PG&E (PCG) 10-K 18 Feb 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	PG&E CORP
Entity Central Index Key	1,004,980
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,015
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			$ 23,628
Entity Common Stock, Shares Outstanding		492,830,471
Pacific Gas And Electric Company [Member]
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Entity Filer Category	Non-accelerated Filer
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	75,488
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2,015
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 Inco

Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues
Electric	$ 13,657	$ 13,658	$ 12,494
Natural gas	3,176	3,432	3,104
Total operating revenues	16,833	17,090	15,598
Operating Expenses
Cost of electricity	5,099	5,615	5,016
Cost of natural gas	663	954	968
Operating and maintenance	6,951	5,638	5,775
Depreciation, amortization, and decommissioning	2,612	2,433	2,077
Total operating expenses	15,325	14,640	13,836
Operating Income	1,508	2,450	1,762
Interest income	9	9	9
Interest expense	(773)	(734)	(715)
Other income (expense)	117	70	40
Income Before Income Taxes	861	1,795	1,096
Income tax benefit	(27)	345	268
Net Income	888	1,450	828
Preferred stock dividend requirement of subsidiary	14	14	14
Income Available for Common Shareholders	$ 874	$ 1,436	$ 814
Weighted Average Common Shares Outstanding, Basic	484	468	444
Weighted Average Common Shares Outstanding, Diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net Earnings Per Common Share, Diluted	$ 1.79	$ 3.06	$ 1.83
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	$ 13,657	$ 13,656	$ 12,489
Natural gas	3,176	3,432	3,104
Total operating revenues	16,833	17,088	15,593
Operating Expenses
Cost of electricity	5,099	5,615	5,016
Cost of natural gas	663	954	968
Operating and maintenance	6,949	5,635	5,742
Depreciation, amortization, and decommissioning	2,611	2,432	2,077
Total operating expenses	15,322	14,636	13,803
Operating Income	1,511	2,452	1,790
Interest income	8	8	8
Interest expense	(763)	(720)	(690)
Other income (expense)	87	77	84
Income Before Income Taxes	843	1,817	1,192
Income tax benefit	(19)	384	326
Net Income	862	1,433	866
Preferred stock dividend requirement	14	14	14
Income Available for Common Shareholders	$ 848	$ 1,419	$ 852

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income	$ 888	$ 1,450	$ 828
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $0, $10 and $80 and related to the Utility of $1, $6, and $75, at respective dates)	(1)	(14)	113
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	870	1,411	979
Preferred stock dividend requirement of subsidiary	14	14	14
Comprehensive Income Attributable to Common Shareholders	856	1,397	965
Pacific Gas And Electric Company [Member]
Net income	862	1,433	866
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (related to PG&E Corporation net of income tax of $0, $10 and $80 and related to the Utility of $1, $6, and $75, at respective dates)	(2)	(8)	106
Total other comprehensive income (loss)	(2)	(8)	106
Comprehensive Income	$ 860	$ 1,425	$ 972

Consolidated Statements Of Com4

Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension and other postretirement benefit plans obligations tax	$ 0	$ 10	$ 80
Change in investments tax	12	17	26
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$ 1	$ 6	$ 75

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 123	$ 151
Restricted cash	234	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66 at respective dates)	1,106	960
Accrued unbilled revenue	855	776
Regulatory balancing accounts	1,760	2,266
Other	286	377
Regulatory assets	517	444
Inventories
Gas stored underground and fuel oil	126	172
Materials and supplies	313	304
Income taxes receivable	155	198
Other	347	443
Total current assets	5,822	6,389
Property, Plant, and Equipment
Electric	48,532	45,162
Gas	16,749	15,678
Construction work in progress	2,059	2,220
Other	2	2
Total property, plant, and equipment	67,342	63,062
Accumulated depreciation	(20,619)	(19,121)
Net property, plant, and equipment	46,723	43,941
Other Noncurrent Assets
Regulatory assets	7,029	6,322
Nuclear decommissioning trusts	2,470	2,421
Income taxes receivable	135	91
Other	1,160	963
Total other noncurrent assets	10,794	9,797
TOTAL ASSETS	63,339	60,127
Current Liabilities
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Accounts payable
Trade creditors	1,414	1,244
Regulatory balancing accounts	715	1,090
Other	398	476
Disputed claims and customer refunds	454	434
Interest payable	206	197
Other	1,997	1,846
Total current liabilities	6,363	5,920
Noncurrent Liabilities
Long-term debt	16,030	15,050
Regulatory liabilities	6,321	6,290
Pension and other postretirement benefits	2,622	2,561
Asset retirement obligations	3,643	3,575
Deferred income taxes	9,206	8,513
Other	2,326	2,218
Total noncurrent liabilities	$ 40,148	$ 38,207
Commitments and Contingencies (Note 13)
Shareholders' Equity
Common stock	$ 11,282	$ 10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive(loss)income	(7)	11
Total shareholders' equity	16,576	15,748
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	16,828	16,000
TOTAL LIABILITIES AND EQUITY	63,339	60,127
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	59	55
Restricted cash	234	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $54 and $66 at respective dates)	1,106	960
Accrued unbilled revenue	855	776
Regulatory balancing accounts	1,760	2,266
Other	284	375
Regulatory assets	517	444
Inventories
Gas stored underground and fuel oil	126	172
Materials and supplies	313	304
Income taxes receivable	130	168
Other	346	409
Total current assets	5,730	6,227
Property, Plant, and Equipment
Electric	48,532	45,162
Gas	16,749	15,678
Construction work in progress	2,059	2,220
Total property, plant, and equipment	67,340	63,060
Accumulated depreciation	(20,617)	(19,120)
Net property, plant, and equipment	46,723	43,940
Other Noncurrent Assets
Regulatory assets	7,029	6,322
Nuclear decommissioning trusts	2,470	2,421
Income taxes receivable	135	91
Other	1,053	864
Total other noncurrent assets	10,687	9,698
TOTAL ASSETS	63,140	59,865
Current Liabilities
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Accounts payable
Trade creditors	1,414	1,243
Regulatory balancing accounts	715	1,090
Other	418	444
Disputed claims and customer refunds	454	434
Interest payable	203	195
Other	1,750	1,604
Total current liabilities	6,133	5,643
Noncurrent Liabilities
Long-term debt	15,680	14,700
Regulatory liabilities	6,321	6,290
Pension and other postretirement benefits	2,534	2,477
Asset retirement obligations	3,643	3,575
Deferred income taxes	9,487	8,773
Other	2,282	2,178
Total noncurrent liabilities	$ 39,947	$ 37,993
Commitments and Contingencies (Note 13)
Shareholders' Equity
Preferred stock	$ 258	$ 258
Common stock	1,322	1,322
Additional paid-in capital	7,215	6,514
Reinvested earnings	8,262	8,130
Accumulated other comprehensive(loss)income	3	5
Total shareholders' equity	17,060	16,229
TOTAL LIABILITIES AND EQUITY	$ 63,140	$ 59,865

