			13			-			25
Amortization of net actuarial loss
(net of taxes of $45, $3, and $0, respectively)		66			3			-			69
Transfer to regulatory account
(net of taxes of $54, $0, and $0, respectively)		(76	)		-			-			(76	)
Net current period other comprehensive income		21			92			38			151
Ending balance	$	-7			15			42			50
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)
With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.
New Accounting Pronouncements
Revenue Recognition Standard
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance.  The accounting standards update will be effective on January 1, 2017.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

Regulatory_Assets_Liabilities_

Regulatory Assets, Liabilities, And Balancing Accounts	12 Months Ended
	Dec. 31, 2014
Regulatory Assets, Liabilities, And Balancing Accounts
	NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	Regulatory Assets
	Long-term regulatory assets are comprised of the following:
		Balance at December 31,				Recovery
	(in millions)	2014		2013		Period
	Pension benefits (1)	$	2,347	$	1,444	N/A (4)
	Deferred income taxes (1)		2,390		1,835	47 years
	Utility retained generation (2)		456		503	11 years
	Environmental compliance costs (1)		717		628	32 years
	Price risk management (1)		127		106	10 years
	Electromechanical meters (3)		70		135	2 years
	Unamortized loss, net of gain, on reacquired debt (1)		113		135	12 years
	Other		102		127	Various
	Total long-term regulatory assets	$	6,322	$	4,913
	(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets.  (See Note 11 below.)
	(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility's retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
	(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.
	(4) The Utility expects to continuously recover pension benefits.
	In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest.  Accordingly, the Utility earns a return only on its regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.
	Regulatory Liabilities
	Long-term regulatory liabilities are comprised of the following:
		Balance at December 31,
	(in millions)	2014		2013
	Cost of removal obligations (1)	$	4,211	$	3,844
	Recoveries in excess of AROs (2)		754		748
	Public purpose programs (3)		701		587
	Other		624		481
	Total long-term regulatory liabilities	$	6,290	$	5,660
	(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
	(2) Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 10 below.)
	(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
	Regulatory Balancing Accounts
	The Utility's recovery of revenue requirements and costs is generally decoupled from the volume of sales.  The Utility tracks (1) differences between the Utility's authorized revenue requirement and actual customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets - regulatory assets or noncurrent liabilities - regulatory liabilities, respectively, in the Consolidated Balance Sheets.
	The Utility sells and delivers electricity and natural gas.  The Utility also administers public purpose programs, primarily related to customer energy efficiency programs.  The balancing accounts associated with these items will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
	Current regulatory balancing accounts receivable and payable are comprised of the following:
		Receivable
		Balance at December 31,
	(in millions)	2014		2013
	Electric distribution	$	344	$	102
	Utility generation		261		57
	Gas distribution		566		70
	Energy procurement		608		410
	Public purpose programs		109		56
	Other		378		429
	Total regulatory balancing accounts receivable	$	2,266	$	1,124
		Payable
		Balance at December 31,
	(in millions)	2014		2013
	Energy procurement	$	188	$	298
	Public purpose programs		154		171
	Other (1)		748		539
	Total regulatory balancing accounts payable	$	1,090	$	1,008
	(1) At December 31, 2014, Other regulatory balancing accounts payable mostly includes energy supplier settlements.  (See Note 12 for additional details.)

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt
	NOTE 4: DEBT
	Long-Term Debt
	The following table summarizes PG&E Corporation's and the Utility's long-term debt:
		December 31,
	(in millions)	2014			2013
	PG&E Corporation
	Senior notes, 5.75%, due 2014		-			350
	Senior notes, 2.40%, due 2019		350			-
	Less: current portion		-			(350	)
	Total senior notes		350			-
	Total PG&E Corporation long-term debt		350			-
	Utility
	Senior notes:
	4.80% due 2014		-			539
	5.625% due 2017		700			700
	8.25% due 2018		800			800
	3.50% due 2020		800			800
	4.25% due 2021		300			300
	3.25% due 2021		250			250
	2.45% due 2022		400			400
	3.25% due 2023		375			375
	3.85% due 2023		300			300
	3.40% due 2024		350			-
	3.75% due 2024		450			-
	6.05% due 2034		3,000			3,000
	5.80% due 2037		950			950
	6.35% due 2038		400			400
	6.25% due 2039		550			550
	5.40% due 2040		800			800
	4.50% due 2041		250			250
	4.45% due 2042		400			400
	3.75% due 2042		350			350
	4.60% due 2043		375			375
	5.125% due 2043		500			500
	4.75% due 2044		675			-
	4.30% due 2045		500			-
	Less: current portion		-			(539	)
	Unamortized discount, net of premium		(43	)		(51	)
	Total senior notes, net of current portion		13,432			11,449
	Pollution control bonds:
	Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614			614
	Series 2004 A-D, 4.75%, due 2023 (3)		345			345
	Series 2009 A-D, variable rates (1), due 2016 and 2026 (4)		309			309
	Total pollution control bonds		1,268			1,268
	Total Utility long-term debt, net of current portion		14,700			12,717
	Total consolidated long-term debt, net of current portion	$	15,050		$	12,717
	(1) At December 31, 2014, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
	(2) Each series of these bonds is supported by a separate letter of credit.  In April 2014, the letters of credit were extended to April 1, 2019.  Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
	(3) The Utility has obtained credit support from an insurance company for these bonds.
	(4) Each series of these bonds is supported by a separate direct-pay letter of credit.  In June 2014, Series A and B letters of credit were extended to June 5, 2019.  Series C and D letters expire on December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
	Pollution Control Bonds
	The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility.  Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility's Diablo Canyon nuclear power plant.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sale agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  The Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
	Short-term Borrowings
	The following table summarizes PG&E Corporation's and the Utility's outstanding borrowings under their revolving credit facilities and commercial paper programs at December 31, 2014:
								Letters of
		Termination		Facility				Credit			Commercial				Facility
	(in millions)	Date		Limit				Outstanding			Paper				Availability
	PG&E Corporation	Apr-19		$	300	-1		$	-		$	-			$	300
	Utility	Apr-19			3,000	-2			84			333				2,583
	Total revolving credit facilities			$	3,300			$	84		$	333			$	2,883
	(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
	(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
	For 2014, the average outstanding bank borrowings on PG&E Corporation's revolving credit facility was $27 million and the maximum outstanding balance during the year was $260 million.  In February 2014, PG&E Corporation repaid the full outstanding bank borrowings of $260 million and initiated borrowing under its commercial paper program established in January 2014.  For the year ended December 31, 2014, PG&E Corporation's average outstanding commercial paper balance was $118 million and the maximum outstanding balance during the period was $260 million.  For 2014, the Utility's average outstanding commercial paper balance was $609 million and the maximum outstanding balance during the year was $1.4 billion.  The Utility did not have any bank borrowings in 2014.
Revolving Credit Facilities
In April 2014, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from April 1, 2018 to April 1, 2019.  These agreements contain substantially similar terms as the original 2011 credit agreements.  PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes.  At PG&E Corporation's and the Utility's request and at the sole discretion of each lender, the facilities may be extended for additional periods.  Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders' commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.
Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation's and the Utility's election, on (1) a London Interbank Offered Rate plus an applicable margin or (2) the base rate plus an applicable margin.  The base rate will equal the higher of the following: the administrative agent's announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin.  Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.  PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities.  The applicable margins and the facility fees will be based on PG&E Corporation's and the Utility's senior unsecured debt ratings issued by Standard & Poor's Rating Services and Moody's Investor Service.  Facility fees are payable quarterly in arrears.
PG&E Corporation's and the Utility's revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes.  In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter.  PG&E Corporation's revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.
Commercial Paper Programs
For 2014, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.24% and 0.23%, respectively.
The borrowings from PG&E Corporation and the Utility's commercial paper programs are used primarily to fund temporary financing needs.  Liquidity support for these borrowings is provided by available capacity under their respective revolving credit facilities, as described above.  PG&E Corporation and the Utility treat the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facilities.  The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation's and the Utility's other unsubordinated and unsecured indebtedness.  Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance.
Other Short-term Borrowings
In May 2014, the Utility issued $300 million principal amount of Floating Rate Senior Notes due May 11, 2015.
Repayment Schedule
PG&E Corporation's and the Utility's combined long-term debt principal repayment amounts at December 31, 2014 are reflected in the table below:
(in millions,
except interest rates)	2015			2016				2017				2018				2019			Thereafter				Total
PG&E Corporation
Average fixed interest rate		-				-				-				-			2.40	%			-				2.4	%
Fixed rate obligations	$	-			$	-			$	-			$	-		$	350			$	-			$	350
Utility
Average fixed interest rate		-				-				5.63	%			8.25	%		-				4.92	%			5.15	%
Fixed rate obligations	$	-			$	-			$	700			$	800		$	-			$	12,320			$	13,820
Variable interest rate
as of December 31, 2014		-				0.01	%			-				-			0.01	%			-				0.01	%
Variable rate obligations (1)	$	-			$	160			$	-			$	-		$	763			$	-			$	923
Total consolidated debt	$	-			$	160			$	700			$	800		$	1,113			$	12,320			$	15,093
(1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, April 1, 2019, or June 5, 2019.

Common_Stock_And_ShareBased_Co

Common Stock And Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
Common Stock And Share-Based Compensation
	NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION
	PG&E Corporation had 475,913,404 shares of common stock outstanding at December 31, 2014.  PG&E Corporation held all of the Utility's outstanding common stock at December 31, 2014.
	In February 2014, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  During 2014, PG&E Corporation sold 11 million shares under the February 2014 equity distribution agreement for cash proceeds of $496 million, exhausting the capacity under this agreement. This amount is net of commissions paid of $4 million.
	In addition, PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans.  During 2014, 8 million shares were issued for cash proceeds of $306 million under these plans.
	Dividends
	The Board of Directors of PG&E Corporation and the Utility declare dividends quarterly.  Under the Utility's Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility's preferred stock have been paid.  For 2014, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.455 per share.
	Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over four years.  PG&E Corporation and the Utility are in compliance with these restrictions. At December 31, 2014, the Utility had restricted net assets of $14.6 billion and was limited to $153 million of additional common stock dividends it could pay to PG&E Corporation at December 31, 2014.
	Long-Term Incentive Plan
	The PG&E Corporation LTIP permits various forms of share-based incentive awards, including restricted stock awards, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  In May 2014, the 2006 LTIP was terminated and the 2014 LTIP became effective.  A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 16,184,126 shares were available for future awards at December 31, 2014.
	The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2014, 2013, and 2012:
	(in millions)	2014			2013		2012
	Restricted stock units	$	42		$	36	$	31
	Performance shares		36			28		26
	Total compensation expense (pre-tax)	$	78		$	64	$	57
	Total compensation expense (after-tax)	$	47		$	38	$	34
	The amount of share-based compensation costs capitalized during 2014, 2013, and 2012 was immaterial.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
	Restricted Stock Units
	Prior to 2014, restricted stock units generally vested over four years in 20% increments on the first business day of March in year one, two, and three, with the remaining 40% vesting on the first business day of March in year four.  Restricted stock units granted in 2014 generally vest equally over three years.  Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized rateably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2014, 2013, and 2012 was $43.76, $42.92, and $42.17, respectively.  The total fair value of restricted stock units that vested during 2014, 2013, and 2012 was $34 million, $30 million, and $18 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.  As of December 31, 2014, $51 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.77 years.
	The following table summarizes restricted stock unit activity for 2014:
		Number of		Weighted Average Grant-
		Restricted Stock Units		Date Fair Value
	Nonvested at January 1	2,300,021		$	43.16
	Granted	1,092,035		$	43.76
	Vested	(777,883	)	$	43.28
	Forfeited	(75,816	)	$	43.01
	Nonvested at December 31	2,538,357		$	43.38
	Performance Shares
	Performance shares generally will vest three years after the grant date.  Upon vesting, performance shares are settled in shares of common stock based on PG&E Corporation's total shareholder return relative to a specified group of industry peer companies over a three-year performance period.  Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled.
	Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model.  The weighted average grant-date fair value for performance shares granted during 2014, 2013, and 2012 was $51.81, $33.45, and $41.93 respectively.  There was no tax benefit associated with performance shares during each of these periods.  As of December 31, 2014, $34 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.18 years.
	The following table summarizes activity for performance shares in 2014:
		Number of		Weighted Average Grant-
		Performance Shares		Date Fair Value
	Nonvested at January 1	1,791,320		$	37.85
	Granted	843,185			51.81
	Vested	(275,247	)		41.94
	Forfeited (1)	(665,319	)		42.34
	Nonvested at December 31	1,693,939		$	42.37
	(1) Includes performance shares that expired with zero value as performance targets were not met.

Preferred_Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2014
Preferred Stock	NOTE 6: PREFERRED STOCK
	PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock.  PG&E Corporation does not have any preferred stock outstanding.
	The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock.  At December 31, 2014 and December 31, 2013, the Utility's preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share.  The Utility's preferred stock outstanding are not subject to mandatory redemption.  All outstanding preferred stock has a $25 par value.
	At December 31, 2014, annual dividends on the Utility's nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2014, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
	Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $14 million of dividends on preferred stock in each of 2014, 2013, and 2012.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share	NOTE 7: EARNINGS PER SHARE
	PG&E Corporation's basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation's income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2014, 2013, and 2012.
		Year Ended December 31,
	(in millions, except per share amounts)	2014		2013		2012
	Income available for common shareholders	$	1,436	$	814	$	816
	Weighted average common shares outstanding, basic		468		444		424
	Add incremental shares from assumed conversions:
	Employee share-based compensation		2		1		1
	Weighted average common share outstanding, diluted		470		445		425
	Total earnings per common share, diluted	$	3.06	$	1.83	$	1.92
	For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes	NOTE 8: INCOME TAXES
	PG&E Corporation and the Utility use the liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year.  PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.
	PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.
	Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.
	PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
	The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
		PG&E Corporation									Utility
		Year Ended December 31,
	(in millions)	2014			2013			2012			2014			2013			2012
	Current:
	Federal	$	(84	)	$	(218	)	$	(74	)	$	(84	)	$	(222	)	$	(52	)
	State		(41	)		(26	)		33			(29	)		(23	)		41
	Deferred:
	Federal		396			552			374			426			604			404
	State		78			(35	)		(92	)		75			(28	)		(91	)
	Tax credits		(4	)		(5	)		(4	)		(4	)		(5	)		(4	)
	Income tax provision	$	345		$	268		$	237		$	384		$	326		$	298
	The following table describes net deferred income tax liabilities:
		PG&E Corporation						Utility
		Year Ended December 31,
	(in millions)	2014			2013			2014			2013
	Deferred income tax assets:
	Customer advances for construction	$	88		$	90		$	88		$	90
	Reserve for damages		137			161			137			161
	Environmental reserve		111			152			111			152
	Compensation		107			167			36			102
	Net operating loss carryforward		1,177			890			946			670
	GHG allowances		56			108			56			108
	Other		74			135			100			128
	Total deferred income tax assets	$	1,750		$	1,703		$	1,474		$	1,411
	Deferred income tax liabilities:
	Regulatory balancing accounts	$	512		$	261		$	512		$	261
	Property related basis differences		8,683			8,048			8,666			8,038
	Income tax regulatory asset (1)		974			748			974			748
	Other		88			151			86			86
	Total deferred income tax liabilities	$	10,257		$	9,208		$	10,238		$	9,133
	Total net deferred income tax liabilities	$	8,507		$	7,505		$	8,764		$	7,722
	Classification of net deferred income tax liabilities:
	Included in current liabilities (assets)	$	(6	)	$	(318	)	$	(9	)	$	(320	)
	Included in noncurrent liabilities		8,513			7,823			8,773			8,042
	Total net deferred income tax liabilities	$	8,507		$	7,505		$	8,764		$	7,722
	(1) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  (See Note 3 above.)
	The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
		PG&E Corporation									Utility
		Year Ended December 31,
		2014			2013			2012			2014			2013			2012
	Federal statutory income tax rate	35	%		35	%		35	%		35	%		35	%		35	%
	Increase (decrease) in income
	tax rate resulting from:
	State income tax (net of
	federal benefit) (1)	1.4			(3.1	)		(3.9	)		1.6			(2.2	)		(3.0	)
	Effect of regulatory treatment
	of fixed asset differences (2)	(15.0	)		(4.2	)		(4.1	)		(14.7	)		(3.8	)		(3.9	)
	Tax credits	(0.7	)		(0.4	)		(0.6	)		(0.7	)		(0.4	)		(0.6	)
	Benefit of loss carryback	(0.8	)		(1.1	)		(0.7	)		(0.8	)		(1.0	)		(0.4	)
	Non deductible penalties	0.3			0.8			0.6			0.3			0.7			0.5
	Other, net	(0.8	)		(2.2	)		(3.8	)		0.4			(0.9	)		(0.8	)
	Effective tax rate	19.4	%		24.8	%		22.5	%		21.1	%		27.4	%		26.8	%
	(1) Includes the effect of state flow-through ratemaking treatment.
	(2) Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the “2014 GRC Impact” section.
	Unrecognized tax benefits
	The following table reconciles the changes in unrecognized tax benefits:
		PG&E Corporation									Utility
		2014			2013			2012			2014			2013			2012
(in millions)
Balance at beginning of year	$	666		$	581		$	506		$	660		$	575		$	503
Additions for tax position taken
during a prior year		7			12			32			7			12			26
Reductions for tax position
taken during a prior year		(9	)		(6	)		(13	)		(9	)		(6	)		(10	)
Additions for tax position
taken during the current year		61			79			67			61			79			67
Settlements		(12	)		-			(11	)		(12	)		-			(11	)
Balance at end of year	$	713		$	666		$	581		$	707		$	660		$	575
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2014 for PG&E Corporation and the Utility was $20 million, with the remaining balance representing the potential deferral of taxes to later years.
PG&E Corporation's and the Utility's unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the audits related to the 2011, 2012, and 2013 tax returns (see “2014 GRC impact” below).  As of December 31, 2014, it is reasonably possible that unrecognized tax benefits will decrease by approximately $330 million within the next 12 months, and most of this decrease would not impact net income.
Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2014, 2013, and 2012, these amounts were immaterial.
2014 GRC impact
The 2014 GRC decision authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets or liabilities.  Therefore, PG&E Corporation's and the Utility's effective income tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  In addition, recent guidance from the IRS allowed the Utility to deduct more repair costs than previously forecasted in the GRC.  For the year ended December 31, 2014, the Utility recognized a reduction in income tax expense of $235 million consistent with a lower revenue requirement in the 2014 GRC and IRS guidance.
IRS settlements and years that remain subject to examination
PG&E Corporation participates in the Compliance Assurance Process, a real-time IRS audit intended to expedite resolution of tax matters.  The Compliance Assurance Process audit culminates with a letter from the IRS indicating its acceptance of the return.
The IRS is currently reviewing several matters in the 2011, 2012, and 2013 tax returns.  The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining which repair costs are deductible for the electric transmission and distribution businesses.  PG&E Corporation and the Utility expect that the IRS will complete the review of the deductible repair costs for the electric transmission and distribution businesses in 2015.  The IRS is also expected to issue guidance during 2015 that determines which repair costs are deductible for the natural gas transmission and distribution businesses.
The Tax Increase Prevention Act, signed into law on December 19, 2014, extended 50% bonus federal tax depreciation on qualified property placed into service in 2014.
Carryforwards
As of December 31, 2014, PG&E Corporation had approximatelyError! Bookmark not defined. $4.1 billion of federal net operating loss carryforwards and $77 million of tax credit carryforwards, which will expire between 2029 and 2034.  In addition, PG&E Corporation had approximately $219 million of loss carryforwards related to charitable contributions, which will expire between 2015 and 2019.  PG&E Corporation had $123 million of California net operating loss carryforwards which will expire between 2033 and 2034 and $30 million of California credit carryforwards, some of which will expire in 2024 and others which will carryforward indefinitely.  PG&E Corporation believes it is more likely than not the tax benefits associated with the federal net operating loss, charitable contributions, and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2014.  As of December 31, 2014, PG&E Corporation had approximately $24 million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.

Derivatives_And_Hedging_Activi

Derivatives And Hedging Activities	12 Months Ended
	Dec. 31, 2014
Derivatives And Hedging Activities
	NOTE 9: DERIVATIVES
	Use of Derivative Instruments
	The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include forward contracts, swaps, futures, options, and CRRs.
	These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  Customer rates are designed to recover the Utility's reasonable costs of providing services, including the costs related to price risk management activities.
	Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets.  As long as the current ratemaking mechanism discussed in Note 2, above, remains in place and the Utility's price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives.  Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility's regulatory assets and liabilities on the Consolidated Balance Sheets.  Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
	Cash collateral paid or received is offset against the fair value of derivative instruments executed with the same counterparty under a master netting arrangement, where the right of offset and the intention to offset exist.  Derivatives are presented in the Utility's Consolidated Balance Sheets on a net basis; see below.
	The Utility elects the normal purchase and sale exception for eligible derivatives.  Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered.  The fair value of these items is not reflected in the Consolidated Balance Sheets at fair value, eligible derivatives are accounted for under the accrual method of accounting.
	Volume of Derivative Activity
	At December 31, 2014 and 2013, respectively, the volumes of the Utility's outstanding derivatives were as follows:
					Contract Volume
	Underlying Product		Instruments		2014		2013
	Natural Gas (1) (MMBtus (2))		Forwards and Swaps		308,130,101		331,840,788
			Options		164,418,002		260,262,916
	Electricity (Megawatt-hours)		Forwards and Swaps		5,346,787		8,089,269
			Congestion Revenue Rights (3)		224,124,341		250,922,591
	(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 congestion costs based on demand when there is insufficient transmission capacity.
	Presentation of Derivative Instruments in the Financial Statements
	At December 31, 2014, 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	$	73		$	(4	)	$	19		$	88
	Other noncurrent assets - other		178			(13	)		-			165
	Current liabilities - other		(78	)		4			26			(48	)
	Noncurrent liabilities - other		(140	)		13			9			(118	)
	Total commodity risk	$	33		$	-		$	54		$	87
	At December 31, 2013, 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	$	42		$	(10	)	$	16		$	48
	Other noncurrent assets - other		99			(4	)		-			95
	Current liabilities - other		(122	)		10			69			(43	)
	Noncurrent liabilities - other		(110	)		4			2			(104	)
	Total commodity risk	$	-91		$	-		$	87		$	-4
	Gains and losses recorded on the Utility's derivatives were as follows:
		Commodity Risk
		For the year ended December 31,
	(in millions)	2014			2013			2012
	Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	124		$	238		$	391
	Realized loss - cost of electricity (2)		(83	)		(178	)		(486	)
	Realized loss - cost of natural gas (2)		(8	)		(22	)		(38	)
	Total commodity risk	$	33		$	38		$	-133
	(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Consolidated Statements of Income.  These amounts exclude the impact of cash collateral postings.
	(2) These amounts are fully passed through to customers in rates.  Accordingly, net income was not impacted by realized amounts on these instruments.
	Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility's 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 December 31, 2014, the Utility's credit rating was investment grade.  If the Utility's credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.
	The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:
		Balance at December 31,
	(in millions)	2014			2013
	Derivatives in a liability position with credit risk-related
	contingencies that are not fully collateralized	$	(47	)	$	(79	)
	Related derivatives in an asset position		-			4
	Collateral posting in the normal course of business related to
	these derivatives		44			65
	Net position of derivative contracts/additional collateral
	posting requirements (1)	$	-3		$	-10
	(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	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements
	NOTE 10: FAIR VALUE MEASUREMENTS
	PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:
	Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
	Level 2 - Other inputs that are directly or indirectly observable in the marketplace.
	Level 3 - Unobservable inputs which are supported by little or no market activities.
	The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
	Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (assets held in rabbi trusts and other investments are held by PG&E Corporation and not the Utility):
		Fair Value Measurements
		At  December 31, 2014
	(in millions)	Level 1			Level 2			Level 3			Netting (1)			Total
	Assets:
	Money market investments	$	94		$	-		$	-		$	-		$	94
	Nuclear decommissioning trusts
	Money market investments		17			-			-			-			17
	Global equity securities		1,585			13			-			-			1,598
	Fixed-income securities		741			389			-			-			1,130
	Total nuclear decommissioning trusts (2)		2,343			402			-			-			2,745
	Price risk management instruments
	(Note 9)
	Electricity		-			17			232			2			251
	Gas		1			1			-			-			2
	Total price risk management instruments		1			18			232			2			253
	Rabbi trusts
	Fixed-income securities		-			42			-			-			42
	Life insurance contracts		-			72			-			-			72
	Total rabbi trusts		-			114			-			-			114
	Long-term disability trust
	Money market investments		7			-			-			-			7
	Global equity securities		-			25			-			-			25
	Fixed-income securities		-			128			-			-			128
	Total long-term disability trust		7			153			-			-			160
	Other investments		33			-			-			-			33
	Total assets	$	2,478		$	687		$	232		$	2		$	3,399
	Liabilities:
	Price risk management instruments
	(Note 9)
	Electricity	$	47		$	5		$	163		$	(52	)	$	163
	Gas		-			3			-			-			3
	Total liabilities	$	47		$	8		$	163		$	-52		$	166
	(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
	(2) Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
		Fair Value Measurements
		At December 31, 2013
	(in millions)	Level 1			Level 2			Level 3			Netting (1)			Total
	Assets:
	Money market investments	$	226		$	-		$	-		$	-		$	226
	Nuclear decommissioning trusts
	Money market investments		38			-			-			-			38
	U.S. equity securities		1,046			11						-			1,057
	Non-U.S. equity securities		457			-			-			-			457
	U.S. government and agency securities		760			156			-			-			916
	Municipal securities		-			25			-			-			25
	Other fixed-income securities		-			162			-			-			162
	Total nuclear decommissioning trusts (2)		2,301			354			-			-			2,655
	Price risk management instruments
	(Note 9)
	Electricity		2			27			107			3			139
	Gas		-			5			-			(1	)		4
	Total price risk management instruments		2			32			107			2			143
	Rabbi trusts
	Fixed-income securities		-			39			-			-			39
	Life insurance contracts		-			70			-			-			70
	Total rabbi trusts		-			109			-			-			109
Long-term disability trust
Money market investments		9			-			-			-			9
U.S. equity securities		-			14			-			-			14
Non-U.S. equity securities		-			12			-			-			12
Fixed-income securities		-			122			-			-			122
Total long-term disability trust		9			148			-			-			157
Other investments		84			-			-			-			84
Total assets	$	2,622		$	643		$	107		$	2		$	3,374
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	19		$	72		$	137		$	(84	)	$	144
Gas		1			3			-			(1	)		3
Total liabilities	$	20		$	75		$	137		$	-85		$	147
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $313 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.  Investments, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.  Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the year ended December 31, 2014 and 2013.
Trust Assets
Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities, debt securities, and life insurance policies.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.
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.  Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes are readily observable and available.
Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.
Price Risk Management Instruments
Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, 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 forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.
Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility's Level 3 instruments using pricing inputs from brokers and historical data.
The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.
Level 3 Measurements and Sensitivity Analysis
The Utility's market and credit risk management function, which reports to the Chief Risk Officer of the Utility, is responsible for determining the fair value of the Utility's price risk management derivatives.  The Utility's finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.
Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 9 above.)
		Fair Value at
(in millions)		31-Dec-14
Fair Value Measurement		Assets			Liabilities			Valuation Technique		Unobservable Input		Range (1)
Congestion revenue rights		$	232		$	63		Market approach		CRR auction prices		$	(15.97) - 8.17
Power purchase agreements		$	-		$	100		Discounted cash flow		Forward prices		$	16.04 - 56.21
(1)       Represents price per megawatt-hour
		Fair Value at
(in millions)		31-Dec-13
Fair Value Measurement		Assets			Liabilities			Valuation Technique		Unobservable Input		Range (1)
Congestion revenue rights		$	107		$	32		Market approach		CRR auction prices		$	(6.47) - 12.04
Power purchase agreements		$	-		$	105		Discounted cash flow		Forward prices		$	23.43 - 51.75
(1) Represents price per megawatt-hour
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2014 and 2013, respectively:
	Price Risk Management Instruments
(in millions)	2014			2013
Liability balance as of January 1	$	-30		$	-79
Realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		99			49
Asset (liability) balance as of December 31	$	69		$	-30
(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
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, floating rate senior notes, and the Utility's variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2014 and 2013, 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-rate pollution control bonds and PG&E Corporation's fixed-rate senior notes were based on quoted market prices at December 31, 2014 and 2013.
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 December 31,
	2014						2013
(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation	$	350		$	352		$	350		$	354
Utility		13,778			15,851			12,334			13,444
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 December 31, 2014
Nuclear decommissioning trusts
Money market investments	$	17		$	-		$	-		$	17
Global equity securities		520			1,087			(9	)		1,598
Fixed-income securities		1,059			75			(4	)		1,130
Total nuclear decommissioning trusts (1)		1,596			1,162			(13	)		2,745
Other investments		5			28			-			33
Total	$	1,601		$	1,190		$	-13		$	2,778
As of December 31, 2013
Nuclear decommissioning trusts
Money market investments	$	38		$	-		$	-		$	38
Equity securities
U.S.		246			811			-			1,057
Non-U.S.		215			242			-			457
Debt securities
U.S. government and agency securities		870			51			(5	)		916
Municipal securities		24			2			(1	)		25
Other fixed-income securities		163			1			(2	)		162
Total nuclear decommissioning trusts (1)		1,556			1,107			(8	)		2,655
Other investments		13			71			-			84
Total (1)	$	1,569		$	1,178		$	-8		$	2,739
(1) Represents amounts before deducting $324 million and $313 million at December 31, 2014 and 2013, respectively, primarily related to deferred taxes on appreciation of investment value.
The fair value of debt securities by contractual maturity is as follows:
	As of
(in millions)	31-Dec-14
Less than 1 year	$	17
1-5 years		466
5-10 years		263
More than 10 years		384
Total maturities of debt securities	$	1,130
The following table provides a summary of activity for the debt and equity securities:
	2014			2013			2012
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	1,336		$	1,619		$	1,133
Gross realized gains on sales of securities held as available-for-sale		118			94			19
Gross realized losses on sales of securities held as available-for-sale		(12	)		(13	)		(17	)

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Employee Benefit Plans
	NOTE 11: EMPLOYEE BENEFIT PLANS
	Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)
	PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation's and the Utility's funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  Based upon current assumptions and available information, the Utility's minimum funding requirements related to its pension plans is zero.
	PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.
	Change in Plan Assets, Benefit Obligations, and Funded Status
	The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans' aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2014 and 2013:
	Pension Plan
	(in millions)	2014			2013
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	12,527		$	12,141
	Actual return on plan assets		1,946			673
	Company contributions		332			323
	Benefits and expenses paid		(589	)		(610	)
	Fair value of plan assets at end of year	$	14,216		$	12,527
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	14,077		$	15,541
	Service cost for benefits earned		383			468
	Interest cost		695			627
	Actuarial (gain) loss		2,131			(1,950	)
	Plan amendments		(1	)		-
	Transitional costs		-			1
	Benefits and expenses paid		(589	)		(610	)
	Benefit obligation at end of year (1)	$	16,696		$	14,077
	Funded Status:
	Current liability	$	(6	)	$	(6	)
	Noncurrent liability		(2,474	)		(1,544	)
	Net liability at end of year	$	-2,480		$	-1,550
	(1) PG&E Corporation's accumulated benefit obligation was $14.9 billion and $12.6 billion at December 31, 2014 and 2013, respectively.
	Postretirement Benefits Other than Pensions
	(in millions)	2014			2013
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	1,892		$	1,758
	Actual return on plan assets		241			64
	Company contributions		57			145
	Plan participant contribution		63			64
	Benefits and expenses paid		(161	)		(139	)
	Fair value of plan assets at end of year	$	2,092		$	1,892
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	1,597		$	1,940
	Service cost for benefits earned		45			53
	Interest cost		76			74
	Actuarial (gain) loss		166			(415	)
	Benefits paid		(140	)		(123	)
	Federal subsidy on benefits paid		4			4
	Plan participant contributions		63			64
	Benefit obligation at end of year	$	1,811		$	1,597
	Funded Status: (1)
	Noncurrent asset	$	368		$	352
	Noncurrent liability		(87	)		(57	)
	Net asset at end of year	$	281		$	295
	(1) At December 31, 2014 and 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
	There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
	Components of Net Periodic Benefit Cost
	Net periodic benefit cost as reflected in PG&E Corporation's Consolidated Statements of Income was as follows:
	Pension Plan
	(in millions)	2014			2013			2012
	Service cost	$	383		$	468		$	396
	Interest cost		695			627			658
	Expected return on plan assets		(807	)		(650	)		(598	)
	Amortization of prior service cost		20			20			20
	Amortization of net actuarial loss		2			111			123
	Net periodic benefit cost		293			576			599
	Less: transfer to regulatory account (1)		42			(238	)		(301	)
Total expense recognized	$	335		$	338		$	298
(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
Postretirement Benefits Other than Pensions
(in millions)	2014			2013			2012
Service cost	$	45		$	53		$	49
Interest cost		76			74			83
Expected return on plan assets		(103	)		(79	)		(77	)
Amortization of transition obligation		-			-			24
Amortization of prior service cost		23			23			25
Amortization of net actuarial loss		2			6			6
Net periodic benefit cost	$	43		$	77		$	110
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
Components of Accumulated Other Comprehensive Income
PG&E Corporation and the Utility record unrecognized prior service costs, unrecognized gains and losses, and unrecognized net transition obligations related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).
The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2015 are as follows:
(in millions)	Pension Plan			PBOP Plans
Unrecognized prior service cost	$	15		$	19
Unrecognized net loss		11			4
Total	$	26		$	23
There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.
Valuation Assumptions
In 2014, PG&E Corporation and the Utility adopted the Society of Actuaries 2014 Mortality Tables Report (RP-2014) and Mortality Improvement Scale (MP-2014 with modifications), which updated the mortality assumptions used for measuring retirement plan obligations.  This new mortality table and improvement scale extends the assumed life expectancy of plan participants, resulting in an increase in PG&E Corporation's and the Utility's accrued benefit cost as of December 31, 2014.  Total pension and postretirement benefit obligation increased $82 million and $18 million in 2014, respectively.
The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs.  The following weighted average year-end assumptions were used in determining the plans' projected benefit obligations and net benefit cost.
	Pension Plan									PBOP Plans
	December 31,									December 31,
	2014			2013			2012			2014		2013		2012
Discount rate	4	%		4.89	%		3.98	%		3.89 - 4.09	%	4.70 - 5.00	%	3.75 - 4.08	%
Rate of future compensation
increases	4	%		4	%		4	%		-		-		-
Expected return on plan
assets	6.2	%		6.5	%		5.4	%		3.30 - 6.70	%	3.50 - 6.70	%	2.90 - 6.10	%
The assumed health care cost trend rate as of December 31, 2014 was 7.5%, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 3.5%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:
	One-Percentage-Point			One-Percentage-Point
(in millions)	Increase			Decrease
Effect on postretirement benefit obligation	$	107		$	(108	)
Effect on service and interest cost		8			(8	)
Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.2% compares to a ten-year actual return of 9.3%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 715 Aa-grade non-callable bonds at December 31, 2014.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
Investment Policies and Strategies
The financial position of PG&E Corporation's and the Utility's funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation's and the Utility's investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.
The trusts asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation's and the Utility's funded status volatility.  In addition to affecting the trusts's fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation's and the Utility's trusts hold significant allocations in long maturity fixed-income investments.  Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust's holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets.  Real assets include commodities futures, REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.
Target allocations for equity investments have generally declined in favor of longer-maturity fixed-income investments and real assets as a means of dampening future funded status volatility.  Derivative instruments such as equity index futures contracts are used to maintain existing equity exposure while adding exposure to fixed-income securities.  In addition, derivative instruments such as equity index futures and fixed income futures are used to rebalance the fixed income/equity allocation of the pension's portfolio.  Foreign currency exchange contracts are also used to hedge a portion of the currency of the global equity investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
	Pension Plan									PBOP Plans
	2015			2014			2013			2015		2014		2013
Global equity	25	%		25	%		25	%		31	%	30	%	28	%
Absolute return	5	%		5	%		5	%		3	%	3	%	4	%
Real assets	10	%		10	%		10	%		8	%	8	%	8	%
Fixed income	60	%		60	%		60	%		58	%	59	%	60	%
Total	100	%		100	%		100	%		100	%	100	%	100	%
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.
Fair Value Measurements
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2014 and 2013.
	Fair Value Measurements
	At December 31,
	2014											2013
(in millions)	Level 1			Level 2			Level 3			Total		Level 1		Level 2			Level 3		Total
Pension Plan:
Short-term investments	$	352		$	311		$	-		$	663	$	70	$	-	Te	$	-	$	70
Global equity		918			2,311			-			3,229		1,123		2,363			-		3,486
Absolute return		-			-			577			577		-		-			554		554
Real assets		620			-			675			1,295		562		-			544		1,106
Fixed-income		2,068			5,718			638			8,424		1,448		5,104			625		7,177
Total	$	3,958		$	8,340		$	1,890		$	14,188	$	3,203	$	7,467		$	1,723	$	12,393
PBOP Plans:
Short-term investments	$	28		$	-		$	-		$	28	$	31	$	-		$	-	$	31
Global equity		124			549			-			673		127		504			-		631
Absolute return		-			-			55			55		-		-			53		53
Real assets		72			-			49			121		67		-			38		105
Fixed-income		163			1,055			1			1,219		137		936			2		1,075
Total	$	387		$	1,604		$	105		$	2,096	$	362	$	1,440		$	93	$	1,895
Total plan assets at fair value										$	16,284								$	14,288
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $24 million and $131 million at December 31, 2014 and 2013, respectively.  These net assets and net liabilities were comprised primarily of cash, accounts receivable, accounts payable, and deferred taxes.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.
Short-Term Investments
Historically, short-term investments consisted primarily of commingled funds of U.S. government short-term securities that were considered Level 1 assets and valued at the net asset value of $1 per unit.
In 2014, PG&E began diversifying these short-term investments across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.
Global Equity
The global equity category includes investments in common stock, equity-index futures, and commingled funds comprised of equity securities spread across multiple industries and regions of the world.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.  Commingled funds are valued using a net asset value per share and are maintained by investment companies for large institutional investors and are not publicly traded.  Commingled funds are comprised primarily of underlying equity securities that are publicly traded on exchanges, and price quotes for the assets held by these funds are readily observable and available.  Commingled funds are categorized as Level 1 and Level 2 assets.
Absolute Return
The absolute return category includes portfolios of hedge funds that are valued using a net asset value per share based on a variety of proprietary and non-proprietary valuation methods, including unadjusted prices for publicly-traded securities in active markets.  Hedge funds are considered Level 3 assets.
Real Assets
The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.  Private real estate funds are valued using a net asset value per share derived using appraisals, pricing models, and valuation inputs that are unobservable and are considered Level 3 assets.
Fixed-Income
The fixed-income category includes U.S. government securities, corporate securities, and other fixed-income securities.
U.S. government fixed-income primarily consists of U.S. Treasury notes and U.S. government bonds that are valued based on quoted market prices or evaluated pricing data for similar securities adjusted for observable differences.  These securities are categorized as Level 1 or Level 2 assets.
Corporate fixed-income primarily includes investment grade bonds of U.S. issuers across multiple industries that are valued based on a compilation of primarily observable information or broker quotes in non-active markets.  The fair value of corporate bonds is determined using recently executed transactions, market price quotations (where observable), bond spreads or credit default swap spreads obtained from independent external parties such as vendors and brokers adjusted for any basis difference between cash and derivative instruments.  These securities are classified as Level 2 assets.  Corporate fixed-income also includes commingled funds that are valued using a net asset value per share and are comprised of corporate debt instruments.  Commingled funds are considered Level 2 assets.  Corporate fixed-income also includes privately placed debt portfolios which are valued using a net asset value per share using pricing models and valuation inputs that are unobservable and are considered Level 3 assets.
Other fixed-income primarily includes pass-through and asset-backed securities.  Pass-through securities are valued based on benchmark yields created using observable market inputs and are Level 2 assets.  Asset-backed securities are primarily valued based on broker quotes and are considered Level 2 assets.  Other fixed-income also includes municipal bonds and Treasury futures.  Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets.  Futures are valued based on unadjusted prices in active markets and are Level 1 assets.
Transfers Between Levels
Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  No material transfers between levels occurred in the years ended December 31, 2014 and 2013.
Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for pension and other benefit plans that have been classified as Level 3 for the years ended December 31, 2014 and 2013:
	Pension Plan
(in millions)	Absolute			Fixed-
For the year ended December 31, 2014	Return			Income			Real Assets			Total
Balance at beginning of year	$	554		$	625		$	544		$	1,723
Actual return on plan  assets:
Relating to assets still held at the reporting date		23			24			54			101
Relating to assets sold during the period		-			4			-			4
Purchases, issuances, sales, and settlements:
Purchases		-			1			78			79
Settlements		-			(16	)		(1	)		-17
Balance at end of year	$	577		$	638		$	675		$	1,890
	Pension Plan
(in millions)	Absolute			Fixed-
For the year ended December 31, 2013	Return			Income			Real Assets			Total
Balance at beginning of year	$	513		$	611		$	285		$	1,409
Actual return on plan assets:
Relating to assets still held at the reporting date		37			1			49			87
Relating to assets sold during the period		4			-			(3	)		1
Purchases, issuances, sales, and settlements:
Purchases		-			20			352			372
Settlements		-			(7	)		(139	)		-146
Balance at end of year	$	554		$	625		$	544		$	1,723
	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2014	Return			Income			Real Assets			Total
Balance at beginning of year	$	53		$	2			38		$	93
Actual return on plan  assets:
Relating to assets still held at the reporting date		2			-			4			6
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		-			-			7			7
Settlements		-			(1	)		-			-1
Balance at end of year	$	55		$	1		$	49		$	105
	PBOP Plans
(in millions)	Absolute			Fixed-
For the year ended December 31, 2013	Return			Income			Real Assets			Total
Balance at beginning of year	$	49		$	1			28		$	78
Actual return on plan assets:
Relating to assets still held at the reporting date		4			-			3			7
Relating to assets sold during the period		-			-			-			-
Purchases, issuances, sales, and settlements:
Purchases		12			1			21			34
Settlements		(12	)		-			(14	)		-26
Balance at end of year	$	53		$	2		$	38		$	93
There were no material transfers out of Level 3 in 2014 and 2013.
Cash Flow Information
Employer Contributions
PG&E Corporation and the Utility contributed $332 million to the pension benefit plans and $57 million to the other benefit plans in 2014.  These contributions are consistent with PG&E Corporation's and the Utility's funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2014.  The Utility's pension benefits met all the funding requirements under ERISA.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $61 million to the pension plan and other postretirement benefit plans, respectively, for 2015.
Benefits Payments and Receipts
As of December 31, 2014, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
	Pension			PBOP			Federal
(in millions)	Plan			Plans			Subsidy
2015	$	653		$	91		$	(7	)
2016		696			96			(8	)
2017		737			102			(8	)
2018		775			109			(9	)
2019		812			115			(10	)
Thereafter in the succeeding five years		4,545			614			(29	)
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.
Retirement Savings Plan
PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation's Consolidated Statements of Income were $80 million, $71 million, and $67 million in 2014, 2013, and 2012, respectively.
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