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 54	$ 66
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	492,025,443	475,913,404
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$ 54	$ 66
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 Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Operating Activities
Net income	$ 888	$ 1,450	$ 828
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,612	2,433	2,077
Allowance for equity funds used during construction	(107)	(100)	(101)
Deferred income taxes and tax credits, net	693	690	1,075
Disallowed capital expenditures	407	116	196
Other	326	286	355
Effect of changes in operating assets and liabilities:
Accounts receivable	(177)	13	(152)
Inventories	37	(22)	(10)
Accounts payable	(55)	(61)	113
Income taxes receivable/payable	43	376	(363)
Other current assets and liabilities	(315)	205	(469)
Regulatory assets, liabilities, and balancing accounts, net	(244)	(1,642)	(202)
Other noncurrent assets and liabilities	(355)	(67)	80
Net cash provided by operating activities	3,753	3,677	3,427
Cash Flows from Investing Activities
Capital expenditures	(5,173)	(4,833)	(5,207)
Decrease in restricted cash	64	3	29
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,268	1,336	1,619
Purchases of nuclear decommissioning trust investments	(1,392)	(1,334)	(1,604)
Other	22	114	56
Net cash used in investing activities	(5,211)	(4,714)	(5,107)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities	0	(260)	140
Net issuances (repayments) of commercial paper, net of discount of $3, $2, and $2 at respective dates	683	(583)	542
Proceeds from issuance of short-term debt, net of issuance costs	0	300	0
Short-term debt matured	(300)	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $27, $17, and $18 and for the Utility $27, $14, and $18, at respective dates)	1,123	2,308	1,532
Repayments of long-term debt	0	(889)	(861)
Common stock issued	780	802	1,045
Common stock dividends paid	(856)	(828)	(782)
Other	0	42	(41)
Net cash provided by (used in) financing activities	1,430	892	1,575
Net change in cash and cash equivalents	(28)	(145)	(105)
Cash and cash equivalents at January 1	151	296	401
Cash and cash equivalents at December 31	123	151	296
Cash received (paid) for:
Interest, net of amounts capitalized	(684)	(633)	(623)
Income taxes, net	77	501	(41)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	224	217	208
Capital expenditures financed through accounts payable	440	339	322
Noncash common stock issuances	21	21	22
Terminated Capital Leases	0	71	0
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	862	1,433	866
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,611	2,432	2,077
Allowance for equity funds used during construction	(107)	(100)	(101)
Deferred income taxes and tax credits, net	714	731	1,103
Disallowed capital expenditures	407	116	196
Other	263	226	299
Effect of changes in operating assets and liabilities:
Accounts receivable	(177)	16	(152)
Inventories	37	(22)	(10)
Accounts payable	(2)	(55)	99
Income taxes receivable/payable	38	395	(377)
Other current assets and liabilities	(342)	155	(404)
Regulatory assets, liabilities, and balancing accounts, net	(244)	(1,642)	(202)
Other noncurrent assets and liabilities	(340)	(66)	22
Net cash provided by operating activities	3,720	3,619	3,416
Cash Flows from Investing Activities
Capital expenditures	(5,173)	(4,833)	(5,207)
Decrease in restricted cash	64	3	29
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,268	1,336	1,619
Purchases of nuclear decommissioning trust investments	(1,392)	(1,334)	(1,604)
Other	22	29	21
Net cash used in investing activities	(5,211)	(4,799)	(5,142)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $3, $2, and $2 at respective dates	683	(583)	542
Proceeds from issuance of short-term debt, net of issuance costs	0	300	0
Short-term debt matured	(300)	0	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of (for PG&E Corporaiton $27, $17, and $18 and for the Utility $27, $14, and $18, at respective dates)	1,123	1,961	1,532
Repayments of long-term debt	0	(539)	(861)
Preferred stock dividends paid	(14)	(14)	(14)
Common stock dividends paid	(716)	(716)	(716)
Equity contribution from PG&E Corporation	705	705	1,140
Other	14	56	(26)
Net cash provided by (used in) financing activities	1,495	1,170	1,597
Net change in cash and cash equivalents	4	(10)	(129)
Cash and cash equivalents at January 1	55	65	194
Cash and cash equivalents at December 31	59	55	65
Cash received (paid) for:
Interest, net of amounts capitalized	(675)	(618)	(600)
Income taxes, net	77	500	(62)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	440	339	322
Terminated Capital Leases	$ 0	$ 71	$ 0

Consolidated Statements Of Cas8

Consolidated Statements Of Cash Flows (Parenthetical) - Pacific Gas And Electric Company [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows from Financing Activities
Net issuances of commercial paper, discount	$ 3	$ 2	$ 2
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs	$ 27	$ 14	$ 18