Resolution_Of_Remaining_Chapte

Resolution Of Remaining Chapter 11 Disputed Claims	12 Months Ended
	Dec. 31, 2014
Resolution Of Remaining Chapter 11 Disputed Claims	NOTE 12: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS
	Various electricity suppliers filed claims in the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility's customers between May 2000 and June 2001.  These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including governmental entities, for overcharges incurred in the CAISO and the California Power Exchange wholesale electricity markets during this period.
	While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers.  The Utility entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility's refund claims against these electricity suppliers.  These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC.
	Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.
	Interest accrues on the remaining net disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance.  Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers in rates, these collections are not held in escrow.  If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected.  The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.
	In July 2014, a settlement agreement between the Utility and an electric supplier became effective, resolving a portion of the Utility's disputed claims.  The settlement will result in refunds to customers of $312 million and will be returned through rates in future periods.  The Utility is uncertain when and how the remaining disputed claims will be resolved.
	In August 2014, the Utility received a letter from the California Power Exchange clarifying its ultimate intent to offset the Utility's remaining disputed claims principal and interest balances through net settlement.  Accordingly, the Utility has presented $434 million of net Disputed claims and customer refunds on the Consolidated Balance Sheets at December 31, 2014, which includes both principal and interest.  At December 31, 2013, the Consolidated Balance Sheets reflected $154 million of Disputed claims and customer refunds and $710 million of Interest payable.
	At December 31, 2014 and 2013, the Utility held $291 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability.  These amounts are included within restricted cash on the Consolidated Balance Sheets.

Related_Party_Agreements_And_T

Related Party Agreements And Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Agreements And Transactions
	NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS
	The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
	The Utility's significant related party transactions were:
		Year Ended December 31,
	(in millions)	2014		2013		2012
	Utility revenues from:
	Administrative services provided to PG&E Corporation	$	5	$	7	$	7
	Utility expenses from:
	Administrative services received from PG&E Corporation	$	54	$	45	$	50
	Utility employee benefit due to PG&E Corporation		70		57		51
	At December 31, 2014 and 2013, the Utility had receivables of $17Error! Bookmark not defined. million and $22 million, respectively, from PG&E Corporation included in accounts receivable - other and other noncurrent assets - other on the Utility's Consolidated Balance Sheets, and payables of $20 million and $17 million, respectively, to PG&E Corporation included in accounts payable - other on the Utility's Consolidated Balance Sheets.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies
	NOTE 14: 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.  The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below.   PG&E Corporation has financial commitments described in “Other Commitments” below.
	Enforcement and Litigation Matters
	On September 9, 2010, a natural gas transmission pipeline owned and operated by the Utility ruptured in San Bruno, California.  The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage.  PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows have been materially affected by the costs the Utility has incurred related to shareholder funded safety work, the ongoing regulatory investigations, and civil lawsuits that commenced following the San Bruno accident.
	CPUC Investigations Regarding the Utility's Gas Transmission System and the San Bruno Accident
	There are three CPUC investigative enforcement proceedings pending against the Utility.  These investigations relate to (1) the Utility's safety recordkeeping for its natural gas transmission system, (2) the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility's pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident.
	On September 2, 2014, the assigned CPUC ALJs issued their presiding officer decisions in the three investigative enforcement proceedings pending against the Utility related to the Utility's natural gas transmission operations and practices and the San Bruno accident.  The ALJs determined that the Utility committed approximately 3,700 violations of law, rules and regulations.  The ALJs jointly issued a decision calling for total fines and disallowances of $1.4 billion on the Utility to address all violations, allocated as follows: (1) $950 million fine to be paid to the State General Fund, (2) $400 million refund to ratepayers of previously authorized revenues, and (3) remedial measures that the ALJs estimate will cost the Utility at least $50 million.  The ALJs' decisions are not the final decisions of the CPUC.  Three CPUC Commissioners have requested that the CPUC review the decisions.  It is possible that one or more Commissioners will issue an alternate penalty decision for consideration by the CPUC.  In addition, the Utility and other parties, including the SED, TURN, the ORA, the City and County of San Francisco, and the City of San Bruno have appealed the presiding officer decisions.
	In its appeals, the Utility argued that the penalties imposed and the findings and conclusions on which they are based do not meet applicable legal standards, are based on the misapplication of California law and regulations, and are unconstitutional.  The Utility has asked the CPUC to order the Utility to pay a significantly reduced penalty that is reasonable and proportionate in light of the nature of the violations and that takes into account the substantial unrecovered amounts the Utility has already spent and forecasts that it will spend on gas system safety.  The Utility requested that it be allowed 180 days to raise the funds it may be ordered to pay to the State General Fund rather than the 40 days specified in the decision.  The Utility also argued that the entire penalty should go toward funding investments in the Utility's gas transmission system.  TURN, the ORA, and the City and County of San Francisco jointly filed an appeal urging the CPUC to disallow the Utility's recovery of remaining PSEP costs of $877 million and to require the Utility to pay $473 million to the State General Fund.  These parties also argue that the record in the investigative proceedings would support an even larger penalty than stated in the decision.  The City of San Bruno appealed the rejection of its proposals for the appointment of an independent monitor to oversee the Utility's natural gas operations and for the establishment of a pipeline safety trust.  It is uncertain when the final outcome of the investigations will be determined.
	While the various appeals and requests for review of the presiding officer decisions are unresolved there continues to be significant uncertainty about the ultimate forms and amounts of penalties (including fines) that will be imposed on the Utility.  At December 31, 2014, the Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable.  The impact on PG&E Corporation's and the Utility's Consolidated Financial Statements will depend on the amounts and forms of penalties that are ultimately adopted by the CPUC.  Fines payable to the State General Fund or refunds of revenues would be charged to net income when it is probable that such fines or refunds will be imposed and the amounts can be reasonably estimated.  A disallowance of previously authorized and incurred capital costs would be charged to net income when the disallowance is probable and the amount can be reasonably estimated.  Penalties in the form of future disallowed costs would be charged to net income in the period during which the actual costs are incurred.  Although PG&E Corporation and the Utility believe it is probable that the CPUC will impose total penalties materially in excess of the $200 million previously accrued, they are unable to make a better estimate due to the variety of potential combinations of amounts and forms of penalties that could ultimately be imposed on the Utility and uncertainty about the timing of recognition.  PG&E Corporation and the Utility believe the final outcome of the investigations will have a material impact on their financial condition, results of operations, and cash flows.
	Federal Criminal Indictment
	On July 29, 2014, a federal grand jury in the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court replacing the indictment that had been returned on April 1, 2014.  The superseding indictment charges 27 felony counts (increased from 12 counts charged in the original indictment) alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB's investigation into the cause of the San Bruno accident.  The maximum statutory fine for each felony count is $500,000, for total fines of $14 million.  The superseding indictment also alleges an alternative fine under the Alternative Fines Act which states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”  Based on the superseding indictment's allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternate fine would be approximately $1.13 billion.
	The Utility entered a plea of not guilty.  The Utility believes that criminal charges and the alternate fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB's investigation, as alleged in the superseding indictment.  A status conference is scheduled to be held in court on March 9, 2015.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their consolidated financial statements as such amounts are not considered to be probable.
	Other Enforcement Matters
	PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters.
	Improper CPUC Communications
	On September 15, 2014, the Utility notified the CPUC and the ALJ overseeing the 2015 GT&S rate case that it believes certain communications between the Utility and CPUC personnel relating to the 2015 GT&S rate case violated the CPUC's rules regarding ex parte communications.  Ex parte communications include any communication between a decision maker and an interested person concerning substantive issues in certain identified categories of formal proceedings before the CPUC.  (The Utility discovered the communications as part of an internal review of communications between the Utility and the CPUC undertaken after the City of San Bruno filed a motion at the CPUC in late July 2014 alleging that various email communications between the Utility's employees and CPUC personnel violated the ex parte communication rules with respect to the pending CPUC investigative enforcement proceedings against the Utility.  The Utility believes that the communications cited by San Bruno in its July 2014 motion are not prohibited ex parte communications.  The CPUC has not yet addressed San Bruno's motion and its request that the CPUC penalize the Utility.)
	On November 20, 2014, the CPUC issued a decision imposing a fine of $1.05 million on the Utility and disallowing up to the entire amount of the revenue increase that would have been collected from ratepayers over the five-month period between March 2015 and August 2015.  The exact amount of the revenue disallowance will be determined in the CPUC's final decision in the GT&S rate case expected to be issued in August 2015.  In addition, the decision prohibits the Utility from engaging in any oral or written ex parte communications, as well as procedural communications, with Commissioners or their advisors in any rate-setting proceeding and requires the Utility to report communications with senior CPUC staff, in any rate-setting or adjudicatory proceeding before the CPUC, for one year from the effective date of the decision.  With respect to the GT&S rate case, the ban will be in effect until the resolution of the GT&S rate case or one year from the effective date of the decision, whichever is later. The Utility and other parties have requested that the CPUC reconsider its decision.  The ORA, TURN, and the City of San Bruno argue that the applicable law supports the imposition of a fine ranging from $2.5 million to $250 million.  It is uncertain when the CPUC will address these applications for rehearing.
	In October and December 2014, the Utility notified the CPUC of additional email communications between the Utility and CPUC personnel regarding various matters (not limited to the GT&S rate case), that the Utility believes may constitute or describe ex parte communications.  As of January 30, 2015, the Utility had provided copies of approximately 65,000 email communications between the CPUC and the Utility to the CPUC and the City of San Bruno.  It is uncertain whether any of these email communications will be challenged as prohibited ex parte communications or as improper or illegal.
	The Utility believes it is probable that CPUC enforcement actions will be taken in connection with these additional ex parte communications but is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC's wide discretion and the number of factors that can be considered in determining the final penalties.  It is also possible that other parties may request that the CPUC rescind decisions or take other action in open or closed proceedings to address ex parte communications that they may allege occurred regarding substantive issues in those proceedings.  For example, TURN and the ORA have filed petitions to request that the CPUC rescind a $29 million shareholder incentive awarded to the Utility in 2010 for the successful implementation of the Utility's 2006-2008 energy efficiency programs based on their allegation that prohibited ex parte communications tainted the decision.  It is uncertain whether the CPUC will grant these petitions or whether parties will request the CPUC to take action in other proceedings. It is also uncertain whether the ex parte communication issues will affect the outcome of other pending legal matters, ratemaking or regulatory proceedings, investigations and enforcement matters.
	Finally, the U.S. Attorney's Office in San Francisco and the California Attorney General's office have begun investigations in connection with these communications.  The Utility is cooperating with the federal and state investigators.  It is uncertain whether any charges will be brought against the Utility.
	Gas Safety Citation Program
	The SED, the division of the CPUC primarily responsible for overseeing the safety of electric and natural gas utility operations in California, conducts periodic audits of the Utility's operating practices and investigates potential violations.  In December 2011 the CPUC adopted a gas safety citation program and delegated authority to the SED to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices.  The California gas corporations are required to inform the SED of self-identified or self-corrected violations.  The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken.
	Since the gas safety program became effective, the Utility has filed approximately 84 self-reports and the SED has imposed fines ranging from $50,000 to $16.8 million (including the $10.85 million fine related to an explosion in Carmel, California that is discussed below) for violations identified through self-reports, SED investigations and audits.  The SED recently has stated that it will not conduct further investigations into 65 self-reports the Utility had filed through December 31, 2014.  The Utility believes it is probable that the SED will impose fines or take other enforcement action with respect to some of the Utility's remaining self-reports or other self-reports that the Utility has filed since January 1, 2015.  The Utility believes it is reasonably possible that the SED will impose fines on the Utility based on allegations of noncompliance that are contained in some of the SED's audits.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.
	Carmel Incident
	On March 3, 2014, a vacant house in Carmel, California was severely damaged due to a natural gas explosion while the Utility's employees were performing work to upgrade the main natural gas distribution pipeline in the area.  There were no injuries or fatalities.  The SED conducted an investigation of the incident and alleged that the Utility committed two violations of certain natural gas safety regulations by failing to follow procedures to update records, to provide its welding crew with accurate information, and to take steps to make safe any actual or potential hazard to life or property.  On November 20, 2014, the SED issued a citation to the Utility that included a fine of $10.85 million for these alleged violations.  The Utility recorded this amount as an expense for 2014.  The Utility has appealed the citation to the CPUC.  The SED has requested that the CPUC dismiss the Utility's appeal as untimely.  The CPUC has not yet addressed the SED's request.  In addition, the Utility was informed that the U.S. Attorney's Office was investigating the Carmel incident.  It is uncertain whether any charges will be brought against the Utility.
	CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping
	On November 20, 2014, the CPUC issued an order instituting a new investigation into whether the Utility violated applicable laws pertaining to record-keeping practices for its natural gas distribution service and facilities.  The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found.
	In particular, the order cites the SED's investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014.  (See “Carmel Incident” above.)  On December 22, 2014, as directed by the CPUC, the Utility submitted a report that explained why the Utility believes the SED's investigative findings do not constitute violations of law and also outlined the various programs, measures and actions the Utility has undertaken to continuously improve its distribution record keeping practices.
	PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose fines on the Utility or take other enforcement action in connection with this matter, but are unable to reasonably estimate the amount or range of future loss contingencies.
	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 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 has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years.  The SED has not addressed the Utility's proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility's failure to continuously survey its system and remove encroachments.
	Pipeline Safety Enhancement Plan
	On November 20, 2014, the CPUC approved the settlement agreement (submitted in July 2014) among the Utility, ORA, and TURN to resolve the Utility's PSEP Update application.  The CPUC decision approved total PSEP-related revenue requirements (2012-2014) of $223 million, subject to refund, that reflect a $23 million reduction to expense funding, as compared to the amount requested in the Utility's application.  (PG&E Corporation's and the Utility's 2014 consolidated financial statements reflect this reduction.)  In accordance with the settlement agreement, the CPUC decision did not adopt any reduction to the Utility's request for authorization of total PSEP capital costs of $766 million.  The Utility previously recorded cumulative charges of $549 million for PSEP-related capital costs that are expected to exceed the authorized amount.  During the quarter ended December 31, 2014, the Utility recorded an additional charge for $116 million for PSEP capital costs that are expected to exceed the authorized amounts, bringing the total cumulative charge to $665 million.  $209 million is expected to be incurred in 2015 and beyond.  At December 31, 2014, approximately $549 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Consolidated Balance Sheets.  The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected or if the Utility was required to refund previously authorized PSEP-related capital and expense amounts and/or revenue requirements.
	Other Legal and Regulatory Contingencies
	PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits.  In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations.  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.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessment of whether a loss is probable or reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation's and the Utility's policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.
	Accruals for other legal and regulatory contingencies (excluding amounts related to natural gas matters above) totaled $55 million at December 31, 2014 and $43 million at December 31, 2013.  These amounts are included in other current liabilities in the Consolidated Balance Sheets.  The estimated reasonably possible range of loss for these matters in excess of the recorded accrual is not material.  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.
	Environmental Remediation Contingencies
	Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment.  The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable and the Utility can reasonably estimate the loss or a range of probable amounts.  The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount.  Amounts recorded are not discounted to their present value.  The Utility's environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:
		Balance at
	(in millions)	31-Dec-14		31-Dec-13
	Topock natural gas compressor station (1)	$	291	$	264
	Hinkley natural gas compressor station (1)		158		190
	Former manufactured gas plant sites owned by the Utility or third parties		257		184
	Utility-owned generation facilities (other than fossil fuel-fired),		150		160
	other facilities, and third-party disposal sites
	Fossil fuel-fired generation facilities and sites		98		102
	Total environmental remediation liability	$	954	$	900
	(1) See “Natural Gas Compressor Station Sites” below.
	At December 31, 2014 the Utility expected to recover $663 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review.  The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.
	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 Hinkley, California and is referred to below as the “Hinkley site.”  Another station is located near Needles, California and is referred to below as the “Topock site.”  The Utility is also required to take measures to abate the effects of the contamination on the environment.
	Hinkley Site
	The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume.  The Utility's remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the Regional Board.  In 2013, the Regional Board certified a final environmental report evaluating the Utility's proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts.  On January 22, 2015, the Regional Board issued a preliminary draft clean-up and abatement order that proposes that the Utility continue and  improve its remedial treatment methods evaluated in the environmental report, along with a proposed monitoring and reporting program and proposed deadlines in 2021 and 2026 to meet specified interim clean-up targets.  Comments by the Utility and the public are due on March 13, 2015.  The Regional Board is tentatively scheduled to consider final adoption of the clean-up and abatement order at its September 2015 meeting.
	The Utility's environmental remediation liability at December 31, 2014 reflects the Utility's best estimate of probable future costs associated with its final remediation plan and interim remediation measures.  Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, and the nature and extent of the chromium contamination.  As the comment process continues and the final order and permits are issued, the Utility expects to obtain additional information about the total costs associated with implementing the final remedy and performing related activities and the best estimate of future costs may be subject to further changes.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.
	Topock Site
	The Utility's remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior.  In September 2014, the Utility submitted its 90% remedial design plan to regulatory authorities and expects to submit its final remedial design plan in mid-2015, which would seek approval to begin construction of an in-situ groundwater treatment system that will convert hexavalent chromium into a non-toxic and non-soluble form of chromium.  The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River.  The Utility's environmental remediation liability at December 31, 2014 reflects its best estimate of probable future costs associated with its final remediation plan.  Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility's required time frame for remediation.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.
	Reasonably Possible Environmental Contingencies
	Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.8 billion (including amounts related to the Hinkley and Topock sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations during the period in which they are recorded.
	Nuclear Insurance
	The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities.  NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility's two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.6 billion per non-nuclear incident for Diablo Canyon.  Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.  If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, as of December 31, 2014, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $51 million.
	NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants.  Certain acts of terrorism may be “certified” by the Secretary of the Treasury.  If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss.  In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.
	Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $13.6 billion.  The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon.  The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors.  The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 million per incident.  Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.  The next scheduled adjustment is due on or before September 10, 2018.
	The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator's facility.  The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.  In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the liability insurance.
Purchase Commitments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2014:
	Power Purchase Agreements
	Renewable		Qualifying				Natural		Nuclear
(in millions)	Energy		Facility		Other		Gas		Fuel		Total
2015	$	2,145	$	601	$	820	$	544	$	138	$	4,248
2016		2,185		525		766		164		129		3,769
2017		2,187		418		758		107		131		3,601
2018		2,063		382		731		107		115		3,398
2019		2,053		304		706		107		109		3,279
Thereafter		30,289		1,217		2,390		648		429		34,973
Total purchase commitments	$	40,922	$	3,447	$	6,171	$	1,677	$	1,051	$	53,268
Third-Party Power Purchase Agreements
In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.
Renewable Energy Power Purchase Agreements - In order to comply with California's RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California's requirement.  The Utility's obligations under a significant portion of these agreements are contingent on the third party's construction of new generation facilities, which are expected to grow significantly.  As of December 31, 2014, renewable energy contracts expire at various dates between 2016 and 2043.
Qualifying Facility Power Purchase Agreement - The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law.  Several of these agreements are treated as capital leases.  At December 31, 2014 and 2013, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $74 million and $97 million including accumulated amortization of $128 million and $176 million.  The present value of the future minimum lease payments due under these agreements included $20 million and $23 million in Current Liabilities and $54 million and $74 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2014, QF contracts in operation expire at various dates between 2015 and 2028 .
Other Power Purchase Agreements - The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility's obligation under a portion of these agreements is contingent on the third parties' development of new generation facilities to provide capacity and energy products to the Utility.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power. As of December 31, 2014, other power purchase agreements expire at various dates between 2015 and 2033.
The costs incurred for all power purchases and electric capacity amounted to $3.6 billion in 2014, $3.0 billion in 2013, and $2.3 billion in 2012.
Natural Gas Supply, Transportation, and Storage Commitments
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  These purchase agreements expire at various dates between 2015 and 2026.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins.  In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers' loads.
Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $1.4 billion in 2014, $1.6 billion in 2013, and $1.3 billion in 2012.
Nuclear Fuel Agreements
The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2015 and 2025 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.
Payments for nuclear fuel amounted to $105 million in 2014, $162 million in 2013, and $118 million in 2012.
Other Commitments
PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2015 and 2052.  At December 31, 2014, the future minimum payments related to these commitments were as follows:
(in millions)	Operating Leases
2015	$	44
2016		43
2017		33
2018		30
2019		27
Thereafter		183
Total minimum lease payments	$	360
Payments for other commitments related to operating leases amounted to $42 million in 2014, $40 million in 2013, and $32 million in 2012.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent.  The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index.  Most leases contain extension operations ranging between one and five years.