Consolidated Statements Of Equi

Consolidated Statements Of Equity - USD ($) $ in Millions	Total	Pacific Gas And Electric Company [Member]	Common Stock Shares [Member]	Common Stock Shares [Member]Pacific Gas And Electric Company [Member]	Preferred Stock [Member]Pacific Gas And Electric Company [Member]	Common Stock Amount [Member]	Additional Paid-In Capital [Member]Pacific Gas And Electric Company [Member]	Reinvested Earnings [Member]	Reinvested Earnings [Member]Pacific Gas And Electric Company [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]Pacific Gas And Electric Company [Member]	Total Shareholders' Equity [Member]	Total Shareholders' Equity [Member]Pacific Gas And Electric Company [Member]	Noncontrolling Interest - Preferred Stock Of Subsidiary [Member]
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 from PG&E Corporation		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
Tax expense from employee stock plans	(1)					(1)	(1)					(1)	(1)
Common stock dividends declared	(819)							(819)	(716)			(819)	(716)
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
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 from PG&E Corporation		$ 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
Tax expense from employee stock plans	(17)					(17)	(12)					(17)	(12)
Common stock dividends declared	(862)							(862)	(716)			(862)	(716)
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
Net income	$ 888	$ 862						888	862			888	862
Other comprehensive income (loss)	(18)	(2)								(18)	(2)	(18)	(2)
Equity contribution from PG&E Corporation		$ 705					705						705
Common stock issued, net	801					801						801
Common stock issued, net, shares			16,112,039
Stock-based compensation amortization	66					66						66
Tax expense from employee stock plans	(6)					(6)	(4)					(6)	(4)
Common stock dividends declared	(889)							(889)	(716)			(889)	(716)
Preferred stock dividend									(14)				(14)
Preferred stock dividend requirement of subsidiary	(14)							(14)				(14)
Balance at Dec. 31, 2015	$ 16,828			$ 1,322	$ 258	$ 11,282	$ 7,215	$ 5,301	$ 8,262	$ (7)	$ 3	$ 16,576	$ 17,060	$ 252
Balance, in shares at Dec. 31, 2015	492,025,443	264,374,809	492,025,443