Schedule_I_Condensed_Financial

Schedule I - Condensed Financial Information Of Parent	12 Months Ended
	Dec. 31, 2014
Schedule I - Condensed Financial Information Of Parent
	PG&E CORPORATION
	SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
	CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
			Years Ended December 31,
	(in millions, except per share amounts)		2014			2013			2012
	Administrative service revenue	$	51		$	41		$	43
	Operating expenses		(53	)		(42	)		(41	)
	Interest income		1			1			1
	Interest expense		(14	)		(25	)		(22	)
	Other expense		(1	)		(57	)		(39	)
	Equity in earnings of subsidiaries		1,413			848			817
	Income before income taxes		1,397			766			759
	Income tax benefit		39			48			57
	Net income	$	1,436		$	814		$	816
	Other Comprehensive Income
	Pension and other postretirement benefit plans obligations (net of taxes of $10,
	$80, and $72, at respective dates)	$	(14	)	$	113		$	108
	Net change in investments (net of taxes of $17, $26, and $3, at respective dates)		(25	)		38			4
	Total other comprehensive income (loss)		(39	)		151			112
	Comprehensive Income	$	1,397		$	965		$	928
	Weighted Average Common Shares Outstanding, Basic		468			444			424
	Weighted Average Common Shares Outstanding, Diluted		470			445			425
	Earnings per common share, basic	$	3.07		$	1.83		$	1.92
	Earnings per common share, diluted	$	3.06		$	1.83		$	1.92
	PG&E CORPORATION
	SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
	CONDENSED BALANCE SHEETS
		Balance at December 31,
	(in millions)	2014			2013
	ASSETS
	Current Assets
	Cash and cash equivalents	$	96		$	231
	Advances to affiliates		31			30
	Income taxes receivable		29			13
	Other		38			86
	Total current assets		194			360
	Noncurrent Assets
	Equipment		2			2
	Accumulated depreciation		(1	)		(1	)
	Net equipment		1			1
	Investments in subsidiaries		16,003			14,711
	Other investments		117			110
	Income taxes receivable		-			5
	Deferred income taxes		260			188
	Total noncurrent assets		16,381			15,015
	Total Assets	$	16,575		$	15,375
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current Liabilities
	Short-term borrowings	$	-		$	260
	Long-term debt classified as current		-			350
	Accounts payable - other		67			66
	Other		269			230
	Total current liabilities		336			906
	Noncurrent Liabilities
	Long-term debt		350			-
	Other		141			127
	Total noncurrent liabilities		491			127
	Common Shareholders' Equity
	Common stock		10,421			9,550
	Reinvested earnings		5,316			4,742
	Accumulated other comprehensive loss		11			50
	Total common shareholders' equity		15,748			14,342
	Total Liabilities and Shareholders' Equity	$	16,575		$	15,375
PG&E CORPORATION
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
			Year Ended December 31,
			2014			2013			2012
Cash Flows from Operating Activities:
Net income			$	1,436		$	814		$	816
Adjustments to reconcile net income to net cash provided by operating activities:
Stock-based compensation amortization				65			54			51
Equity in earnings of subsidiaries				(1,413	)		(848	)		(817	)
Deferred income taxes and tax credits, net				(72	)		(10	)		(31	)
Noncurrent income taxes receivable/payable				5			-			(6	)
Current income taxes receivable/payable				(16	)		20			(82	)
Other				43			(20	)		20
Net cash provided by (used in) operating activities				48			10			(49)
Cash Flows From Investing Activities:
Investment in subsidiaries				(978	)		(1,371	)		(1,023	)
Dividends received from subsidiaries (1)				716			716			716
Proceeds from tax equity investments				368			275			228
Other				-			(8	)		-
Net cash provided by (used in) investing activities				106			-388			(79)
Cash Flows From Financing Activities:
Borrowings under revolving credit facilities				-			140			120
Repayments under revolving credit facilities				(260	)		-			-
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014				347			-			-
Repayments of long-term debt				(350	)		-			-
Common stock issued				802			1,045			751
Common stock dividends paid (2)				(828	)		(782	)		(746	)
Other				-			(1	)		1
Net cash provided by (used in) financing activities				-289			402			126
Net change in cash and cash equivalents				-135			24			-2
Cash and cash equivalents at January 1				231			207			209
Cash and cash equivalents at December 31			$	96		$	231		$	207
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized			$	(15	)	$	(23	)	$	(20	)
Income taxes, net				1			21			(60	)
Supplemental disclosures of noncash investing and financing
activities
Noncash common stock issuances				21			22			22
Common stock dividends declared but not yet paid			$	217		$	208		$	196
-1	Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
-2	In January, April, July, and October of 2014, 2013, and 2012, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule_II_Consolidated_Valua

Schedule II - Consolidated Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Schedule II - Consolidated Valuation And Qualifying Accounts	PG&E Corporation
	SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
	For the Years Ended December 31, 2014, 2013, and 2012
	(in millions)			Additions
	Description		Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
	Valuation and qualifying accounts deducted from assets:
	2014:
	Allowance for uncollectible accounts (1)	$	80	$	41	$	2	$	57	$	66
	2013:
	Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80
	2012:
	Allowance for uncollectible accounts (1)	$	81	$	66	$	-	$	60	$	87
	(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
	(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
	Pacific Gas and Electric Company
	SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
	For the Years Ended December 31, 2014, 2013, and 2012
	(in millions)			Additions
	Description		Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
	Valuation and qualifying accounts deducted from assets:
	2014:
	Allowance for uncollectible accounts (1)	$	80	$	41	$	2	$	57	$	66
	2013:
	Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80
	2012:
	Allowance for uncollectible accounts (1)	$	81	$	66	$	-	$	60	$	87
	(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
	(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Regulation And Regulated Operations	Regulation and Regulated Operations
	As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility's costs of service.  The Utility's ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility's electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
	The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below.
	Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility's operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
Revenue Recognition	Revenue Recognition
	The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements.
	The CPUC authorizes most of the Utility's revenues in the Utility's GRC and its GT&S rate cases, which generally occur every three years.  In general, the Utility's ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility's sales of electricity and natural gas services.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, revenue is recognized ratably over the year.
	The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.
	The FERC authorizes the Utility's revenue requirements in periodic (often annual) TO rate cases.  The Utility's ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility's electricity sales, and revenue is recognized only for amounts billed and unbilled.
Cash And Cash Equivalents	Cash and Cash Equivalents
	Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.
Restricted Cash	Restricted Cash
	Restricted cash consists primarily of the Utility's cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code.  (See Note 12 below.)
Allowance For Doubtful Accounts Receivable	Allowance for Doubtful Accounts Receivable
	PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories
	Inventories
	Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground represents gas that is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.
	The Utility also purchases GHG emission allowances that are recorded as inventory.  They are carried at weighted-average cost and included in current assets - other and other noncurrent assets - other on the Consolidated Balance Sheets.  The costs of the GHG emissions are expensed and recoverable through rates.
Property, Plant, And Equipment
	Property, Plant, and Equipment
	Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.) The Utility's total estimated useful lives and balances of its property, plant, and equipment were as follows:
		Estimated Useful		Balance at December 31,
	(in millions, except estimated useful lives)	Lives (years)		2014			2013
	Electricity generating facilities (1)	10 to 100		$	9,374		$	9,116
	Electricity distribution facilities	10 to 55			26,633			25,333
	Electricity transmission facilities	10 to 70			9,155			8,429
	Natural gas distribution facilities	20 to 60			9,741			9,117
	Natural gas transportation and storage facilities	7 to 65			5,937			5,265
	Construction work in progress				2,220			1,834
	Total property, plant, and equipment				63,060			59,094
	Accumulated depreciation				(19,120	)		(17,843	)
	Net property, plant, and equipment			$	43,940		$	41,251
	(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)
	The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility's composite depreciation rates were 3.77% in 2014, 3.51% in 2013, and 3.63% in 2012.  The useful lives of the Utility's property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC	AFUDC
	AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $45 million and $100 million during 2014, $47 million and $101 million during 2013, and $49 million and $107 million during 2012.
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 Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.
	The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2014 and 2013.  The estimated undiscounted nuclear decommissioning cost for the Utility's nuclear power plants was $3.5 billion at December 31, 2014 and 2013 (or $6.1 billion in future dollars).  These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.
	The following table summarizes the changes in ARO liability during 2014 and 2013:
	(in millions)		2014			2013
	ARO liability at beginning of year	$	3,538		$	2,919
	Revision in estimated cash flows		(16	)		596
	Accretion		163			130
	Liabilities settled		(110	)		(107	)
	ARO liability at end of year	$	3,575		$	3,538
	The Utility has not recorded a liability related to certain ARO's for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.
Disallowance of Plant Costs	Disallowance of Plant Costs
	PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  The Utility recorded charges of $116 million, $196 million and $353 million in 2014, 2013, and 2012, respectively, for PSEP capital costs that are expected to exceed the CPUC's authorized levels or that are specifically disallowed.  (See “Enforcement and Litigation Matters” in Note 14 below).
Nuclear Decommissioning Trusts	Nuclear Decommissioning Trusts
	The Utility's nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
	The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.”  Since the Utility's nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments.  Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility's earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.
Gains And Losses On Debt Extinguishments	Gains and Losses on Debt Extinguishments
	Deferred gains and losses on debt extinguishments are recorded to regulatory assets in current assets and regulatory assets in other noncurrent assets on the Consolidated Balance Sheets. Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates.  PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $135 million, $157 million, and $163 million at December 31, 2014, 2013, and 2012, respectively.  The amortization expense related to this loss was $22 million in 2014 and $23 million in both 2013 and 2012.
Variable Interest Entities	Variable Interest Entities
	A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
	Some of the counterparties to the Utility's power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2014, it assessed whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE's gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE's performance, such as dispatch rights and operating and maintenance activities.  The Utility's financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2014, it did not consolidate any of them.
	PG&E Corporation affiliates previously entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that were considered VIEs.  Since PG&E Corporation was not the primary beneficiary of any of these VIEs, they were not consolidated.  On July 2, 2014, PG&E Corporation disposed of its interest in the tax equity agreements and has no remaining commitment to fund these agreements.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment		Estimated Useful		Balance at December 31,
	(in millions, except estimated useful lives)	Lives (years)		2014			2013
	Electricity generating facilities (1)	10 to 100		$	9,374		$	9,116
	Electricity distribution facilities	10 to 55			26,633			25,333
	Electricity transmission facilities	10 to 70			9,155			8,429
	Natural gas distribution facilities	20 to 60			9,741			9,117
	Natural gas transportation and storage facilities	7 to 65			5,937			5,265
	Construction work in progress				2,220			1,834
	Total property, plant, and equipment				63,060			59,094
	Accumulated depreciation				(19,120	)		(17,843	)
	Net property, plant, and equipment			$	43,940		$	41,251
	(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)
Schedule Of Changes In Asset Retirement Obligations	(in millions)		2014			2013
	ARO liability at beginning of year	$	3,538		$	2,919
	Revision in estimated cash flows		(16	)		596
	Accretion		163			130
	Liabilities settled		(110	)		(107	)
	ARO liability at end of year	$	3,575		$	3,538
Reclassification Out Of Accumulated Other Comprehensive Income TableText Block	The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:
		Pension			Other			Other
	(in millions, net of income tax)	Benefits			Benefits			Investments			Total
	Beginning balance	$	(7	)		15			42			50
	Other comprehensive income before reclassifications:
	Change in investments
	(net of taxes of $0, $0, and $4, respectively)		-			-			5			5
	Unrecognized net actuarial loss
	(net of taxes of $404, $19, and $0, respectively)		(588	)		(28	)		-			(616	)
	Unrecognized prior service cost
	(net of taxes of $0, $0, and $0, respectively)		1			-			-			1
	Transfer to regulatory account
	(net of taxes of $394, $19, and $0, respectively)		573			28			-			601
	Amounts reclassified from other comprehensive income:
	Amortization of prior service cost
	(net of taxes of $8, $9, and $0, respectively) (1)		12			14			-			26
	Amortization of net actuarial loss
	(net of taxes of $1, $1, and $0, respectively) (1)		1			1			-			2
	Transfer to regulatory account
	(net of taxes of $9, $10, and $0, respectively) (1)		(13	)		(15	)		-			(28	)
	Realized gain on investments
	(net of taxes of $0, $0, and $20, respectively)		-			-			(30	)		(30	)
	Net current period other comprehensive loss		-14			-			-25			-39
	Ending balance	$	-21			15			17			11
	(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)
	The changes, net of income tax, in PG&E Corporation's accumulated other comprehensive income (loss) for the year ended December 31, 2013 consisted of the following:
		Pension			Other			Other
	(in millions, net of income tax)	Benefits			Benefits			Investments			Total
	Beginning balance	$	(28	)		(77	)		4			(101	)
	Other comprehensive income before reclassifications:
	Change in investments
	(net of taxes of $0, $0, and $26, respectively)		-			-			38			38
	Unrecognized net actuarial loss
	(net of taxes of $804, $35, and $0, respectively)		1,169			45			-			1,214
	Transfer to regulatory account
	(net of taxes of $790, $22, and $0, respectively)		(1,150	)		31			-			(1,119	)
	Amounts reclassified from other comprehensive income: (1)
	Amortization of prior service cost
	(net of taxes of $8, $10, and $0, respectively)		12			13			-			25
	Amortization of net actuarial loss
	(net of taxes of $45, $3, and $0, respectively)		66			3			-			69
	Transfer to regulatory account
	(net of taxes of $54, $0, and $0, respectively)		(76	)		-			-			(76	)
	Net current period other comprehensive income		21			92			38			151
	Ending balance	$	-7			15			42			50
	(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

Regulatory_Assets_Liabilities_1

Regulatory Assets, Liabilities, And Balancing Accounts (Tables)	12 Months Ended
	Dec. 31, 2014
Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]
Long-Term Regulatory Assets
	NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	Regulatory Assets
		Balance at December 31,				Recovery
	(in millions)	2014		2013		Period
	Pension benefits (1)	$	2,347	$	1,444	N/A (4)
	Deferred income taxes (1)		2,390		1,835	47 years
	Utility retained generation (2)		456		503	11 years
	Environmental compliance costs (1)		717		628	32 years
	Price risk management (1)		127		106	10 years
	Electromechanical meters (3)		70		135	2 years
	Unamortized loss, net of gain, on reacquired debt (1)		113		135	12 years
	Other		102		127	Various
	Total long-term regulatory assets	$	6,322	$	4,913
	(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets.  (See Note 11 below.)
	(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility's proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility's retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
	(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.
	(4) The Utility expects to continuously recover pension benefits.
Long-Term Regulatory Liabilities		Balance at December 31,
	(in millions)	2014		2013
	Cost of removal obligations (1)	$	4,211	$	3,844
	Recoveries in excess of AROs (2)		754		748
	Public purpose programs (3)		701		587
	Other		624		481
	Total long-term regulatory liabilities	$	6,290	$	5,660
	(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
	(2) Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear generation facilities.  Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments.  (See Note 10 below.)
	(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
Current Regulatory Balancing Accounts Receivable		Receivable
		Balance at December 31,
	(in millions)	2014		2013
	Electric distribution	$	344	$	102
	Utility generation		261		57
	Gas distribution		566		70
	Energy procurement		608		410
	Public purpose programs		109		56
	Other		378		429
	Total regulatory balancing accounts receivable	$	2,266	$	1,124
Current Regulatory Balancing Accounts Payable		Payable
		Balance at December 31,
	(in millions)	2014		2013
	Energy procurement	$	188	$	298
	Public purpose programs		154		171
	Other (1)		748		539
	Total regulatory balancing accounts payable	$	1,090	$	1,008
	(1) At December 31, 2014, Other regulatory balancing accounts payable mostly includes energy supplier settlements.  (See Note 12 for additional details.)

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt [Abstract]
Schedule Of Long-Term Debt		December 31,
	(in millions)	2014			2013
	PG&E Corporation
	Senior notes, 5.75%, due 2014		-			350
	Senior notes, 2.40%, due 2019		350			-
	Less: current portion		-			(350	)
	Total senior notes		350			-
	Total PG&E Corporation long-term debt		350			-
	Utility
	Senior notes:
	4.80% due 2014		-			539
	5.625% due 2017		700			700
	8.25% due 2018		800			800
	3.50% due 2020		800			800
	4.25% due 2021		300			300
	3.25% due 2021		250			250
	2.45% due 2022		400			400
	3.25% due 2023		375			375
	3.85% due 2023		300			300
	3.40% due 2024		350			-
	3.75% due 2024		450			-
	6.05% due 2034		3,000			3,000
	5.80% due 2037		950			950
	6.35% due 2038		400			400
	6.25% due 2039		550			550
	5.40% due 2040		800			800
	4.50% due 2041		250			250
	4.45% due 2042		400			400
	3.75% due 2042		350			350
	4.60% due 2043		375			375
	5.125% due 2043		500			500
	4.75% due 2044		675			-
	4.30% due 2045		500			-
	Less: current portion		-			(539	)
	Unamortized discount, net of premium		(43	)		(51	)
	Total senior notes, net of current portion		13,432			11,449
	Pollution control bonds:
	Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)		614			614
	Series 2004 A-D, 4.75%, due 2023 (3)		345			345
	Series 2009 A-D, variable rates (1), due 2016 and 2026 (4)		309			309
	Total pollution control bonds		1,268			1,268
	Total Utility long-term debt, net of current portion		14,700			12,717
	Total consolidated long-term debt, net of current portion	$	15,050		$	12,717
	(1) At December 31, 2014, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
	(2) Each series of these bonds is supported by a separate letter of credit.  In April 2014, the letters of credit were extended to April 1, 2019.  Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
	(3) The Utility has obtained credit support from an insurance company for these bonds.
	(4) Each series of these bonds is supported by a separate direct-pay letter of credit.  In June 2014, Series A and B letters of credit were extended to June 5, 2019.  Series C and D letters expire on December 3, 2016 to coincide with the maturity of the underlying bonds.  Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
Schedule Of Short-Term Borrowings								Letters of
		Termination		Facility				Credit			Commercial				Facility
	(in millions)	Date		Limit				Outstanding			Paper				Availability
	PG&E Corporation	Apr-19		$	300	-1		$	-		$	-			$	300
	Utility	Apr-19			3,000	-2			84			333				2,583
	Total revolving credit facilities			$	3,300			$	84		$	333			$	2,883
	(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
	(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
Schedule Of Repayment Schedule	(in millions,
	except interest rates)	2015			2016				2017				2018				2019			Thereafter				Total
	PG&E Corporation
	Average fixed interest rate		-				-				-				-			2.40	%			-				2.4	%
	Fixed rate obligations	$	-			$	-			$	-			$	-		$	350			$	-			$	350
	Utility
	Average fixed interest rate		-				-				5.63	%			8.25	%		-				4.92	%			5.15	%
	Fixed rate obligations	$	-			$	-			$	700			$	800		$	-			$	12,320			$	13,820
	Variable interest rate
	as of December 31, 2014		-				0.01	%			-				-			0.01	%			-				0.01	%
	Variable rate obligations (1)	$	-			$	160			$	-			$	-		$	763			$	-			$	923
	Total consolidated debt	$	-			$	160			$	700			$	800		$	1,113			$	12,320			$	15,093
	(1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, April 1, 2019, or June 5, 2019.

Common_Stock_And_ShareBased_Co1

Common Stock And Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule Of Compensation Expense For Share-Based Incentive Awards	(in millions)	2014			2013		2012
	Restricted stock units	$	42		$	36	$	31
	Performance shares		36			28		26
	Total compensation expense (pre-tax)	$	78		$	64	$	57
	Total compensation expense (after-tax)	$	47		$	38	$	34
Schedule Of Restricted Stock Units		Number of		Weighted Average Grant-
		Restricted Stock Units		Date Fair Value
	Nonvested at January 1	2,300,021		$	43.16
	Granted	1,092,035		$	43.76
	Vested	(777,883	)	$	43.28
	Forfeited	(75,816	)	$	43.01
	Nonvested at December 31	2,538,357		$	43.38
Schedule Of Performance Shares		Number of		Weighted Average Grant-
		Performance Shares		Date Fair Value
	Nonvested at January 1	1,791,320		$	37.85
	Granted	843,185			51.81
	Vested	(275,247	)		41.94
	Forfeited (1)	(665,319	)		42.34
	Nonvested at December 31	1,693,939		$	42.37
	(1) Includes performance shares that expired with zero value as performance targets were not met.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Basic and Diluted EPS		Year Ended December 31,
	(in millions, except per share amounts)	2014		2013		2012
	Income available for common shareholders	$	1,436	$	814	$	816
	Weighted average common shares outstanding, basic		468		444		424
	Add incremental shares from assumed conversions:
	Employee share-based compensation		2		1		1
	Weighted average common share outstanding, diluted		470		445		425
	Total earnings per common share, diluted	$	3.06	$	1.83	$	1.92

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Schedule Of Components Of Income Tax Expense (Benefit)		PG&E Corporation									Utility
		Year Ended December 31,
	(in millions)	2014			2013			2012			2014			2013			2012
	Current:
	Federal	$	(84	)	$	(218	)	$	(74	)	$	(84	)	$	(222	)	$	(52	)
	State		(41	)		(26	)		33			(29	)		(23	)		41
	Deferred:
	Federal		396			552			374			426			604			404
	State		78			(35	)		(92	)		75			(28	)		(91	)
	Tax credits		(4	)		(5	)		(4	)		(4	)		(5	)		(4	)
	Income tax provision	$	345		$	268		$	237		$	384		$	326		$	298
Schedule Of Deferred Tax Assets And Liabilities		PG&E Corporation						Utility
		Year Ended December 31,
	(in millions)	2014			2013			2014			2013
	Deferred income tax assets:
	Customer advances for construction	$	88		$	90		$	88		$	90
	Reserve for damages		137			161			137			161
	Environmental reserve		111			152			111			152
	Compensation		107			167			36			102
	Net operating loss carryforward		1,177			890			946			670
	GHG allowances		56			108			56			108
	Other		74			135			100			128
	Total deferred income tax assets	$	1,750		$	1,703		$	1,474		$	1,411
	Deferred income tax liabilities:
	Regulatory balancing accounts	$	512		$	261		$	512		$	261
	Property related basis differences		8,683			8,048			8,666			8,038
	Income tax regulatory asset (1)		974			748			974			748
	Other		88			151			86			86
	Total deferred income tax liabilities	$	10,257		$	9,208		$	10,238		$	9,133
	Total net deferred income tax liabilities	$	8,507		$	7,505		$	8,764		$	7,722
	Classification of net deferred income tax liabilities:
	Included in current liabilities (assets)	$	(6	)	$	(318	)	$	(9	)	$	(320	)
	Included in noncurrent liabilities		8,513			7,823			8,773			8,042
	Total net deferred income tax liabilities	$	8,507		$	7,505		$	8,764		$	7,722
	(1) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP.  (See Note 3 above.)
Schedule Of Effective Income Tax Rate Reconciliation		PG&E Corporation									Utility
		Year Ended December 31,
		2014			2013			2012			2014			2013			2012
	Federal statutory income tax rate	35	%		35	%		35	%		35	%		35	%		35	%
	Increase (decrease) in income
	tax rate resulting from:
	State income tax (net of
	federal benefit) (1)	1.4			(3.1	)		(3.9	)		1.6			(2.2	)		(3.0	)
	Effect of regulatory treatment
	of fixed asset differences (2)	(15.0	)		(4.2	)		(4.1	)		(14.7	)		(3.8	)		(3.9	)
	Tax credits	(0.7	)		(0.4	)		(0.6	)		(0.7	)		(0.4	)		(0.6	)
	Benefit of loss carryback	(0.8	)		(1.1	)		(0.7	)		(0.8	)		(1.0	)		(0.4	)
	Non deductible penalties	0.3			0.8			0.6			0.3			0.7			0.5
	Other, net	(0.8	)		(2.2	)		(3.8	)		0.4			(0.9	)		(0.8	)
	Effective tax rate	19.4	%		24.8	%		22.5	%		21.1	%		27.4	%		26.8	%
	(1) Includes the effect of state flow-through ratemaking treatment.
	(2) Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the “2014 GRC Impact” section.
Schedule Of Change In Unrecognized Tax Benefits		PG&E Corporation									Utility
		2014			2013			2012			2014			2013			2012
	(in millions)
	Balance at beginning of year	$	666		$	581		$	506		$	660		$	575		$	503
	Additions for tax position taken
	during a prior year		7			12			32			7			12			26
	Reductions for tax position
	taken during a prior year		(9	)		(6	)		(13	)		(9	)		(6	)		(10	)
	Additions for tax position
	taken during the current year		61			79			67			61			79			67
	Settlements		(12	)		-			(11	)		(12	)		-			(11	)
	Balance at end of year	$	713		$	666		$	581		$	707		$	660		$	575

Derivatives_And_Hedging_Activi1

Derivatives And Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Derivatives And Hedging Activities [Abstract]
Volumes Of Outstanding Derivative Contracts					Contract Volume
	Underlying Product		Instruments		2014		2013
	Natural Gas (1) (MMBtus (2))		Forwards and Swaps		308,130,101		331,840,788
			Options		164,418,002		260,262,916
	Electricity (Megawatt-hours)		Forwards and Swaps		5,346,787		8,089,269
			Congestion Revenue Rights (3)		224,124,341		250,922,591
	(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 congestion costs based on demand when there is insufficient transmission capacity.
Outstanding Derivative Balances	At December 31, 2014, 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	$	73		$	(4	)	$	19		$	88
	Other noncurrent assets - other		178			(13	)		-			165
	Current liabilities - other		(78	)		4			26			(48	)
	Noncurrent liabilities - other		(140	)		13			9			(118	)
	Total commodity risk	$	33		$	-		$	54		$	87
	At December 31, 2013, 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	$	42		$	(10	)	$	16		$	48
	Other noncurrent assets - other		99			(4	)		-			95
	Current liabilities - other		(122	)		10			69			(43	)
	Noncurrent liabilities - other		(110	)		4			2			(104	)
	Total commodity risk	$	-91		$	-		$	87		$	-4
Gains And Losses On Derivative Instruments		Commodity Risk
		For the year ended December 31,
	(in millions)	2014			2013			2012
	Unrealized gain/(loss) - regulatory assets and liabilities (1)	$	124		$	238		$	391
	Realized loss - cost of electricity (2)		(83	)		(178	)		(486	)
	Realized loss - cost of natural gas (2)		(8	)		(22	)		(38	)
	Total commodity risk	$	33		$	38		$	-133
	(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the  Consolidated Statements of Income.  These amounts exclude the impact of cash collateral postings.
	(2) These amounts are fully passed through to customers in rates.  Accordingly, net income was not impacted by realized amounts on these instruments.
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered		Balance at December 31,
	(in millions)	2014			2013
	Derivatives in a liability position with credit risk-related
	contingencies that are not fully collateralized	$	(47	)	$	(79	)
	Related derivatives in an asset position		-			4
	Collateral posting in the normal course of business related to
	these derivatives		44			65
	Net position of derivative contracts/additional collateral
	posting requirements (1)	$	-3		$	-10
	(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)	12 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Assets And Liabilities Measured At Fair Value On A Recurring Basis		Fair Value Measurements
		At  December 31, 2014
	(in millions)	Level 1			Level 2			Level 3			Netting (1)			Total
	Assets:
	Money market investments	$	94		$	-		$	-		$	-		$	94
	Nuclear decommissioning trusts
	Money market investments		17			-			-			-			17
	Global equity securities		1,585			13			-			-			1,598
	Fixed-income securities		741			389			-			-			1,130
	Total nuclear decommissioning trusts (2)		2,343			402			-			-			2,745
	Price risk management instruments
	(Note 9)
	Electricity		-			17			232			2			251
	Gas		1			1			-			-			2
	Total price risk management instruments		1			18			232			2			253
	Rabbi trusts
	Fixed-income securities		-			42			-			-			42
	Life insurance contracts		-			72			-			-			72
	Total rabbi trusts		-			114			-			-			114
	Long-term disability trust
	Money market investments		7			-			-			-			7
	Global equity securities		-			25			-			-			25
	Fixed-income securities		-			128			-			-			128
	Total long-term disability trust		7			153			-			-			160
	Other investments		33			-			-			-			33
	Total assets	$	2,478		$	687		$	232		$	2		$	3,399
	Liabilities:
	Price risk management instruments
	(Note 9)
	Electricity	$	47		$	5		$	163		$	(52	)	$	163
	Gas		-			3			-			-			3
	Total liabilities	$	47		$	8		$	163		$	-52		$	166
	(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
	(2) Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
		Fair Value Measurements
		At December 31, 2013
	(in millions)	Level 1			Level 2			Level 3			Netting (1)			Total
	Assets:
	Money market investments	$	226		$	-		$	-		$	-		$	226
	Nuclear decommissioning trusts
	Money market investments		38			-			-			-			38
	U.S. equity securities		1,046			11						-			1,057
	Non-U.S. equity securities		457			-			-			-			457
	U.S. government and agency securities		760			156			-			-			916
	Municipal securities		-			25			-			-			25
	Other fixed-income securities		-			162			-			-			162
	Total nuclear decommissioning trusts (2)		2,301			354			-			-			2,655
	Price risk management instruments
	(Note 9)
	Electricity		2			27			107			3			139
	Gas		-			5			-			(1	)		4
	Total price risk management instruments		2			32			107			2			143
	Rabbi trusts
	Fixed-income securities		-			39			-			-			39
	Life insurance contracts		-			70			-			-			70
	Total rabbi trusts		-			109			-			-			109
	Long-term disability trust
	Money market investments		9			-			-			-			9
	U.S. equity securities		-			14			-			-			14
	Non-U.S. equity securities		-			12			-			-			12
	Fixed-income securities		-			122			-			-			122
	Total long-term disability trust		9			148			-			-			157
	Other investments		84			-			-			-			84
	Total assets	$	2,622		$	643		$	107		$	2		$	3,374
Liabilities:
Price risk management instruments
(Note 9)
Electricity	$	19		$	72		$	137		$	(84	)	$	144
Gas		1			3			-			(1	)		3
Total liabilities	$	20		$	75		$	137		$	-85		$	147
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $313 million, primarily related to deferred taxes on appreciation of investment value.
Sensitivity Analysis
			Fair Value at
	(in millions)		31-Dec-14
	Fair Value Measurement		Assets			Liabilities			Valuation Technique		Unobservable Input		Range (1)
	Congestion revenue rights		$	232		$	63		Market approach		CRR auction prices		$	(15.97) - 8.17
	Power purchase agreements		$	-		$	100		Discounted cash flow		Forward prices		$	16.04 - 56.21
	(1)       Represents price per megawatt-hour
			Fair Value at
	(in millions)		31-Dec-13
	Fair Value Measurement		Assets			Liabilities			Valuation Technique		Unobservable Input		Range (1)
	Congestion revenue rights		$	107		$	32		Market approach		CRR auction prices		$	(6.47) - 12.04
	Power purchase agreements		$	-		$	105		Discounted cash flow		Forward prices		$	23.43 - 51.75
	(1) Represents price per megawatt-hour
Level 3 Reconciliation		Price Risk Management Instruments
	(in millions)	2014			2013
	Liability balance as of January 1	$	-30		$	-79
	Realized and unrealized gains:
	Included in regulatory assets and liabilities or balancing accounts (1)		99			49
	Asset (liability) balance as of December 31	$	69		$	-30
	(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.
Carrying Amount And Fair Value Of Financial Instruments		At December 31,
		2014						2013
	(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
	Debt (Note 4)
	PG&E Corporation	$	350		$	352		$	350		$	354
	Utility		13,778			15,851			12,334			13,444
Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments						Total			Total
		Amortized				Unrealized			Unrealized			Total Fair
	(in millions)	Cost				Gains			Losses			Value
	As of December 31, 2014
	Nuclear decommissioning trusts
	Money market investments	$	17		$	-		$	-		$	17
	Global equity securities		520			1,087			(9	)		1,598
	Fixed-income securities		1,059			75			(4	)		1,130
	Total nuclear decommissioning trusts (1)		1,596			1,162			(13	)		2,745
	Other investments		5			28			-			33
	Total	$	1,601		$	1,190		$	-13		$	2,778
	As of December 31, 2013
	Nuclear decommissioning trusts
	Money market investments	$	38		$	-		$	-		$	38
	Equity securities
	U.S.		246			811			-			1,057
	Non-U.S.		215			242			-			457
	Debt securities
	U.S. government and agency securities		870			51			(5	)		916
	Municipal securities		24			2			(1	)		25
	Other fixed-income securities		163			1			(2	)		162
	Total nuclear decommissioning trusts (1)		1,556			1,107			(8	)		2,655
	Other investments		13			71			-			84
	Total (1)	$	1,569		$	1,178		$	-8		$	2,739
	(1) Represents amounts before deducting $324 million and $313 million at December 31, 2014 and 2013, respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule Of Long Term Debt Repayments		As of
	(in millions)	31-Dec-14
	Less than 1 year	$	17
	1-5 years		466
	5-10 years		263
	More than 10 years		384
	Total maturities of debt securities	$	1,130
Schedule Of Activity For Debt And Equity Securities		2014			2013			2012
	(in millions)
	Proceeds from sales and maturities of nuclear decommissioning trust
	investments	$	1,336		$	1,619		$	1,133
	Gross realized gains on sales of securities held as available-for-sale		118			94			19
	Gross realized losses on sales of securities held as available-for-sale		(12	)		(13	)		(17	)

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status	Pension Plan
	(in millions)	2014			2013
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	12,527		$	12,141
	Actual return on plan assets		1,946			673
	Company contributions		332			323
	Benefits and expenses paid		(589	)		(610	)
	Fair value of plan assets at end of year	$	14,216		$	12,527
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	14,077		$	15,541
	Service cost for benefits earned		383			468
	Interest cost		695			627
	Actuarial (gain) loss		2,131			(1,950	)
	Plan amendments		(1	)		-
	Transitional costs		-			1
	Benefits and expenses paid		(589	)		(610	)
	Benefit obligation at end of year (1)	$	16,696		$	14,077
	Funded Status:
	Current liability	$	(6	)	$	(6	)
	Noncurrent liability		(2,474	)		(1,544	)
	Net liability at end of year	$	-2,480		$	-1,550
	(1) PG&E Corporation's accumulated benefit obligation was $14.9 billion and $12.6 billion at December 31, 2014 and 2013, respectively.
	Postretirement Benefits Other than Pensions
	(in millions)	2014			2013
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	1,892		$	1,758
	Actual return on plan assets		241			64
	Company contributions		57			145
	Plan participant contribution		63			64
	Benefits and expenses paid		(161	)		(139	)
	Fair value of plan assets at end of year	$	2,092		$	1,892
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	1,597		$	1,940
	Service cost for benefits earned		45			53
	Interest cost		76			74
	Actuarial (gain) loss		166			(415	)
	Benefits paid		(140	)		(123	)
	Federal subsidy on benefits paid		4			4
	Plan participant contributions		63			64
	Benefit obligation at end of year	$	1,811		$	1,597
	Funded Status: (1)
	Noncurrent asset	$	368		$	352
	Noncurrent liability		(87	)		(57	)
	Net asset at end of year	$	281		$	295
	(1) At December 31, 2014 and 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
Components Of Net Periodic Benefit Cost	Pension Plan
	(in millions)	2014			2013			2012
	Service cost	$	383		$	468		$	396
	Interest cost		695			627			658
	Expected return on plan assets		(807	)		(650	)		(598	)
	Amortization of prior service cost		20			20			20
	Amortization of net actuarial loss		2			111			123
	Net periodic benefit cost		293			576			599
	Less: transfer to regulatory account (1)		42			(238	)		(301	)
	Total expense recognized	$	335		$	338		$	298
	(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
	Postretirement Benefits Other than Pensions
	(in millions)	2014			2013			2012
	Service cost	$	45		$	53		$	49
	Interest cost		76			74			83
	Expected return on plan assets		(103	)		(79	)		(77	)
	Amortization of transition obligation		-			-			24
	Amortization of prior service cost		23			23			25
	Amortization of net actuarial loss		2			6			6
	Net periodic benefit cost	$	43		$	77		$	110
Estimated Amortized Net Periodic Benefit For 2012
	(in millions)	Pension Plan			PBOP Plans
	Unrecognized prior service cost	$	15		$	19
	Unrecognized net loss		11			4
	Total	$	26		$	23
Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost		Pension Plan									PBOP Plans
		December 31,									December 31,
		2014			2013			2012			2014		2013		2012
	Discount rate	4	%		4.89	%		3.98	%		3.89 - 4.09	%	4.70 - 5.00	%	3.75 - 4.08	%
	Rate of future compensation
	increases	4	%		4	%		4	%		-		-		-
	Expected return on plan
	assets	6.2	%		6.5	%		5.4	%		3.30 - 6.70	%	3.50 - 6.70	%	2.90 - 6.10	%
Schedule Of Assumed Health Care Cost Trend		One-Percentage-Point			One-Percentage-Point
	(in millions)	Increase			Decrease
	Effect on postretirement benefit obligation	$	107		$	(108	)
	Effect on service and interest cost		8			(8	)
Target Asset Allocation Percentages		Pension Plan									PBOP Plans
		2015			2014			2013			2015		2014		2013
	Global equity	25	%		25	%		25	%		31	%	30	%	28	%
	Absolute return	5	%		5	%		5	%		3	%	3	%	4	%
	Real assets	10	%		10	%		10	%		8	%	8	%	8	%
	Fixed income	60	%		60	%		60	%		58	%	59	%	60	%
	Total	100	%		100	%		100	%		100	%	100	%	100	%
Schedule Of Changes In Fair Value Of Plan Assets		Fair Value Measurements
		At December 31,
		2014											2013
	(in millions)	Level 1			Level 2			Level 3			Total		Level 1		Level 2		Level 3		Total
	Pension Plan:
	Short-term investments	$	352		$	311		$	-		$	663	$	70	$	-	$	-	$	70
	Global equity		918			2,311			-			3,229		1,123		2,363		-		3,486
	Absolute return		-			-			577			577		-		-		554		554
	Real assets		620			-			675			1,295		562		-		544		1,106
	Fixed-income		2,068			5,718			638			8,424		1,448		5,104		625		7,177
	Total	$	3,958		$	8,340		$	1,890		$	14,188	$	3,203	$	7,467	$	1,723	$	12,393
	PBOP Plans:
	Short-term investments	$	28		$	-		$	-		$	28	$	31	$	-	$	-	$	31
	Global equity		124			549			-			673		127		504		-		631
	Absolute return		-			-			55			55		-		-		53		53
	Real assets		72			-			49			121		67		-		38		105
	Fixed-income		163			1,055			1			1,219		137		936		2		1,075
	Total	$	387		$	1,604		$	105		$	2,096	$	362	$	1,440	$	93	$	1,895
	Total plan assets at fair value										$	16,284							$	14,288
Schedule Of Level 3 Reconciliation
		Pension Plan
	(in millions)	Absolute			Fixed-
	For the year ended December 31, 2014	Return			Income			Real Assets			Total
	Balance at beginning of year	$	554		$	625		$	544		$	1,723
	Actual return on plan  assets:
	Relating to assets still held at the reporting date		23			24			54			101
	Relating to assets sold during the period		-			4			-			4
	Purchases, issuances, sales, and settlements:
	Purchases		-			1			78			79
	Settlements		-			(16	)		(1	)		-17
	Balance at end of year	$	577		$	638		$	675		$	1,890
		Pension Plan
	(in millions)	Absolute			Fixed-
	For the year ended December 31, 2013	Return			Income			Real Assets			Total
	Balance at beginning of year	$	513		$	611		$	285		$	1,409
	Actual return on plan assets:
	Relating to assets still held at the reporting date		37			1			49			87
	Relating to assets sold during the period		4			-			(3	)		1
	Purchases, issuances, sales, and settlements:
	Purchases		-			20			352			372
	Settlements		-			(7	)		(139	)		-146
	Balance at end of year	$	554		$	625		$	544		$	1,723
		PBOP Plans
	(in millions)	Absolute			Fixed-
	For the year ended December 31, 2014	Return			Income			Real Assets			Total
	Balance at beginning of year	$	53		$	2			38		$	93
	Actual return on plan  assets:
	Relating to assets still held at the reporting date		2			-			4			6
	Relating to assets sold during the period		-			-			-			-
	Purchases, issuances, sales, and settlements:
	Purchases		-			-			7			7
	Settlements		-			(1	)		-			-1
	Balance at end of year	$	55		$	1		$	49		$	105
		PBOP Plans
	(in millions)	Absolute			Fixed-
	For the year ended December 31, 2013	Return			Income			Real Assets			Total
	Balance at beginning of year	$	49		$	1			28		$	78
	Actual return on plan assets:
	Relating to assets still held at the reporting date		4			-			3			7
	Relating to assets sold during the period		-			-			-			-
	Purchases, issuances, sales, and settlements:
	Purchases		12			1			21			34
	Settlements		(12	)		-			(14	)		-26
	Balance at end of year	$	53		$	2		$	38		$	93
Schedule Of Estimated Benefits Expected To Be Paid		Pension			PBOP			Federal
	(in millions)	Plan			Plans			Subsidy
	2015	$	653		$	91		$	(7	)
	2016		696			96			(8	)
	2017		737			102			(8	)
	2018		775			109			(9	)
	2019		812			115			(10	)
	Thereafter in the succeeding five years		4,545			614			(29	)