Organization And Basis Of Prese

Organization And Basis Of Presentation	12 Months Ended
	Dec. 31, 2015
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 decom missioning of the Utility’s nuclear generation facilities. This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s consolidated financial statements include the accounts of PG& E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s consolidated financial statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the compan ies operate in one segment). The accompanying consolidated financial statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP req uires 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 obligatio ns. 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 Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies	NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. T he 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 expecte d 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 r egulatory 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 a nd 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 c ustomers 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 mo st of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three years. T he Utility’s ability to recover r evenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the v olume 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. G enerally, 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 electri city 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 autho rizes 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 f or 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 “ Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 below.) Allowance for Doubtful Accounts Receivable PG&E Corporation and the Utility recognize an allowance for doubtful accounts to reco rd 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 c ustomer collectability. Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed a s the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed. Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Cost s are carried at weighted-average and are recoverable through rates. Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2015 2014 Electricity generating facilities (1) 5 to 100 $ 9,860 $ 9,374 Electricity distribution facilities 15 to 55 28,476 26,633 Electricity transmission facilities 15 to 75 10,196 9,155 Natural gas distribution facilities 5 to 60 10,397 9,741 Natural gas transportation and storage facilities 5 to 65 6,352 5,937 Construction work in progress 2,059 2,220 Total property, plant, and equipment 67,340 63,060 Accumulated depreciation (20,617) (19,120) Net property, plant, and equipment $ 46,723 $ 43,940 (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 13 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 de preciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.80 % in 2015 , 3.77% in 2014 , and 3.51% in 2013 . 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 depreci ation. 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 $ 48 million and $ 107 million during 2015 , $45 million and $100 million during 2014 , and $47 million and $101 million during 2013 . Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2015 and 2014 , including nuclear decommissioning obligations: (in millions) 2015 2014 ARO liability at beginning of year $ 3,575 $ 3,538 Revision in estimated cash flows 13 (16) Accretion 169 163 Liabilities settled (114) (110) ARO liability at end of year $ 3,643 $ 3,575 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, photovol taic facilities, 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. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissio ning 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, 2015 and 2014 . The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $ 3.5 billion at December 31, 2015 and 2014 (or $ 6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements . 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 $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision and $116 million and $196 million i n 2014 and 2013 , 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 13 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 Utilit y'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.” Sin ce 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 impair ments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any charac teristics 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, 2015, 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 r ights 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 electrici ty 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, 2015, it did not consolidate any of them. Other Accounting Policies For other accounting policies impacting PG&E Corporation’s a nd the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Note 13 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 Cor poration’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following: Pension Other Other (in millions, net of income tax) Benefits Benefits Investments Total Beginning balance $ (21) $ 15 $ 17 $ 11 Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $51, $21, and $0, respectively) (76) (31) - (107) Regulatory account transfer (net of taxes of $51, $21, and $0, respectively) 73 31 - 104 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $7, $8, and $0, respectively) (1) 8 11 - 19 Amortization of net actuarial loss (net of taxes of $4, $1, and $0, respectively) (1) 6 3 - 9 Regulatory account transfer (net of taxes of $10, $9, and $0, respectively) (1) (13) (13) - (26) Realized gain on investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss (2) 1 (17) (18) Ending balance $ (23) $ 16 $ - $ (7) (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, 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 Regulatory account transfer (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 Regulatory account transfer (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.) 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 Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016 -0 1 , Financial Instruments—Overall (Subtopic 825-10): Recognition and Measureme nt of Financial Assets and Financial Liabilities , which amends guidance to help improve the recognition and measurement of financial instruments . The ASU will be effective for PG&E Corporation and the Utility on January 1, 201 8 . PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures. Balance Sheet Classification of Deferred Taxes In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 7 40): Balance Sheet Classification of Deferred Taxes , which amends existing guidance on the presentation of deferred income tax assets and liabilities. The amendments in the ASU require that all deferred tax liabilities and assets be classified as noncurren t on the balance sheet. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2017, with earlier adoption permitted. PG&E Corporation and the Utility have implemented this standard as of the year ended December 31, 2015 on a prosp ective basis and the prior periods have not been retrospectively adjusted. Fair Value Measurement In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which removes the requirement to categorize within the fair value hierarchy all investments measured using net asset value per share as a practical expedient. The ASU became effective for PG&E Corporation and the Util ity on January 1, 2016 . This standard will be adopted for related disclosures in the first quarter of 2016 and will not have an impact on the consolidated financial statements. Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, t he FASB issued ASU No. 2015-05, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement , which adds guidance to help entities evaluate the accounting treatment for clo ud computing arrangements. The ASU became effective for PG&E Corporation and the Utility on January 1, 2016. PG&E Corporation and the Utility h ave determined that this ASU will not impact their consolidated financial statements and related disclosures an d will adopt this standard starting in the first quarter of 2016. Presentation of Debt Issuance Costs In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , which amends existing presentation of debt issuance costs. PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other. The amendments in this ASU, that became effective for PG&E Corpo ration and the Utility on January 1, 2016, require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG& E Corporation and the Utility will adopt this standard in the first quarter of 2016 and do not expect the reclassification to have a material impact on their consolidated financial statements. Revenue Recognition Standard In May 2014, the FASB issued A SU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance . In August 2015 , the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date , deferring the eff ective date of this amendment for PG&E Corporation and the Utility by one year to January 1, 2018, with early adoption permitted as of the original effective date of 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, 2015
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) 2015 2014 Period Pension benefits (1) $ 2,414 $ 2,347 Indefinitely (4) Deferred income taxes (1) 3,054 2,390 47 years Utility retained generation (2) 411 456 10 years Environmental compliance costs (1) 748 717 32 years Price risk management (1) 138 127 10 years Electromechanical meters (3) - 70 - Unamortized loss, net of gain, on reacquired debt (1) 94 113 11 years Other 170 102 Various Total long-term regulatory assets $ 7,029 $ 6,322 (1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. (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 Utilit y’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) Re presents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets. (4) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits. In gene ral, 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 re gulatory assets for unamortized loss, net of gain, on reacquired debt. Regulatory Liabilities Current Regulatory Liabilities At December 31, 2015 and 2014, the Utility had current regulatory liabilities of $676 million and $261 million, respectively. At December 31, 2015, the current regulatory liabilities consisted primarily of a $400 million bill credit to the Utility’s natural gas customers resulting from the Penalty Decision. (See Note 13 below.) Current regulatory liabilities are included within current liabilities-other in the Consolidated Balance Sheets. Long -Term Regulatory Liabilities Long-term regulatory liabilities are comprised of the following: Balance at December 31, (in millions) 2015 2014 Cost of removal obligations (1) $ 4,605 $ 4,211 Recoveries in excess of AROs (2) 631 754 Public purpose programs (3) 600 701 Other 485 624 Total long-term regulatory liabilities $ 6,321 $ 6,290 (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. Decommissioning cos ts related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissionin g 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 progr ams. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are rec orded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at December 31, (in millions) 2015 2014 Electric distribution $ 380 $ 344 Utility generation 122 261 Gas distribution 493 566 Energy procurement 262 608 Public purpose programs 155 109 Other 348 378 Total regulatory balancing accounts receivable $ 1,760 $ 2,266 Payable Balance at December 31, (in millions) 2015 2014 Energy procurement $ 112 $ 188 Public purpose programs 244 154 Other 359 748 Total regulatory balancing accounts payable $ 715 $ 1,090 The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency and low income energy efficien cy.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 PG&E Corporation Senior notes, 2.40%, due 2019 350 350 Total PG&E Corporation long-term debt 350 350 Utility Senior notes: 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 350 350 3.75% due 2024 450 450 3.50% due 2025 600 - 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 675 675 4.30% due 2045 600 500 4.25% due 2046 450 - Unamortized discount, net of premium (53) (43) Total senior notes, net of current portion 14,572 13,432 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 Less: current portion (160) - Total pollution control bonds 1,108 1,268 Total Utility long-term debt, net of current portion 15,680 14,700 Total consolidated long-term debt, net of current portion $ 16,030 $ 15,050 (1) At December 31, 2015 , interest rates on these bonds were 0.01 %. (2) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility. (3) The Utility has obtained credit support fro m an insurance company for these bonds. (4) Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit 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 Ca lifornia 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 use d 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-retir ed 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 ta x-exempt pollution control bonds issued to finance the Geysers project are outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities. 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, 2015 : Credit Letters of Commercial Termination Facility Credit Paper Facility (in millions) Date Limit Outstanding Outstanding Availability PG&E Corporation April 2020 $ 300 (1) $ - $ - $ 300 Utility April 2020 3,000 (2) 33 1,019 1,948 Total revolving credit facilities $ 3,300 $ 33 $ 1,019 $ 2,248 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 millio n lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. For the year ended December 31, 2015 , PG&E Corporation’s average outstanding commercial paper balance was $ 64 million and the maximum outstanding balance during the year was $ 128 million. For 2015 , the Utility’s average outstanding commercial paper balance was $ 678 million and the maximum outstanding balance during the year was $ 1.5 billion. There were no bank borrowings for both PG&E Corporation and the Utility in 2015 . Revolving Credit Facilities On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities. The amendments and restatements extended the te rmination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million . PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repaym ent 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. Borrowings under each amended and restated credit a greement (other than swing line loans) will bear interest based, at each borrower’s election, on (1) a London Interbank Offered Rate (“LIBOR”) 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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’ s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0 .075% and 0.225%, respectively. PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective revolving credit facilities require that PG&E Corporation and the Utility maintai n 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 outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility. Commercial Paper Programs The borrowings from PG&E Corporation and the Utility’s commercial paper programs are used primarily to fund temporar y financing needs. On July 2, 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respec tively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective 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. For 2015, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.38 % and 0.42 % , respectively. Other Short-term Borrowings On May 11, 2015, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured. Repayment Schedule PG& E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2015 are reflected in the table below: (in millions, except interest rates) 2016 2017 2018 2019 2020 Thereafter Total PG&E Corporation Average fixed interest rate - - - 2.40 % - - 2.40 Fixed rate obligations $ - $ - $ - $ 350 $ - $ - $ 350 Utility Average fixed interest rate - 5.63 % 8.25 % - 3.50 % 4.91 % 5.05 Fixed rate obligations $ - $ 700 $ 800 $ - $ 800 $ 12,670 $ 14,970 Variable interest rate as of December 31, 2015 0.01 % - - 0.01 % 0.01 % - 0.01 Variable rate obligations (1) $ 160 $ - $ - $ 149 $ 614 $ - $ 923 Total consolidated debt $ 160 $ 700 $ 800 $ 499 $ 1,414 $ 12,670 $ 16,243 (1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