Related_Party_Agreements_And_T1

Related Party Agreements And Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Agreements And Transactions [Abstract]
Schedule Of Significant Related Party Transactions		Year Ended December 31,
	(in millions)	2014		2013		2012
	Utility revenues from:
	Administrative services provided to PG&E Corporation	$	5	$	7	$	7
	Utility expenses from:
	Administrative services received from PG&E Corporation	$	54	$	45	$	50
	Utility employee benefit due to PG&E Corporation		70		57		51

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Schedule of Environmental Remediation Liability		Balance at
	(in millions)	31-Dec-14		31-Dec-13
	Topock natural gas compressor station (1)	$	291	$	264
	Hinkley natural gas compressor station (1)		158		190
	Former manufactured gas plant sites owned by the Utility or third parties		257		184
	Utility-owned generation facilities (other than fossil fuel-fired),		150		160
	other facilities, and third-party disposal sites
	Fossil fuel-fired generation facilities and sites		98		102
	Total environmental remediation liability	$	954	$	900
	(1) See “Natural Gas Compressor Station Sites” below.
Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments		Power Purchase Agreements
		Renewable		Qualifying				Natural		Nuclear
	(in millions)	Energy		Facility		Other		Gas		Fuel		Total
	2015	$	2,145	$	601	$	820	$	544	$	138	$	4,248
	2016		2,185		525		766		164		129		3,769
	2017		2,187		418		758		107		131		3,601
	2018		2,063		382		731		107		115		3,398
	2019		2,053		304		706		107		109		3,279
	Thereafter		30,289		1,217		2,390		648		429		34,973
	Total purchase commitments	$	40,922	$	3,447	$	6,171	$	1,677	$	1,051	$	53,268
Schedule of Future Minimum Payments For Operating Leases	(in millions)	Operating Leases
	2015	$	44
	2016		43
	2017		33
	2018		30
	2019		27
	Thereafter		183
	Total minimum lease payments	$	360

Schedule_I_Condensed_Financial1

Schedule I - Condensed Financial Information Of Parent (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule I - Condensed Financial Information Of Parent [Abstract]
Schedule of Condensed Statements of Income	PG&E CORPORATION
	SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
	CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
			Years Ended December 31,
	(in millions, except per share amounts)		2014			2013			2012
	Administrative service revenue	$	51		$	41		$	43
	Operating expenses		(53	)		(42	)		(41	)
	Interest income		1			1			1
	Interest expense		(14	)		(25	)		(22	)
	Other expense		(1	)		(57	)		(39	)
	Equity in earnings of subsidiaries		1,413			848			817
	Income before income taxes		1,397			766			759
	Income tax benefit		39			48			57
	Net income	$	1,436		$	814		$	816
	Other Comprehensive Income
	Pension and other postretirement benefit plans obligations (net of taxes of $10,
	$80, and $72, at respective dates)	$	(14	)	$	113		$	108
	Net change in investments (net of taxes of $17, $26, and $3, at respective dates)		(25	)		38			4
	Total other comprehensive income (loss)		(39	)		151			112
	Comprehensive Income	$	1,397		$	965		$	928
	Weighted Average Common Shares Outstanding, Basic		468			444			424
	Weighted Average Common Shares Outstanding, Diluted		470			445			425
	Earnings per common share, basic	$	3.07		$	1.83		$	1.92
	Earnings per common share, diluted	$	3.06		$	1.83		$	1.92
Schedule of Condensed Balance Sheet	PG&E CORPORATION
	SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
	CONDENSED BALANCE SHEETS
		Balance at December 31,
	(in millions)	2014			2013
	ASSETS
	Current Assets
	Cash and cash equivalents	$	96		$	231
	Advances to affiliates		31			30
	Income taxes receivable		29			13
	Other		38			86
	Total current assets		194			360
	Noncurrent Assets
	Equipment		2			2
	Accumulated depreciation		(1	)		(1	)
	Net equipment		1			1
	Investments in subsidiaries		16,003			14,711
	Other investments		117			110
	Income taxes receivable		-			5
	Deferred income taxes		260			188
	Total noncurrent assets		16,381			15,015
	Total Assets	$	16,575		$	15,375
	LIABILITIES AND SHAREHOLDERS' EQUITY
	Current Liabilities
	Short-term borrowings	$	-		$	260
	Long-term debt classified as current		-			350
	Accounts payable - other		67			66
	Other		269			230
	Total current liabilities		336			906
	Noncurrent Liabilities
	Long-term debt		350			-
	Other		141			127
	Total noncurrent liabilities		491			127
	Common Shareholders' Equity
	Common stock		10,421			9,550
	Reinvested earnings		5,316			4,742
	Accumulated other comprehensive loss		11			50
	Total common shareholders' equity		15,748			14,342
	Total Liabilities and Shareholders' Equity	$	16,575		$	15,375
Schedule Of Condensed Statement Of Cash Flows	PG&E CORPORATION
	SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT - (Continued)
	CONDENSED STATEMENTS OF CASH FLOWS
	(in millions)
				Year Ended December 31,
				2014			2013			2012
	Cash Flows from Operating Activities:
	Net income			$	1,436		$	814		$	816
	Adjustments to reconcile net income to net cash provided by operating activities:
	Stock-based compensation amortization				65			54			51
	Equity in earnings of subsidiaries				(1,413	)		(848	)		(817	)
	Deferred income taxes and tax credits, net				(72	)		(10	)		(31	)
	Noncurrent income taxes receivable/payable				5			-			(6	)
	Current income taxes receivable/payable				(16	)		20			(82	)
	Other				43			(20	)		20
	Net cash provided by (used in) operating activities				48			10			(49)
	Cash Flows From Investing Activities:
	Investment in subsidiaries				(978	)		(1,371	)		(1,023	)
	Dividends received from subsidiaries (1)				716			716			716
	Proceeds from tax equity investments				368			275			228
	Other				-			(8	)		-
	Net cash provided by (used in) investing activities				106			-388			(79)
	Cash Flows From Financing Activities:
	Borrowings under revolving credit facilities				-			140			120
	Repayments under revolving credit facilities				(260	)		-			-
	Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014				347			-			-
	Repayments of long-term debt				(350	)		-			-
	Common stock issued				802			1,045			751
	Common stock dividends paid (2)				(828	)		(782	)		(746	)
	Other				-			(1	)		1
	Net cash provided by (used in) financing activities				-289			402			126
	Net change in cash and cash equivalents				-135			24			-2
	Cash and cash equivalents at January 1				231			207			209
	Cash and cash equivalents at December 31			$	96		$	231		$	207
	Supplemental disclosures of cash flow information
	Cash received (paid) for:
	Interest, net of amounts capitalized			$	(15	)	$	(23	)	$	(20	)
	Income taxes, net				1			21			(60	)
	Supplemental disclosures of noncash investing and financing
	activities
	Noncash common stock issuances				21			22			22
	Common stock dividends declared but not yet paid			$	217		$	208		$	196
	-1	Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
	-2	In January, April, July, and October of 2014, 2013, and 2012, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule_II_Consolidated_Valua1

Schedule II - Consolidated Valuation And Qualifying Accounts (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Schedule II - Consolidated Valuation And Qualifying Accounts	PG&E Corporation
	SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
	For the Years Ended December 31, 2014, 2013, and 2012
	(in millions)			Additions
	Description		Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
	Valuation and qualifying accounts deducted from assets:
	2014:
	Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
	2013:
	Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80
	2012:
	Allowance for uncollectible accounts (1)	$	81	$	66	$	-	$	60	$	87
	(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
	(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
	Pacific Gas and Electric Company
	SCHEDULE II - CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
	For the Years Ended December 31, 2014, 2013, and 2012
	(in millions)			Additions
	Description		Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions (2)		Balance at End of Period
	Valuation and qualifying accounts deducted from assets:
	2014:
	Allowance for uncollectible accounts (1)	$	80	$	41	$	-	$	55	$	66
	2013:
	Allowance for uncollectible accounts (1)	$	87	$	53	$	-	$	60	$	80
	2012:
	Allowance for uncollectible accounts (1)	$	81	$	66	$	-	$	60	$	87
	(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”
	(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Number of tax equity agreements	4
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Disallowed capital expenditure losses	$116,000,000	$196,000,000	$353,000,000
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate	3.77%	3.51%	3.63%
AFUDC interest recorded	45,000,000	47,000,000	49,000,000
AFUDC equity recorded	100,000,000	101,000,000	107,000,000
Nuclear decommissioning obligation accrued	2,500,000,000	2,500,000,000
Estimated cost recovery on spent nuclear fuel storage proceeding every year	3,500,000,000	3,500,000,000
Approximate estimated nuclear decommissioning cost in future dollars	6,100,000,000	6,100,000,000
PGE Corporation and Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Loss on debt extinguishment	135,000,000	157,000,000	163,000,000
Amortization on loss on debt extinguishment	$22,000,000	$23,000,000	$23,000,000

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	63,060		$59,094
Accumulated depreciation	-19,120		-17,843
Net property, plant, and equipment	43,940		41,251
Electricity generating facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	9,374	[1]	9,116	[1]
Electricity generating facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Electricity generating facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	100 years
Electricity distribution facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	26,633		25,333
Electricity distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Electricity distribution facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	55 years
Electricity transmission [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	9,155		8,429
Electricity transmission [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Electricity transmission [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	70 years
Natural gas distribution facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	9,741		9,117
Natural gas distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	20 years
Natural gas distribution facilities [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	60 years
Natural gas transportation and storage [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	5,937		5,265
Natural gas transportation and storage [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Natural gas transportation and storage [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	65 years
Construction Work In Progress [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	2,220		$1,834
[1]	Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output. (See Note 14 below.)

Summary_Of_Significant_Account5

Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]
Balance at beginning of year	$3,538	$2,919
Revision in estimated cash flows	-16	596
Accretion	163	130
Liabilities settled	-110	-107
Balance at end of year	$3,575	$3,538

New_and_Significant_Accounting

New and Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensived Income) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	$50		($101)
Change in investments	-25		38		4
Total other comprehensive income (loss)	-39		151		112
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	11		50		-101
Net actuarial loss tax	10		80		72
Change in investments tax	17		26		3
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	-28	[1]	-76	[1]
Amortization of prior service cost	26	[1]	25	[1]
Amortization of net actuarial loss	2	[1]	69	[1]
Realized gain on investments	-30
Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	-616		1,214
Unrecognized prior service cost	1		1,119
Transfer to regulatory account	601
Change in investments	5		38
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	15		-77
Unrecognized net actuarial loss	4
Unrecognized prior service cost	19
Amortization of prior service cost	23		23		25
Amortization of net actuarial loss	2		6		6
Total other comprehensive income (loss)	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	15		15		-77
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	-15	[1]	0	[1]
Amortization of prior service cost	14	[1]	13	[1]
Amortization of net actuarial loss	1	[1]	3	[1]
Realized gain on investments	0
Total other comprehensive income (loss)			92
Net actuarial loss tax	1		3
Transfer To Regulatory Account Tax	10		0
Amortization of prior service cost tax	9		10
Realized gain on investments tax	0
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	-28		45
Unrecognized prior service cost	0		-31
Transfer to regulatory account	28
Change in investments	0		0
Net actuarial loss tax	19		35
Transfer To Regulatory Account Tax	19		22
Change in investments tax	0		0
Other Investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	42
Total other comprehensive income (loss)	-25
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	17				4
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	0	[1]	0	[1]
Amortization of prior service cost	0	[1]	0	[1]
Amortization of net actuarial loss	0	[1]	0	[1]
Realized gain on investments	-30
Total other comprehensive income (loss)			38
Net actuarial loss tax	0		0
Transfer To Regulatory Account Tax	0		0
Amortization of prior service cost tax	0		0
Realized gain on investments tax	20
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	0		0
Unrecognized prior service cost	0		0
Transfer to regulatory account	0
Change in investments	5		38
Net actuarial loss tax	0		0
Transfer To Regulatory Account Tax	0		0
Change in investments tax	4		26
Pension [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance	-7
Total other comprehensive income (loss)	-14
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance	-21				-28
Pension [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	-13	[1]	-76	[1]
Amortization of prior service cost	12	[1]	12	[1]
Amortization of net actuarial loss	1	[1]	66	[1]
Realized gain on investments	0
Total other comprehensive income (loss)			21
Net actuarial loss tax	1		45
Transfer To Regulatory Account Tax	9		54
Amortization of prior service cost tax	8		8
Realized gain on investments tax	0
Pension [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss	-588		1,169
Unrecognized prior service cost	1		1,150
Transfer to regulatory account	573
Change in investments	0		0
Net actuarial loss tax	404		804
Transfer To Regulatory Account Tax	394		790
Change in investments tax	$0		$0
[1]	These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)

Regulatory_Assets_Liabilities_2

Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Regulatory Assets [Line Items]
Deferred income taxes regulatory asset recovery maximum (years)	47 years
Utility retained generation asset costs	$1,200
Weighted average remaining life of Utility retained generation assets (years)	11 years
Environmental compliance costs regulatory asset recovery (years)	32 years
Price risk management regulatory assets recovery (years)	10 years
Expected recovery of electromechanical meters (years)	2 years
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)	12 years
Period of time exceeded for regulatory balancing accounts to be recorded in other noncurrent assets (months)	12 months
Period Of Time Expected To Refund Regulatory Liabilities To Customers	12 months
Period Of Time Expected To Incur Public Purpose Program Costs Minimum	12 months

Regulatory_Assets_Liabilities_3

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Assets [Line Items]
Total long-term regulatory assets	$6,322		$4,913
Pension Plans Defined Benefit [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,347	[1],[2]	1,444	[1],[2]
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,390	[1]	1,835	[1]
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	456	[3]	503	[3]
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	717	[1]	628	[1]
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	127	[1]	106	[1]
Electromechanical meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	70	[4]	135	[4]
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	113	[1]	135	[1]
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	$102		$127
[1]	Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets. (See Note 11 below.)
[2]	The Utility expects to continuously recover pension benefits.
[3]	In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility?s proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility?s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
[4]	Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter? devices.

Regulatory_Assets_Liabilities_4

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$6,290		$5,660
Cost Of Removal Obligation [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	4,211	[1]	3,844	[1]
Recoveries In Excess Of ARO [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	754	[2]	748	[2]
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	701	[3]	587	[3]
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$624		$481
[1]	Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
[2]	Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility?s nuclear generation facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 10 below.)
[3]	Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.

Regulatory_Assets_Liabilities_5

Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$2,266		$1,124
Public Purpose Programs [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	109		56
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	1,090		1,008
Electric Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	344		102
Utility Generation [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	261		57
Public Purpose Programs [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	154		171
Gas Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	566		70
Energy Procurement [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	608		410
Energy Procurement [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	188		298
Other [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	378		429
Other [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$748	[1]	$539	[1]
[1]	At December 31, 2014, Other regulatory balancing accounts payable mostly includes energy supplier settlements. (See Note 12 for additional details.)

Debt_Narrative_Details

Debt (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt [Line Items]
Interest including LIBOR on credit facilities	Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation?s and the Utility?s election, on (1) a London Interbank Offered Rate plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent?s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%
Ownership requirement percentage	80.00%
Required ownership of voting capital stock	70.00%
Commercial paper, maturities (days)	365 days
Utility [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	$3,000	[1]
Right to increase commitments	500
Commercial paper average yield	0.23%
Line of Credit Facility, Expiration Date	1-Apr-19
Pg E Corporation [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	300	[2]
Right to increase commitments	100
Commercial paper average yield	0.24%
Line of Credit Facility, Expiration Date	1-Apr-18
Senior Notes	350		0
Credit Facilities [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	3,300
Floating Rate Senior Notes [Member] | Utility [Member]
Debt [Line Items]
Senior Notes	300
Commercial Paper [Member] | Utility [Member]
Debt [Line Items]
Average outstanding borrowings	609
Maximum outstanding balance	1,400
Commercial Paper [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average outstanding borrowings	118
Maximum outstanding balance	260
Revolving Credit Facility [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average outstanding borrowings	27
Maximum outstanding balance	$260
[1]	Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
[2]	Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

Debt_Schedule_Of_LongTerm_Debt

Debt (Schedule Of Long-Term Debt) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt [Line Items]
Total long-term debt, net of current portion	15,050		$12,717
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Total long-term debt, net of current portion	14,700		12,717
Utility [Member]
Debt [Line Items]
Less: current portion	0		-539
Unamortized discount, net of premium	-43		-51
Total senior notes, net of current portion	13,432		11,449
Total pollution control bonds	1,268		1,268
Pg E Corporation [Member]
Debt [Line Items]
Senior notes	350		0
Less: current portion	0		-350
Total long-term debt, net of current portion	350		0
Senior Notes, 5.75%, Due 2014 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Senior notes	0		350
Senior Notes, 2.40% Due 2019 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Senior notes	350		0
Senior Notes, 3.40% Due 2024 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes	350		0
Senior Notes, 4.80% Due 2014 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes	0		539
Senior Notes, 5.625% Due 2017 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	700		700
Senior Notes, 8.25% Due 2018 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	800		800
Senior Notes, 3.50% Due 2020 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	800		800
Senior Notes, 4.25% Due 2021[Member] | Utility [Member]
Debt [Line Items]
Senior notes	300		300
Senior Notes, 3.25% Due 2021 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	250		250
Senior Notes, 2.45% Due 2022 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes	400		400
Senior Notes, 3.25% Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	375		375
Senior Notes, 3.85% Due 2023 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes			300
Senior Notes, 3.85% Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	300
Senior Notes, 3.75% Due 2024 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes	450		0
Senior Notes, 6.05% Due 2034 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	3,000		3,000
Senior Notes, 5.80% Due 2037 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	950		950
Senior Notes, 6.35% Due 2038 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	400		400
Senior Notes, 6.25% Due 2039 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	550		550
Senior Notes, 5.40% Due 2040 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	800		800
Senior Notes, 4.50% Due 2041 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	250		250
Senior Notes, 4.45% Due 2042 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	400		400
Senior Notes, 3.75% Due 2042 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	350		350
Senior Notes, 4.60% Due 2043 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	375		375
Senior Notes, 5.125% Due 2043 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	500		500
Senior Notes, 4.75% Due 2044 [Member] | Utility [Member]
Debt [Line Items]
Senior notes	675		0
Senior Notes, 4.30% Due 2045 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Senior notes	500		0
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member]
Debt [Line Items]
Interest rate on bonds, minimum	0.01%
Interest rate on bonds, maximum	0.02%
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	614	[1],[2]	614	[1],[2]
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	345	[3]	345	[3]
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member]
Debt [Line Items]
Interest rate on bonds, minimum	0.01%
Interest rate on bonds, maximum	0.02%
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	309	[1],[4]	$309	[1],[4]
[1]	At December 31, 2014, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
[2]	Each series of these bonds is supported by a separate letter of credit. In April 2014, the letters of credit were extended to April 1, 2019. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
[3]	The Utility has obtained credit support from an insurance company for these bonds.
[4]	Each series of these bonds is supported by a separate direct-pay letter of credit. In June 2014, Series A and B letters of credit were extended to June 5, 2019. Series C and D letters expire on December 3, 2016 to coincide with the maturity of the underlying bonds. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.

Debt_Schedule_Of_LongTerm_Debt1

Debt (Schedule Of Long-Term Debt Repayments) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Debt [Line Items]
Total consolidated long-term debt	$15,093
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.15%
Fixed rate obligations	13,820
Variable interest rate as of December 31, 2014	0.01%
Variable rate obligations	923	[1]
Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	350
2015 [Member]
Debt [Line Items]
Total consolidated long-term debt	0
2015 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
Variable interest rate as of December 31, 2014	0.00%
Variable rate obligations	0	[1]
2015 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
2016 [Member]
Debt [Line Items]
Total consolidated long-term debt	160
2016 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
Variable interest rate as of December 31, 2014	0.01%
Variable rate obligations	160	[1]
2016 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
2017 [Member]
Debt [Line Items]
Total consolidated long-term debt	700
2017 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.63%
Fixed rate obligations	700
Variable interest rate as of December 31, 2014	0.00%
Variable rate obligations	0	[1]
2017 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
2018 [Member]
Debt [Line Items]
Total consolidated long-term debt	800
2018 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	8.25%
Fixed rate obligations	800
Variable interest rate as of December 31, 2014	0.00%
Variable rate obligations	0	[1]
2018 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
2019 [Member]
Debt [Line Items]
Total consolidated long-term debt	1,113
2019 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	0
Variable interest rate as of December 31, 2014	0.01%
Variable rate obligations	763	[1]
2019 [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	350
Thereafter [Member]
Debt [Line Items]
Total consolidated long-term debt	12,320
Thereafter [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	4.92%
Fixed rate obligations	12,320
Variable interest rate as of December 31, 2014	0.00%
Variable rate obligations	0	[1]
Thereafter [Member] | Pg E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$0
[1]	These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, April 1, 2019, or June 5, 2019.

Debt_Schedule_Of_Line_Of_Credi

Debt (Schedule Of Line Of Credit) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Utility [Member]
Debt [Line Items]
Expiration date for credit agreement	1-Apr-19
Facility Limit	$3,000	[1]
Letters of Credit outstanding	84
Borrowings	0
Commercial Paper	333
Facility Availability	2,583
Letters of credit, sublimit	1,000
Swingline loans, sublimit	300
Swingline loan repay term (days)	7 days
Pg E Corporation [Member]
Debt [Line Items]
Expiration date for credit agreement	1-Apr-18
Facility Limit	300	[2]
Letters of Credit outstanding	0
Borrowings	0
Commercial Paper	0
Facility Availability	300
Letters of credit, sublimit	100
Swingline loans, sublimit	100
Swingline loan repay term (days)	7 days
Credit Facilities [Member]
Debt [Line Items]
Facility Limit	3,300
Letters of Credit outstanding	84
Borrowings	0
Commercial Paper	333
Facility Availability	$2,883
[1]	Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
[2]	Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

Common_Stock_And_ShareBased_Co2

Common Stock And Share-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Feb. 11, 2014	Dec. 31, 2013
Common stock, shares outstanding	475,913,404					456,670,424
Equity distribution agreement amount					$500
Dividend per share	$0.46	$0.46	$0.46	$0.46
Debt covenant ratio of total consolidated debt to total consolidated capitalization percentage	65.00%
Percentage of equity for capital structure to be maintained	52.00%
Common stock	10,421					9,550
Equity Contract [Member]
Common stock shares issued	11,000,000
Common stock	496
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member]
Common stock shares issued	8,000,000
Common stock	306
May 2, 2013 Equity Contract [Member]
Fees and Commissions	4
Utility [Member]
Net restricted assets for equity component requirement	14,600
Additional Common Stock Dividends	$153

Common_Stock_And_ShareBased_Co3

Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued for LTIP, maximum	17,000,000
Shares available for LTIP award	16,184,126
Total Compensation Expense (pre-tax)	$78	$64	$57
Total Compensation Expense (after-tax)	47	38	34
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	42	36	31
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	$36	$28	$26

Common_Stock_And_ShareBased_Co4

Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Stock And Share-Based Compensation [Abstract]
Restricted stock units terms, percentage of shares to vest	20.00%
Restricted stock units terms, percentage of shares to vest, remaining percentage	40.00%
Weighted average grant-date fair value of RSU's	$43.76	$42.92	$42.17
Total fair value	$34	$30	$18
Total unrecognized compensation costs	$51
Remaining weighted average period, Years	1 year 9 months 0 days
Nonvested at January 1, Number of Restricted Stock Units	2,300,021
Granted, Number of Restricted Stock Units	1,092,035
Vested, Number of Restricted Stock Units	-777,883
Forfeited, Number of Restricted Stock Units	-75,816
Nonvested at December 31, Number of Restricted Stock Units	2,538,357	2,300,021
Nonvested at January 1, Weighted Average Grant-Date Fair Value	$43.16
Granted, Weighted Average Grant Date Fair Value	$43.76
Vested, Weighted Average Grant Date Fair Value	$43.28
Forfeited, Weighted Average Grant Date Fair Value	$43.01
Nonvested at December 31, Weighted Average Grant-Date Fair Value	$43.38	$43.16

Common_Stock_And_ShareBased_Co5

Common Stock And Share-Based Compensation (Performance Shares) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance period for vesting of performance shares, years	3 years
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized	$34
Weighted-average period (years)	1 year 2 months 0 days
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested at January 1, Number of Performance Shares	1,791,320
Granted, Number of Performance Shares	843,185
Vested, Number of Performance Shares	-275,247
Forfeited, Number of Performance Shares	-665,319	[1]
Nonvested at December 31, Number of Performance Shares	1,693,939		1,791,320
Nonvested at January 1, Weighted Average Exercise Price	$37.85
Granted, Weighted Average Exercise Price	51.81		33.45	41.93
Vested, Weighted Average Exercise Price	41.94
Forfeited, Weighted Average Exercise Price	42.34
Nonvested at December 31, Weighted Average Exercise Price	$42.37		$37.85
[1]	Includes performance shares that expired with zero value as performance targets were not met.

Preferred_Stock_Narrative_Deta

Preferred Stock (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Preferred Stock [Line Items]
Preferred stock dividends	$14	$14	$14
Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends	$14	$14	$14
$25 Par Value [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$25
$25 Par Value [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$25
Preferred stock, shares issued	75,000,000
$100 Par Value [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$100
Preferred stock, shares issued	10,000,000
$100 Par Value [Member] | PG&E Corporation [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$100
Preferred stock, shares issued	5,000,000
No Par Value [Member] | PG&E Corporation [Member]
Preferred Stock [Line Items]
Preferred stock, shares authorized	80,000,000
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	$1.25
Preferred stock dividends per share, high range	$1.50
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock dividends per share, low range	$1.09
Preferred stock dividends per share, high range	$1.25

Preferred_Stock_Summary_Of_Iss

Preferred Stock (Summary Of Issued And Outstanding Preferred Stock) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014
Nonredeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Nonredeemable preferred stock, value	145
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	5.00%
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	6.00%
Redeemable Preferred Stock [Member] | Utility [Member]
Preferred Stock [Line Items]
Redeemable preferred stock, value	113
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Minimum [Member]
Preferred Stock [Line Items]
Redemption Price	25.75
Preferred stock interest rate	4.36%
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
Redemption Price	27.25
Preferred stock interest rate	5.00%

Earnings_Per_Share_Reconciliat

Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Shares Of Common Stock Outstanding For Calculating Diluted EPS) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Weighted average common shares outstanding, basic	468	444	424
Add Incremental Shares From Assumed conversions:
Employee share-based compensation	2	1	1
Weighted average common shares outstanding, diluted	470	445	425
Total earnings per common share, diluted	$3.06	$1.83	$1.92

Income_Taxes_Schedule_Of_Incom

Income Taxes (Schedule Of Income Tax Provision) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current, Federal	($84)	($218)	($74)
Current, State	-41	-26	33
Deferred, Federal	396	552	374
Deferred, State	78	-35	-92
Tax credits	-4	-5	-4
Income Tax Provision	345	268	237
Pacific Gas And Electric Company [Member]
Current, Federal	-84	-222	-52
Current, State	-29	-23	41
Deferred, Federal	426	604	404
Deferred, State	75	-28	-91
Tax credits	-4	-5	-4
Income Tax Provision	$384	$326	$298

Income_Taxes_Schedule_Of_Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Pacific Gas And Electric Company [Member]
Customer advances for construction	$88		$90
Reserve for damages	137		161
Environmental reserve	111		152
Compensation	36		102
Net operating loss carryforward	946		670
GHG Allowances	56		108
Other	100		128
Total deferred income tax assets	1,474		1,411
Regulatory balancing accounts	512		261
Property related basis differences	8,666		8,038
Income tax regulatory asset	974	[1]	748	[1]
Other	86		86
Total deferred income tax liabilities	10,238		9,133
Total net deferred income tax liabilities	8,764		7,722
Included in current liabilities (assets)	-9		-320
Included in noncurrent liabilities	8,773		8,042
Pg E Corporation [Member]
Customer advances for construction	88		90
Reserve for damages	137		161
Environmental reserve	111		152
Compensation	107		167
Net operating loss carryforward	1,177		890
GHG Allowances	56		108
Other	74		135
Total deferred income tax assets	1,750		1,703
Regulatory balancing accounts	512		261
Property related basis differences	8,683		8,048
Income tax regulatory asset	974	[1]	748	[1]
Other	88		151
Total deferred income tax liabilities	10,257		9,208
Total net deferred income tax liabilities	8,507		7,505
Included in current liabilities (assets)	-6		-318
Included in noncurrent liabilities	$8,513		$7,823
[1]	Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 above.)

Income_Taxes_Schedule_Of_Effec

Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pacific Gas And Electric Company [Member]
Federal statutory income tax rate	35.00%		35.00%		35.00%
State income tax (net of federal benefit)	1.60%	[1]	-2.20%	[1]	-3.00%	[1]
Effect of regulatory treatment of fixed asset differences	-14.70%	[2]	-3.80%	[2]	-3.90%	[2]
Tax credits	-0.70%		-0.40%		-0.60%
Benefit of loss carryback	-0.80%		-1.00%		-0.40%
Non deductible penalties	0.30%		0.70%		0.50%
Other, net	0.40%		-0.90%		-0.80%
Effective tax rate	21.10%		27.40%		26.80%
Pg E Corporation [Member]
Federal statutory income tax rate	35.00%		35.00%		35.00%
State income tax (net of federal benefit)	1.40%	[1]	-3.10%	[1]	-3.90%	[1]
Effect of regulatory treatment of fixed asset differences	-15.00%	[2]	-4.20%	[2]	-4.10%	[2]
Tax credits	-0.70%		-0.40%		-0.60%
Benefit of loss carryback	-0.80%		-1.10%		-0.70%
Non deductible penalties	0.30%		0.80%		0.60%
Other, net	-0.80%		-2.20%		-3.80%
Effective tax rate	19.40%		24.80%		22.50%
[1]	Includes the effect of state flow-through ratemaking treatment.
[2]	Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the ?2014 GRC Impact? section.

Income_Taxes_Schedule_Of_Chang

Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pacific Gas And Electric Company [Member]
Balance at beginning of year	$660	$575	$503
Additions for tax position taken during a prior year	7	12	26
Reductions for tax position taken during a prior year	-9	-6	-10
Additions for tax position taken during the current year	61	79	67
Settlements	-12	0	-11
Balance at end of year	707	660	575
Pg E Corporation [Member]
Balance at beginning of year	666	581	506
Additions for tax position taken during a prior year	7	12	32
Reductions for tax position taken during a prior year	-9	-6	-13
Additions for tax position taken during the current year	61	79	67
Settlements	-12	0	-11
Balance at end of year	$713	$666	$581

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2015	Dec. 31, 2014
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year		$20
Decrease of unrecognized tax benefit	330
Loss carryforwards, charitable contribution		219
Tax benefit from employee stock plans		24
Income Tax Expense Ratemaking		235
Charitable Contribution Carryforward Expiration Date [Minimum]		31-Dec-15
Charitable Contribution Carryforward Expiration Date [Maximum]		31-Dec-19
Minimum [Member]
Net operating loss expiration year		31-Dec-33
Maximum [Member]
Net operating loss expiration year		31-Dec-34
State [Member]
Net operating loss carryforwards		123
Tax credit carryforward, amount		30
Tax Credit Carryforward Expiration Date [Maximum]		31-Dec-24
Federal [Member]
Net operating loss carryforwards		4,100
Tax credit carryforwards, expiration amount		$77
Tax Credit Carryforward Expiration Date [Minimum]		31-Dec-29
Tax Credit Carryforward Expiration Date [Maximum]		31-Dec-34

Derivatives_And_Hedging_Activi2

Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)	Dec. 31, 2014		Dec. 31, 2013
	MWh		MWh
Forwards And Swaps [Member]
Derivative [Line Items]
Derivative Number of Instruments Held	5,346,787		8,089,269
Options [Member]
Derivative [Line Items]
Derivative Number of Instruments Held	164,418,002	[1],[2]	260,262,916	[1],[2]
Congestion Revenue Rights [Member]
Derivative [Line Items]
Derivative Number of Instruments Held	224,124,341	[3]	250,922,591	[3]
[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 congestion costs based on demand when there is insufficient transmission capacity.

Derivatives_And_Hedging_Activi3

Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$73	$42
Cash Collateral	19	16
Total Derivative Balances	88	48
Derivative Liability Offsetting Derivative Asset	-4	-10
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	178	99
Cash Collateral	0	0
Total Derivative Balances	165	95
Derivative Liability Offsetting Derivative Asset	-13	-4
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	-78	-122
Cash Collateral	26	69
Total Derivative Balances	-48	-43
Derivative Asset Offsetting Derivative Liability	4	10
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	-140	-110
Cash Collateral	9	2
Total Derivative Balances	-118	-104
Derivative Asset Offsetting Derivative Liability	13	4
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Gross Derivative Balance	33	-91
Netting [Member]
Derivatives And Hedging Activities [Line Items]
Derivative Asset Offsetting Derivative Liability	0	0
Cash Collatera [lMember]
Derivatives And Hedging Activities [Line Items]
Cash Collateral	54	87
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balances	$87	($4)

Derivatives_And_Hedging_Activi4

Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) (PGE Corporation Utility Member, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
PGE Corporation Utility Member
Unrealized (loss) gain - regulatory assets and liabilities	$124	[1]	$238	[1]	$391	[1]
Realized loss-cost of electricity	-83	[2]	-178	[2]	-486	[2]
Realized loss-cost of natural gas	-8	[2]	-22	[2]	-38	[2]
Total commodity risk instruments	$33		$38		($133)
[1]	Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the 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_And_Hedging_Activi5

Derivatives And Hedging Activities (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit-Risk-Related Contingency Features Were Triggered) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives And Hedging Activities [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	($47)		($79)
Related derivatives in an asset position	0		4
Collateral posting in the normal course of business related to these derivatives	44		65
Net position of derivative contracts/additional collateral posting requirements	($3)	[1]	($10)	[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 $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$324		$313
Estimate Of Fair Value Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	94		226
Total assets	3,399		3,374
Other investments	33		84
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	94		226
Total assets	2,478		2,622
Other investments	33		84
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	687		643
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	232		107
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	2	[1]	2	[1]
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	17		38
U.S. equity securities			1,046
Non-U.S. equity securities			457
Global equity securities	1,585
Fixed-income securities	741
U.S. government and agency securities			760
Municipal securities			0
Other fixed-income securities			0
Total assets	2,343	[2]	2,301	[3]
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities			11
Non-U.S. equity securities			0
Global equity securities	13
Fixed-income securities	389
U.S. government and agency securities			156
Municipal securities			25
Other fixed-income securities			162
Total assets	402	[2]	354	[3]
Nuclear Decommissioning Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	17		38
U.S. equity securities			1,057
Non-U.S. equity securities			457
Global equity securities	1,598
Fixed-income securities	1,130
U.S. government and agency securities			916
Municipal securities			25
Other fixed-income securities			162
Total assets	2,745	[2]	2,655	[3]
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	1		2
Electric	0		2
Gas	1		0
Electric	47		19
Gas	0		1
Total liabilities	47		20
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	18		32
Electric	17		27
Gas	1		5
Electric	5		72
Gas	3		3
Total liabilities	8		75
Price Risk Management Instruments [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	232		107
Electric	232		107
Electric	163		137
Total liabilities	163		137
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	2	[1]	2	[1]
Electric	2	[1]	3	[1]
Gas	0	[1]	-1	[1]
Electric	-52	[1]	-84	[1]
Gas	0	[1]	-1	[1]
Total liabilities	-52	[1]	-85	[1]
Price Risk Management Instruments [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	253		143
Electric	251		139
Gas	2		4
Electric	163		144
Gas	3		3
Total liabilities	166		147
Rabbi Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities	42		39
Life insurance contracts	72		70
Total assets	114		109
Rabbi Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities	42		39
Life insurance contracts	72		70
Total assets	114		109
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	7		9
Total assets	7		9
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities			14
Non-U.S. equity securities			12
Global equity securities	25
Fixed-income securities	128		122
Total assets	153		148
Long-Term Disability Trust [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	7		9
U.S. equity securities			14
Non-U.S. equity securities			12
Global equity securities	25
Fixed-income securities	128		122
Total assets	$160		$157
[1]	Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
[2]	Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
[3]	Represents amount before deducting $313 million, primarily related to deferred taxes on appreciation of investment value.

Fair_Value_Measurements_Level_

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$232		$107
Liabilities, Fair Value	63		32
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	$100		$105
Fair value measurement Valuation technique	Discounted cash flow		Discounted cash flow
Fair value measurement Unobservable Input	Forward prices		Forward prices
Minimum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	15.97	[1]	-6.47	[1]
Minimum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	16.04	[1]	23.43	[1]
Maximum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	8.17	[1]	12.04	[1]
Maximum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	56.21	[1]	51.75	[1]
[1]	Represents price per megawatt-hour

Fair_Value_Measurements_Level_1

Fair Value Measurements (Level 3 Reconciliation) (Details) (Fair Value, Inputs, Level 3 [Member], Price Risk Management Instruments [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Inputs, Level 3 [Member] | Price Risk Management Instruments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1	($30)		($79)
Realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts	99	[1]	49	[1]
Liability balance as of December 31	$69		($30)
[1]	The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

Fair_Value_Measurements_Carryi

Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Carrying Amount [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$350	$350
Carrying Amount [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	13,778	12,334
Estimate Of Fair Value [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	352	354
Estimate Of Fair Value [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$15,851	$13,444

Fair_Value_Measurements_Schedu

Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Schedule of Available-for-sale Securities [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$324		$313
Cash And Cash Equivalents [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	17		38
Total Fair Value	17		38
U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost			246
Total Unrealized Gains			811
Total Unrealized Losses			0
Total Fair Value			1,057
Non-U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost			215
Total Unrealized Gains			242
Total Unrealized Losses			0
Total Fair Value			457
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	520
Total Unrealized Gains	1,087
Total Unrealized Losses	-9
Total Fair Value	1,598
U.S. Government And Agency Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost			870
Total Unrealized Gains			51
Total Unrealized Losses			-5
Total Fair Value			916
Municipal Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost			24
Total Unrealized Gains			2
Total Unrealized Losses			-1
Total Fair Value			25
Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,059		163
Total Unrealized Gains	75		1
Total Unrealized Losses	-4		-2
Total Fair Value	1,130		162
Securities (Assets) [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,601		1,569
Total Unrealized Gains	1,190		1,178
Total Unrealized Losses	-13		-8
Total Fair Value	2,778		2,739
Other securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	5		13
Total Unrealized Gains	28		71
Total Unrealized Losses	0		0
Total Fair Value	33		84
Nuclear Decommissioning Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	1,596	[1]	1,556	[1]
Total Unrealized Gains	1,162	[1]	1,107	[1]
Total Unrealized Losses	-13	[1]	-8	[1]
Total Fair Value	$2,745	[1]	$2,655	[1]
[1]	Represents amounts before deducting $324 million and $313 million at December 31, 2014 and 2013, respectively, primarily related to deferred taxes on appreciation of investment value.