Common Stock And Share-Based Co

Common Stock And Share-Based Compensation	12 Months Ended
	Dec. 31, 2015
Common Stock And Share-Based Compensation	NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION PG&E Corporation had 492,025,443 shares of common stock outstanding at December 31, 2015 . PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2015 . In February 2015, 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 2015 , PG&E Corporation sold 1.4 million shares under this agreement for cash proceeds of $ 74 million, net of commissions paid of $ 1 million. In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offering for cash proceeds of $352 million , net of fees. In addition, during 2015 , PG&E Corporation sold 7.9 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds o f $ 354 million. 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 cumu lative preferred dividends on the Utility’s preferred stock have been paid. For 2015, 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 an d 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, 2015, the Utility had restricted net assets of $ 15.2 billion and was limited to $ 110 million of additional common stock dividends it could pay to PG&E Corporation. 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 15,674,803 shares were available for future awards at December 31, 2015 . The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2015 , 2014 , and 2013 : (in millions) 2015 2014 2013 Restricted stock units $ 47 $ 42 $ 36 Performance shares 46 36 28 Total compensation expense (pre-tax) $ 93 $ 78 $ 64 Total compensation expense (after-tax) $ 55 $ 47 $ 38 The amount of share-based compensation costs capitalized during 2015 , 2014 , and 2013 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 and 2015 generally vest equally over three years. Vested restricted st ock 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 peri od based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2015 , 2014 , and 2013 was $ 53.30 , $43 .76, and $42.92, respectively. The total fair value of restricted stock units that vested during 2015 , 2014 , and 2013 was $ 57 Error! Bookmark not defined. million, $34 million, and $30 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. As of December 31, 2015 , $ 45 million of tot al unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.48 years. The following table summarize s restricted stock unit activity for 2015 : Number of Weighted Average Grant- Restricted Stock Units Date Fair Value Nonvested at January 1 2,538,357 $ 43.39 Granted 820,834 $ 53.30 Vested (1,304,150) $ 43.51 Forfeited (82,142) $ 45.63 Nonvested at December 31 1,972,899 $ 47.33 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. Compe nsation 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 val ue for performance shares granted during 2015 , 2014 , and 2013 was $ 68.27 , $51.81, and $33.45 respectively. There was no tax benefit associated with performance shares during each of these periods. As of December 31, 2015 , $ 36 million of total unrecognized compensation costs r elated to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.45 years. The following table summarizes activity for performance shares in 2015 : Number of Weighted Average Grant- Performance Shares Date Fair Value Nonvested at January 1 1,693,939 $ 42.37 Granted 669,519 68.27 Vested (421,262) 33.57 Forfeited (1) (491,584) 35.56 Nonvested at December 31 1,450,612 $ 59.24 (1) Includes performance shares that expired with 50% value as a result of total shareholder return results.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2015
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, 2015 and December 31, 2014, 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, 2015 , 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, 2015 , 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 2015 , 2014, and 2013.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
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 2015 , 2014 , and 2013 . Year Ended December 31, (in millions, except per share amounts) 2015 2014 2013 Income available for common shareholders $ 874 $ 1,436 $ 814 Weighted average common shares outstanding, basic 484 468 444 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 1 Weighted average common share outstanding, diluted 487 470 445 Tot al earnings per common share, diluted $ 1.79 $ 3.06 $ 1.83 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, 2015
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 diff erences, 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 taxi ng 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 betwe en a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit. Investment tax credits are deferred a nd 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 tr eatment. 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 Corpor ation 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) 2015 2014 2013 2015 2014 2013 Current: Federal $ (89) $ (84) $ (218) $ (88) $ (84) $ (222) State 11 (41) (26) 6 (29) (23) Deferre d: Federal 131 396 552 136 426 604 State (76) 78 (35) (69) 75 (28) Tax credits (4) (4) (5) (4) (4) (5) Income tax provision $ (27) $ 345 $ 268 $ (19) $ 384 $ 326 The following table describes net deferred income tax liabilities: PG&E Corporation Utility Year Ended December 31, (in millions) 2015 2014 2015 2014 Deferred income tax assets: Customer advances for construction $ 69 $ 88 $ 69 $ 88 Environmental reserve 85 111 85 111 Compensation and benefits 219 244 145 173 Tax carryforwards 1,703 1,177 1,462 946 Greenhouse gas allowances 340 56 340 56 Other 44 74 61 100 Total deferred income tax assets $ 2,460 $ 1,750 $ 2,162 $ 1,474 Deferred income tax liabilities: Regulatory balancing accounts $ 691 $ 512 $ 691 $ 512 Property related basis differences 9,656 8,683 9,638 8,666 Income tax regulatory asset (1) 1,244 974 1,245 974 Other 75 88 75 86 Total deferred income tax liabilities $ 11,666 $ 10,257 $ 11,649 $ 10,238 Total net deferred income tax liabilities $ 9,206 $ 8,507 $ 9,487 $ 8,764 Classification of net deferred income tax liabilities: Included in current liabilities (assets) $ - $ (6) $ - $ (9) Included in noncurrent liabilities 9,206 8,513 9,487 8,773 Total net deferred income tax liabilities $ 9,206 $ 8,507 $ 9,487 $ 8,764 (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 f ederal statutory rate to the income tax provision: PG&E Corporation Utility Year Ended December 31, 2015 2014 2013 2015 2014 2013 Federal statutory income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (4.9) 1.4 (3.1) (4.8) 1.6 (2.2) Effect of regulatory treatment of fixed asset differences (2) (33.6) (15.0) (4.2) (33.7) (14.7) (3.8) Tax credits (1.3) (0.7) (0.4) (1.3) (0.7) (0.4) Benefit of loss carryback (1.5) (0.8) (1.1) (1.5) (0.8) (1.0) Non deductible penalties (3) 4.3 0.3 0.8 4.3 0.3 0.7 Other, net (1.1) (0.8) (2.2) (0.2) 0.4 (0.9) Effective tax rate (3.1) % 19.4 % 24.8 % (2.2) % 21.1 % 27.4 % (1) Includes the effect of state flow-through ratemaking treatment. In 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs in 2015 and 2014 as authorized by the 2014 GRC decision. Amounts are impacted by the level of income before income taxes. (3) Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision. (For more information about the Penalty Decision see Note 13 below.) Unrecognized tax benefits The following table reconciles the changes in unrecognized tax benefits: PG& E Corporation Utility (in millions) 2015 2014 2013 2015 2014 2013 Balance at beginning of year $ 713 $ 666 $ 581 $ 707 $ 660 $ 575 Additions for tax position taken during a prior year 40 7 12 40 7 12 Reductions for tax position taken d uring a prior year (349) (9) (6) (349) (9) (6) Additio ns for tax position taken during the current year 64 61 79 64 61 79 Settlements - (12) - - (12) - Balance at end of year $ 468 $ 713 $ 666 $ 462 $ 707 $ 660 The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 3 1, 2015 for PG&E Corporation and the Utility was $ 50 million. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months du e to the resolution of several matters, including audits. As of December 31, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $ 60 million within the next 12 months. Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2015, 2014, and 2013, these amounts were immaterial. IRS settlements PG&E Corporation participated in the Compliance Assurance Process in 2015, 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 retur n. PG&E Corporation’s tax returns have been accepted through 2014 except for a few matters, the most significant of which relates to deductible repair costs. In December 2015, PG&E Corporation reached an agreement with the IRS on deductible repair costs for the 2011 tax year, subject to approval by the Joint Committee on Taxation. Deductible repair costs will continue to be subject to examination by the IRS for subsequent years. The IRS is expected to issue guidance in 2016 that clarifies which repair c osts are deductible for the natural gas transmission and distribution businesses. T ax years after 2004 remain subject to examination by the state of California. Carryforwards The following table describes PG&E Corporation’s operating loss and tax credi t carryforward balances: December 31, Expiration (in millions) 2015 Year Federal: Net operating loss carryforward $ 4,856 2029 - 2035 Tax credit carryforward 110 2029 - 2035 Charitable contribution loss carryforward 178 2017 - 2020 State: Net operating loss carryforward $ 80 2033 - 2034 Tax credit carryforward 59 Various Charitable contribution loss carryforward 119 2019 - 2020 PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of Dec ember 31, 2015 for these tax attributes. As of December 31, 2015, PG&E Corporation had approximately $ 29 million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be record ed in additional paid-in capital when used.

Derivatives And Hedging Activit

Derivatives And Hedging Activities	12 Months Ended
	Dec. 31, 2015
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. Derivatives are presented in the Utility’s Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives as long as the current ratemaking mechanism remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purcha se 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 p rovisions unrelated to the commodity delivered. These items are 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, 2015 and 2014 , respectively, the volumes of the Utility’s outstanding derivatives were as follows: Contract Volume Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 333,091,813 308,130,101 Options 111,550,004 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 3,663,512 5,346,787 Congestion Revenue Rights (3) 216,383,389 224,124,341 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges du e to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At December 31, 2015 , 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 $ 97 $ (4) $ 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Total commodity risk $ 27 $ - $ 90 $ 117 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 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk For the year ended December 31, (in millions) 2015 2014 2013 Unrealized gain/(loss) - regulatory assets and liabilities (1) $ (6) $ 124 $ 238 Realized loss - cost of electricity (2) (14) (83) (178) Realized loss - cost of natural gas (2) (10) (8) (22) Total commodity risk $ (30) $ 33 $ 38 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash col lateral 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, 2015 , 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 der ivative 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) 2015 2014 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (2) $ (47) Related derivatives in an asset position - - Collateral posting in the normal course of business related to these derivatives - 44 Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (3) (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, 2015
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. Le vel 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 liab ilities 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, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Money market investments 36 - - - 36 Global equity securities 1,520 13 - - 1,533 Fixed-income securities 694 521 - - 1,215 Total nuclear decommissioning trusts (2) 2,250 534 - - 2,784 Price risk management instruments (Note 9) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Money market investments 7 - - - 7 Global equity securities - 26 - - 26 Fixed-income securities - 132 - - 132 Total long-term disability trust 7 158 - - 165 Total assets $ 2,321 $ 829 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 Total liabilities $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 314 million, primarily related to deferred taxes on appreciation of investment value. 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. 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 hie rarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the year ended December 31, 2015 and 2014 . Trust Assets Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities and debt securities. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Global equity securities p rimarily 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 sec urities, 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 diffe rences. 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 purchas e 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 a nd 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 valua tion of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to the Chief Risk and Audit Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance a nd 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 condition s to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 9 above.) Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power purchase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2014 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 232 $ 63 Market approach CRR auction prices $ (15.97) - 8.17 Pow er purchase agreements $ - $ 100 Discounted cash flow Forward prices $ 16.04 - 56.21 (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, 2015 and 2014 , respectively: Price Risk Management Instruments (in millions ) 2015 2014 Asset (liability) balance as of January 1 $ 69 $ (30) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 20 99 Asset (liability) balance as of December 31 $ 89 $ 69 (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, 2015 and 2014 , 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 se nior notes were based on quoted market prices at December 31, 2015 and 2014 . 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, 2015 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation $ 350 $ 354 $ 350 $ 352 Utility 14,918 16,422 13,778 15,851 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, 2015 Nuclear decommissioning trusts Money market investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 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 (1) Represents amounts before deducting $ 314 million and $324 million at December 31, 2015 and 2014 , 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) December 31, 2015 Less than 1 year $ 18 1–5 years 470 5–10 years 273 More than 10 years 454 Total maturities of debt securities $ 1,215 The following table provides a summary of activity for the debt and equity securities: 2015 2014 2013 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 1,268 $ 1,336 $ 1,619 Gross realized gains on sales of securities held as available-for-sale 55 118 94 Gross realized losses on sales of securities held as available-for-sale (37) (12) (13)