Fair_Value_Measurements_Schedu1

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value Measurements [Abstract]
Less than 1 year	$17
1-5 years	466
5-10 years	263
More than 10 years	384
Total maturities of debt securities	$1,130

Fair_Value_Measurements_Schedu2

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$1,336	$1,619	$1,133
Gross realized gains on sales of securities held as available-for-sale	118	94	19
Gross realized losses on sales of securities held as available-for-sale	($12)	($13)	($17)

Employee_Benefit_Plans_Reconci

Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability	($2,561)		($1,601)
Accumulated benefit obligation	14,900		12,600
Decrease in other comprehensive income	14		-113		-108
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	1,892		1,758
Actual return on plan assets	241		64
Company contributions	57		145
Plan participant contribution	63		64
Benefits and expenses paid	-161		-139
Fair value of plan assets at December 31	2,092		1,892		1,758
Projected benefit obligation at January 1	1,597		1,940
Service cost for benefits earned	45		53
Interest cost	76		74		83
Actuarial (gain) loss	-166		-415
Benefits and expenses paid	-140		-123
Federal subsidy on benefits paid	4		4
Projected benefit obligation at December 31	1,811		1,597		1,940
Noncurrent liability	-87	[1]	-57	[1]
Net assets (liabilities) at end of year	-281	[1]	-295	[1]
Noncurrent asset	368	[1]	352	[1]
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	12,527		12,141
Actual return on plan assets	1,946		673
Company contributions	332		323
Benefits and expenses paid	-589		-610
Fair value of plan assets at December 31	14,216		12,527		12,141
Projected benefit obligation at January 1	14,077		15,541
Service cost for benefits earned	383		468
Interest cost	695		627		658
Actuarial (gain) loss	2,131		-1,950
Plan amendments	-1		0
Transitional costs	0		1
Benefits and expenses paid	-589		-610
Projected benefit obligation at December 31	16,696	[2]	14,077		15,541
Current liability	-6		-6
Noncurrent liability	-2,474		-1,544
Net assets (liabilities) at end of year	($2,480)		($1,550)
[1]	At December 31, 2014 and 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
[2]	PG&E Corporation?s accumulated benefit obligation was $14.9 billion and $12.6 billion at December 31, 2014 and 2013, respectively.

Employee_Benefit_Plans_Compone

Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$45		$53		$49
Interest cost	76		74		83
Expected return on plan assets	-103		-79		-77
Amortization of transition obligation	0		0		24
Amortization of prior service cost	23		23		25
Amortization of net actuarial loss	2		6		6
Net periodic benefit cost	43		77		110
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	383		468		396
Interest cost	695		627		658
Expected return on plan assets	-807		-650		-598
Amortization of prior service cost	20		20		20
Amortization of net actuarial loss	2		111		123
Net periodic benefit cost	293		576		599
Less: transfer to regulatory account	42	[1]	-238	[1]	-301	[1]
Total	$335		$338		$298
[1]	The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Employee_Benefit_Plans_Estimat

Employee Benefit Plans (Estimated Amortized Net Periodic Benefit For 2012) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	$19
Unrecognized net actuarial loss	4
Total	23
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	15
Unrecognized net actuarial loss	11
Total	$26

Employee_Benefit_Plans_Schedul

Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.20%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate range	3.89-4.09	4.70-5.00	3.75-4.08
Expected return on plan assets percentage range	3.30-6.70	3.50-6.70	2.90-6.10
Benefit obligation increase	$18
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.00%	4.89%	3.98%
Average rate of future compensation increases	4.00%	4.00%	4.00%
Expected return on plan assets	6.20%	6.50%	5.40%
Benefit obligation increase	$82

Employee_Benefit_Plans_Schedul1

Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$107
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	-108
Effect on service and interest cost, One-Percentage-Point Increase	8
Effect on service and interest cost, One-Percentage-Point Decrease	($8)
Assumed health care cost trend rate	7.50%
Ultimate trend rate	3.50%
Year of ultimate trend rate	2024
Assumed return	6.20%
10 year actual rate of return	9.30%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used	715

Employee_Benefit_Plans_Target_

Employee Benefit Plans (Target Asset Allocation Percentages) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target allocation percentage of assets, Total	100.00%	100.00%	100.00%
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, target allocation percentage of assets, Total	100.00%	100.00%	100.00%
Fixed Income Securities[Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	58.00%	59.00%	60.00%
Fixed Income Securities[Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	60.00%	60.00%	60.00%
Real Assets [member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	8.00%	8.00%	8.00%
Real Assets [member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	10.00%	10.00%	10.00%
Absolute Return [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	3.00%	3.00%	4.00%
Absolute Return [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	5.00%	5.00%	5.00%
Global Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	31.00%	30.00%	28.00%
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	25.00%	25.00%	25.00%

Employee_Benefit_Plans_Schedul2

Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$16,284	$14,288
Total Fair Value Of Trust Other Net Assets	24	131
Notice To Redeem Investments days [maximum]	90 days
Money Market Investments Net Asset Value Per Unit	$1
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,096	1,895
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	14,188	12,393
Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	387	362
Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,958	3,203
Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,604	1,440
Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	8,340	7,467
Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	105	93	78
Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,890	1,723	1,409
Short-term investments [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	28	31
Short-term investments [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	663	70
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	28	31
Short-term investments [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	352	70
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Short-term investments [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	311	0
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Short-term investments [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans			285
Residential Real Estate [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	121	105
Residential Real Estate [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	1,295	1,106
Residential Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	72	67
Residential Real Estate [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	620	562
Residential Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Residential Real Estate [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Residential Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans		38
Residential Real Estate [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	675	544
Global Equity Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	673	631
Global Equity Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	3,229	3,486
Global Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	124	127
Global Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	918	1,123
Global Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	549	504
Global Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,311	2,363
Global Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Global Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	55	53
Absolute Return [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	577	554
Absolute Return [Member] | Fair Value, Inputs, Level 1 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 2 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	0	0
Absolute Return [Member] | Fair Value, Inputs, Level 3 [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	55	53
Absolute Return [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans		$554

Employee_Benefit_Plans_Schedul3

Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	$16,284	$14,288
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	2,096	1,895
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	387	362
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	1,604	1,440
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	93	78
Relating to assets still held at the reporting date	6	7
Relating to assets sold during the period	0	0
Purchases	7	34
Settlements	-1	-26
Balance as of December 31	105	93
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	14,188	12,393
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	3,958	3,203
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	8,340	7,467
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,723	1,409
Relating to assets still held at the reporting date	101	87
Relating to assets sold during the period	4	1
Purchases	79	372
Settlements	-17	-146
Balance as of December 31	1,890	1,723
Real Estate [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	38	28
Relating to assets still held at the reporting date	4	3
Relating to assets sold during the period	0	0
Purchases	7	21
Settlements	0	-14
Balance as of December 31	49	38
Real Estate [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	544
Relating to assets still held at the reporting date	54	49
Relating to assets sold during the period	0	-3
Purchases	78	352
Settlements	-1	-139
Balance as of December 31	675	544
Absolute Return [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	53	49
Relating to assets still held at the reporting date	2	4
Relating to assets sold during the period	0	0
Purchases	0	12
Settlements	0	-12
Balance as of December 31	55	53
Absolute Return [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1		513
Relating to assets still held at the reporting date	23	37
Relating to assets sold during the period	0	4
Purchases	0	0
Settlements	0	0
Balance as of December 31	577
Corporate Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	1,219
Corporate Fixed Income Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31		1,075
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	163	137
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	1,055	936
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	2	1
Relating to assets still held at the reporting date	0	0
Relating to assets sold during the period	0	0
Purchases	0	1
Settlements	-1	0
Balance as of December 31	1	2
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	8,424	7,177
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	2,068	1,448
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of December 31	5,718	5,104
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	625	611
Relating to assets still held at the reporting date	24	1
Relating to assets sold during the period	4	0
Purchases	1	20
Settlements	-16	-7
Balance as of December 31	$638	$625

Employee_Benefit_Plans_Schedul4

Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$653
2016	696
2017	737
2018	775
2019	812
Thereafter in the succeeding five years	4,545
Contributed to the other benefit plans	332	323
Approximate contribution expected to be paid	327
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	91
2016	96
2017	102
2018	109
2019	115
Thereafter in the succeeding five years	614
Contributed to the other benefit plans	57	145
Approximate contribution expected to be paid	61
Federal Subsidy [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	-7
2016	-8
2017	-8
2018	-9
2019	-10
Thereafter in the succeeding five years	($29)

Employee_Benefit_Plans_Schedul5

Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Employee Benefit Plans [Abstract]
Retirement Savings Plan expense	$80	$71	$67

Resolution_Of_Remaining_Chapte1

Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Interest payable on disputed claims		$710
Pacific Gas And Electric Company [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Remaining disputed claims	434	154
CAISO And PX [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing	291	291
Settlement Refund	$312

Related_Party_Agreements_And_T2

Related Party Agreements And Transactions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Current receivables	$17	$22
Current payables	20	17
Administrative Services Provided To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility revenues from	5	7	7
Administrative Services Received From PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	54	45	50
Utility Employee Benefit Due To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	$70	$57	$51

Commitments_And_Contingencies_1

Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) (USD $)	12 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Violations	3,700
Disallowed capital expenditure losses	$116,000,000	$116,000,000	$196,000,000	$353,000,000
Reduced Expense Funding	23,000,000
Capitalized PSEP costs	766,000,000	766,000,000
Amount of capital included in property plant and equipment	549,000,000	549,000,000
CPUC approved PSEP-related revenue requirements	223,000,000
Self-reports filed	84
Self-reports not investigated further	65
PGE Corporation Utility Member
Loss Contingencies [Line Items]
Accrued legal liabilities	55,000,000	55,000,000	43,000,000
Probable penalty amount	200,000,000	200,000,000
Utility [Member]
Loss Contingencies [Line Items]
Future expected PSEP costs exceeding authorized amounts	209,000,000	209,000,000
State General Fund [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Penalty Issued By ALJS	950,000,000
Refund to Ratepayers of Previously Authorized Revenues [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Penalty Issued By ALJS	400,000,000
Estimated Remedial Measures [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Penalty Issued By ALJS	50,000,000
Various Parties Apeal of CPUC Penalty Decision [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Proposed payment to State General Fund	473,000,000
Disallowed capital expenditure losses	877,000,000	877,000,000
Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Penalty for each count of alleged violation	500,000
Total maximum penalties	14,000,000
Maximum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Fines Imposed in GT&S Rate Case	250,000,000
S E D fines for self reported violations	16,800,000
Minimum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Fines Imposed in GT&S Rate Case	2,500,000
S E D fines for self reported violations	50,000
Ex Parte Communications [Member] | Utility [Member]
Loss Contingencies [Line Items]
CPUC imposed fine		1,050,000
Number of email communications	65,000
Probable 2010 incentive awards rescinded	29,000,000
Carmel Incident [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Fine for alleged violation	10,850,000
Original Indictment [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts	12
Superceeding Indictment [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts	15
Gross gain derived from alleged violation	281,000,000
Gross loss derived from alleged violation	565,000,000
Maximum alternative fine sought	$1,130,000,000
Alleged Obstruction of NTSB Investigation [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts	1

Commitments_And_Contingencies_2

Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Topock natural gas compressor station	$291	[1]	$264	[1]
Hinkley natural gas compressor station	158	[1]	190	[1]
Former manufactured gas plant sites owned by the Utility or third parties	257		184
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites	150		160
Fossil fuel-fired generation facilities and sites	98		102
Total environmental remediation liability	$954		$900
[1]	See Natural Gas Compressor Station Sites below.

Commitments_And_Contingencies_3

Commitments And Contingencies (Environmental Remediation Contingencies) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$663
Utility Undiscounted Future Costs	$1,800
Remediation cost recovery	90.00%

Commitments_And_Contingencies_4

Commitments And Contingencies (Nuclear Insurance) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Humboldt Bay Unit 3 potential premium obligation	$51
Coverage for purchased public liability insurance, per incident	375
Diablo Canyon [Member]
Long-term Purchase Commitment [Line Items]
Maximum public liability per nuclear incident under Price-Anderson Act	13,600
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	375
Maximum public liability claims amount per nuclear event	13,600
Maximum total payment incurred per event under the loss sharing program	255
Maximum annual payment incurred per event under the loss sharing program	38
Diablo Canyon [Member] | Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	3,200
Diablo Canyon [Member] | Non Nuclear Incident [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	2,600
Humboldt Bay Unit [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	131
Amount of indemnification from the NRC for public liability arising from nuclear incidents	500
Amount of liability insurance for Humboldt bay Unit 3	$53

Commitments_And_Contingencies_5

Commitments And Contingencies (Third-Party Power Purchases) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Long-term Purchase Commitment [Line Items]
2015	$4,248
2016	3,769
2017	3,601
2018	3,398
2019	3,279
Thereafter	34,973
Total	53,268
Renewable Energy Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2015	2,145
2016	2,185
2017	2,187
2018	2,063
2019	2,053
Thereafter	30,289
Total	40,922
Qualifying Facilities [Member]
Long-term Purchase Commitment [Line Items]
2015	601
2016	525
2017	418
2018	382
2019	304
Thereafter	1,217
Total	3,447
Other Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2015	820
2016	766
2017	758
2018	731
2019	706
Thereafter	2,390
Total	6,171
Nuclear Fuel Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
2015	138
2016	129
2017	131
2018	115
2019	109
Thereafter	429
Total	1,051
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
2015	544
2016	164
2017	107
2018	107
2019	107
Thereafter	648
Total	$1,677

Commitments_And_Contingencies_6

Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2015
Long term contract for purchase commitments, date of contract expiration, ending date	2028
Present value of fixed capacity payments, portion classified as current liabilities	$20	$23
Present value of fixed capacity payments, portion classified as noncurrent liabilities	54	74
Capitalized asset for fixed capacity payments for corresponding assets	74	97
Capitalized asset for fixed capacity payments, accumulated amortization	108	176
Renewable Energy [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2016
Long term contract for purchase commitments, date of contract expiration, ending date	2043
Power Purchases and Electric Capacity [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2015
Long term contract for purchase commitments, date of contract expiration, ending date	2033
Costs Of Power Purchase	$3,600	$3,000	$2,300

Commitments_And_Contingencies_7

Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	$1,400	$1,600	$1,300
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2015
Long Term Contract For Purchase Commitments Expiration Ending Date	2026

Commitments_And_Contingencies_8

Commitments And Contingencies (Nuclear Fuel Agreements) (Details) (Nuclear Fuel [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Nuclear Fuel [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2015
Long Term Contract For Purchase Commitments Expiration Ending Date	2025
Payments for Nuclear Fuel	$105	$162	$118

Schedule_I_Condensed_Financial2

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating expenses	($14,640)	($13,836)	($13,347)
Interest income	9	9	7
Interest expense	-734	-715	-703
Other income, net	70	40	70
Income Before Income Taxes	1,795	1,096	1,067
Income tax provision	345	268	237
Income Available for Common Shareholders	1,436	814	816
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Net change in investments (net of taxes $17, $26, and $3, at respective dates)	-25	38	4
Total other comprehensive income (loss)	-39	151	112
Comprehensive Income	1,411	979	942
Weighted average common shares outstanding, basic	468	444	424
Weighted average common shares outstanding, diluted	470	445	425
Net earnings per common share, basic	$3.07	$1.83	$1.92
Net earnings per common share, diluted	$3.06	$1.83	$1.92
PG&E Corporation [Member]
Administrative service revenue	51	41	43
Operating expenses	-53	-42	-41
Interest income	1	1	1
Interest expense	-14	-25	-22
Other income, net	-1	-57	-39
Equity in earnings of subsidiaries	1,413	848	817
Income Before Income Taxes	1,397	766	759
Income tax provision	39	48	57
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Pension and other postretirement benefit plans (net of taxes of $10, $80, $72, at respective dates)	-14	113	108
Net change in investments (net of taxes $17, $26, and $3, at respective dates)	-25	38	4
Total other comprehensive income (loss)	-39	151	112
Comprehensive Income	$1,397	$965	$928
Weighted average common shares outstanding, basic	468	444	424
Weighted average common shares outstanding, diluted	470	445	425
Net earnings per common share, basic	$3.07	$1.83	$1.92
Net earnings per common share, diluted	$3.06	$1.83	$1.92

Schedule_I_Condensed_Financial3

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Cash and cash equivalents	$151	$296	$401	$513
Advances to affiliates	20	17
Income taxes receivable	198	574
Other Assets, Current	443	611
Total current assets	6,389	5,977
Equipment	63,062	59,096
Accumulated depreciation	-19,121	-17,844
Net property, plant, and equipment	43,941	41,252
Income taxes receivable	91	85
Other	963	1,036
TOTAL ASSETS	60,127	55,605
Short-term borrowings	633	1,174
Long-term debt, classified as current	0	889
Other	1,846	1,612
Total current liabilities	5,920	7,493
Long-term debt	15,050	12,717
Other	2,218	2,178
Total noncurrent liabilities	38,207	33,518
Common stock	10,421	9,550
Reinvested earnings	5,316	4,742
Accumulated other comprehensive income (loss)	11	50	-101
Total shareholders' equity	15,748	14,342
TOTAL LIABILITIES AND EQUITY	60,127	55,605
PG&E Corporation [Member]
Long-term debt	350	0
PG&E Corporation [Member]
Cash and cash equivalents	231	207	207	209
Advances to affiliates	30	26
Income taxes receivable	13	33
Other Assets, Current	86	0
Total current assets	360	226
Equipment	2	1
Accumulated depreciation	-1	-1
Net property, plant, and equipment	1	0
Investments in subsidiaries	14,711	13,387
Other investments	110	102
Income taxes receivable	5	5
Deferred income taxes	188	178
Other	0	1
Total noncurrent assets	15,015	13,673
TOTAL ASSETS	15,375	13,939
Short-term borrowings	260	120
Long-term debt, classified as current	350	0
Accounts payable - related parties	66	48
Accounts payable - other	230	221
Total current liabilities	906	289
Long-term debt	0	349
Other	127	127
Total noncurrent liabilities	127	476
Common stock	9,550	8,428
Reinvested earnings	4,742	4,747
Accumulated other comprehensive income (loss)	50	-101
Total shareholders' equity	14,342	13,074
TOTAL LIABILITIES AND EQUITY	$15,375	$13,939

Schedule_I_Condensed_Financial4

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Net income	$1,450		$828		$830
Deferred income taxes and tax credits, net	690		1,075		648
Net cash provided by operating activities	3,677		3,427		4,882
Other	114		56		104
Net cash provided by (used in) investing activities	-4,714		-5,107		-4,526
Borrowings under revolving credit facilities	0		140		120
Repayments under revolving credit facilities	-260		0		0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014	2,308		1,532		1,137
Long-Term Debt Repurchased	889		861		50
Common stock issued	802		1,045		751
Common stock dividends paid	-828		-782		-746
Other	42		-41		14
Net cash (used) in financing activities	892		1,575		-468
Net change in cash and cash equivalents	-145		-105		-112
Cash and cash equivalents at January 1	296		401		513
Cash and cash equivalents at December 31	151		296		401
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	17		18		13
Cash received (paid) for:
Interest, net of amounts capitalized	-633		-623		-594
Income taxes, net	501		-41		114
Noncash common stock issuances	-21		-22		-22
Common stock dividends declared but not yet paid	-217		208		196
PG&E Corporation [Member]
Net income	1,436		814		816
Depreciation and amortization	65		54		51
Equity in earnings of subsidiaries	-1,413		-848		-817
Deferred income taxes and tax credits, net	-72		-10		-31
Noncurrent income taxes receivable/payable	5		0		-6
Current income taxes receivable/payable	-16		20		-82
Other	43		-20		20
Net cash provided by operating activities	48		10		-49
Investment in subsidiaries	-978	[1]	-1,371	[1]	-1,023	[1]
Dividends received from subsidiaries	716		716		716
Proceeds from tax equity investments	368		275		228
Other	0		-8		0
Net cash provided by (used in) investing activities	106		-388		-79
Borrowings under revolving credit facilities	0		140		120
Repayments under revolving credit facilities	-260		0		0
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014	347		0		0
Long-Term Debt Repurchased	-350		0		0
Common stock issued	802		1,045		751
Common stock dividends paid	828	[2]	-782	[2]	-746	[2]
Other	0		-1		1
Net cash (used) in financing activities	-289		402		126
Net change in cash and cash equivalents	-135		24		-2
Cash and cash equivalents at January 1	207		207		209
Cash and cash equivalents at December 31	231		207		207
Cash received (paid) for:
Interest, net of amounts capitalized	-15		-23		-20
Income taxes, net	1		21		-60
Noncash common stock issuances	21		22		22
Common stock dividends declared but not yet paid	$217		$208		$196
[1]	Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
[2]	In January, April, July, and October of 2014, 2013, and 2012, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule_II_Consolidated_Valua2

Schedule II - Consolidated Valuation And Qualifying Accounts (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Allowance for uncollectible accounts, Balance at Beginning of Period	$80	[1]	$87	[1]	$81	[1]
Allowance for uncollectible accounts, Charged to Costs and Expenses	41	[1]	53	[1]	66	[1]
Charged to other accounts	0	[1]	0	[1]	0	[1]
Allowance for uncollectible accounts, Deductions	55	[1],[2]	60	[1],[2]	60	[1],[2]
Allowance for uncollectible accounts, Balance at End of Period	$66	[1]	$80	[1]	$87	[1]
[1]	Allowance for uncollectible accounts is deducted from Accounts receivable - Customers.
[2]	Deductions consist principally of write-offs, net of collections of receivables previously written off.