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
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 qualifi ed 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 p ension 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 2015 and 2014 : Pension Plan (in millions) 2015 2014 Change in plan assets: Fair value of plan assets at beginning of year $ 14,216 $ 12,527 Actual return on plan assets (176) 1,946 Company contributions 334 332 Benefits and expenses paid (629) (589) Fair value of plan assets at end of year $ 13,745 $ 14,216 Change in benefit obligation: Benefit obligation at beginning of year $ 16,696 $ 14,077 Service cost for benefits earned 479 383 Interest cost 673 695 Actuarial (gain) loss (922) 2,131 Plan amendments 1 (1) Transitional costs 1 - Benefits and expenses paid (629) (589) Benefit obligation at end of year (1) $ 16,299 $ 16,696 Funded Status: Current liability $ (6) $ (6) Noncurrent liability (2,547) (2,474) Net liability at end of year $ (2,553) $ (2,480) (1) PG&E Corporation’s accumulated benefit obligation was $ 14.7 billion and $14.9 billion at December 31, 2015 and 2014 , respectively. Postretirement Benefits Other th an Pensions (in millions) 2015 2014 Change in plan assets: Fair value of plan assets at beginning of year $ 2,092 $ 1,892 Actual return on plan assets (26) 241 Company contributions 61 57 Plan participant contribution 68 63 Benefits and expenses paid (160) (161) Fair value of plan assets at end of year $ 2,035 $ 2,092 Change in benefit obligation: Benefit obligation at beginning of year $ 1,811 $ 1,597 Service cost for benefits earned 55 45 Interest cost 71 76 Actuarial (gain) loss (98) 166 Transitional costs 1 - Benefits and expenses paid (146) (140) Federal subsidy on benefits paid 4 4 Plan participant contributions 68 63 Benefit obligation at end of year $ 1,766 $ 1,811 Funded Status: (1) Noncurrent asset $ 344 $ 368 Noncurrent liability (75) (87) Net asset at end of year $ 269 $ 281 (1) At December 31, 2015 and 2014 , 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) 2015 2014 2013 Service cost $ 479 $ 383 $ 468 Interest cost 673 695 627 Expected return on plan assets (873) (807) (650) Amortization of prior service cost 15 20 20 Amortization of net actuarial loss 10 2 111 Net periodic benefit cost 304 293 576 Less: transfer to regulatory account (1) 34 42 (238) Total e xpense recognized $ 338 $ 335 $ 338 (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) 2015 2014 2013 Service cost $ 55 $ 45 $ 53 Interest cost 71 76 74 Expected return on plan assets (112) (103) (79) Amortization of prior service cost 19 23 23 Amortization of net actuarial loss 4 2 6 Net periodic benefit cost $ 37 $ 43 $ 77 There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Components of Accumulated Other Comprehensive Income PG&E Corporation and the Utility record unrecognized prior service costs and unrecogniz ed gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Conso lidated 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 r egulatory 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 o therwise 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 amorti zed into net periodic benefit costs for PG&E Corporation in 2016 are as follows: (in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ 8 $ 15 Unrecognized net loss 24 4 Total $ 32 $ 19 There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility. Valuation Assumptions The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cos t. Pension Plan PBOP Plans December 31, December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.37 % 4.00 % 4.89 % 4.27 - 4.48 % 3.89 - 4.09 % 4.70 - 5.00 % Rate of future compensation increases 4.00 % 4.00 % 4.00 % - - - Expected return on plan assets 6.10 % 6.20 % 6.50 % 3.20 - 6.60 % 3.30 - 6.70 % 3.50 - 6.70 % The assumed health care cost trend rate as of December 31, 2015 was 7.2 %, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 4 % . A one-percentage-point change in assumed health care cost trend rate would have the following effects: One-Perce ntage-Point One-Percentage-Point (in millions) Increase Decrease Effect on postretirement benefit obligation $ 113 $ (114) Effect on service and interest cost 9 (9) 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 inflatio n rate. For the pension plan, the assumed return of 6.1 % compares to a ten-year actual return of 7.8 %. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 688 Aa-grade non-callable bonds at December 31, 2015 . This yield curve has discount rates tha t 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 di fferently 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 Utili ty’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influenc e 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 vo latility, 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 return s with low correlation to the direction of these markets. R eal 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 are used to meet target equit y exposure. In addition, derivative instruments such as equity index futures and U.S. treasury 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 porti on of the non U.S. dollar exposure of global equity investments. The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: Pension Plan PBOP Plans 2016 2015 2014 2016 2015 2014 Global equity 25 % 25 % 25 % 32 % 31 % 30 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 10 % 10 % 10 % 7 % 8 % 8 % Fixed income 60 % 60 % 60 % 58 % 58 % 59 % 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 an d 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 appropriat e 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, 2015 and 2014 . Fair Value Measurements At December 31, 2015 2014 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 247 $ 369 $ - $ 616 $ 352 $ 311 $ - $ 663 Global equity 903 2,243 - 3,146 918 2,311 - 3,229 Absolute return - - 660 660 - - 577 577 Real assets 581 - 753 1,334 620 - 675 1,295 Fixed-income 1,841 5,516 640 7,997 2,068 5,718 638 8,424 Total $ 3,572 $ 8,128 $ 2,053 $ 13,753 $ 3,958 $ 8,340 $ 1,890 $ 14,188 PBOP Plans: Short-term investments $ 20 $ - $ - $ 20 $ 28 $ - $ - $ 28 Global equity 104 545 - 649 124 549 - 673 Absolute return - - 65 65 - - 55 55 Real assets 69 - 77 146 72 - 49 121 Fixed-income 150 1,010 - 1,160 163 1,055 1 1,219 Total $ 343 $ 1,555 $ 142 $ 2,040 $ 387 $ 1,604 $ 105 $ 2,096 Total plan assets at fair value $ 15,793 $ 16,284 In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $ 13 million and $24 million at December 31, 2015 and 2014 , respe ctively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days. Short-Term Investments Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets. Global Equity The global equity category includes investments in common sto ck, 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 asset s. 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 equity funds are valu ed using a net asset value per share and are maintained by investment companies for large institutional investors and are not publicly traded. Commingled equity funds are comprised primarily of underlying equity securities that are publicly traded on exch anges, and price quotes for the assets held by these funds are readily observable and available. Commingled equity 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 p ublic 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. F ixed-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. issuer s 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 ass ets. 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 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 Treas ury 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 a ssets. 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, 2015 and 2014 . 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, 2015 and 2014 : Pension Plan (in millions) Absolute Fixed- For the year ended December 31, 2015 Return Income Real Assets Total Balance at beginning of year $ 577 $ 638 $ 675 $ 1,890 Actual return on plan assets: Relating to assets still held at the reporting date (7) 9 63 65 Relating to assets sold during the period - 1 - 1 Purchases, issuances, sales, and settlements: Purchases 90 2 17 109 Settlements - (10) (2) (12) Balance at end of year $ 660 $ 640 $ 753 $ 2,053 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 PBOP Plans (in millions) Absolute Fixed- For the year ended December 31, 2015 Return Income Real Assets Total Balance at beginning of year $ 55 $ 1 $ 49 $ 105 Actual return on plan assets: Relating to assets still held at the reporting date (1) - 5 4 Relating to assets sold during the period - - - - Purchases, issuances, sales, and settlements: Purchases 11 - 23 34 Settlements - (1) - (1) Balance at end of year $ 65 $ - $ 77 $ 142 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 There were no material transfers out of Level 3 in 2015 and 2014 . Cash Flow Information Employer Contributions PG&E Corporation and the Utility contributed $ 334 million to the pension benefit plans and $ 61 million to the other benefit plans in 2015 . These contr ibutions 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 2015 . 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 2016 . Benefits Payments and Receipts As of December 31, 2015 , 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 fo llows: Pension PBOP Federal (in millions) Plan Plans Subsidy 2016 $ 695 $ 89 $ (6) 2017 739 95 (7) 2018 780 101 (7) 2019 818 107 (8) 2020 854 113 (8) Thereafter in the succeeding five years 4,728 593 (17) 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 P G&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, a s 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 reflec ted in PG&E Corporation’s Consolidated Statements of Income were $ 89 million, $80 million, and $71 million in 2015 , 2014 , and 2013 , respectively. There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

Related Party Agreements And Tr

Related Party Agreements And Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Agreements And Transactions	NOTE 12: 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 su pport 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 s ervices. 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 admin istrative 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) 2015 2014 2013 Utility revenues from: Administrative services provided to PG&E Corporation $ 6 $ 5 $ 7 Utility expenses from: Administrative services received from PG&E Corporation $ 53 $ 54 $ 45 Utility employee benefit due to PG&E Corporation 82 70 57 At December 31, 2015 and 2014 , the Utility had receivables of $ 22 Error! Bookmark not defined. million and $17 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 $ 21 million an d $20 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, 2015
Commitments And Contingencies	NOTE 13: 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 ag reements 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 CPUC Matters Order Instituting an Investigation into Compliance with Ex Parte Communication Rules During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have been made or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a Commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permis sible with proper noticing and reporting. On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure gov erning the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in the CPUC i nvestigations related to the Utility’s natural gas transmission pipeline operations and practices. A prehearing conference in the OII has been scheduled for March 1, 2016. The CPUC will determine any penalties that might be imposed on the Utility and de termine whether shareholders or ratepayers will bear the costs of the investigation. The CPUC can impose fines up to $50,000 for each violation, per day. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circu mstances, including such factors as how many days each violation continued; the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compl iance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this discretion in determining penalties. PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC w ill calculate the number of violations or the penalty for any violations, and whether the CPUC will consider additional communications in the OII, including those identified in a motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S r ate case . It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that may have violated the CPUC’s ex parte rules. Finally, the U.S. Attorney’s Office in San Fra ncisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with the federal and state investigators. It is uncert ain whether any charges will be brought against the Utility . CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaini ng to record-keeping practices with respect to maintaining safe operation of 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 th e 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 g as explosion that occurred in Carmel, California on March 3, 2014, for which the CPUC has previously imposed a penalty of $10.85 million. On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validatio n for certain distribution facilities. Evidentiary hearings were held during January 2016. Opening briefs are due by February 26, 2016 and reply briefs are due by March 31, 2016. The SED has indicated it will seek significant penalties, the amount of wh ich is expected to be disclosed in its brief. PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the form of fines or other remedies, including possible future unrecoverable costs to implement ope rational remedies. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion (discussed above). Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments o ver 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. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties . Potential Safety Citations The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, inv estigations, or self-reports. The SED can consider the discretionary factors discussed above (see “ Order Instituting an Investigation into Compliance with Ex parte Communication Rules” above) in determining the number of violations and whether to impose d aily fines for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non- compliance with such laws and regulations 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 with respect to these matters g iven 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. Federal Matters Federal Criminal Indictment On July 29, 2014, a federal grand ju ry for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014. The superseding indictment charges 27 felony counts 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. On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13 remaining counts. The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 million. On December 8, 2015, the court also issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act. The Alternative Fines Act 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.” The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional in formation about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations. (Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million.) After considering the additional information submitted by the government, on February 2, 2016, the court issued an order holding that if the government’s allegation s about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges. The trial on the criminal charges currently is scheduled to begin March 22, 2016. The Utilit y entered a plea of not guilty. The Utility believes that criminal charges and the alternative 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 obstr uct the NTSB’s investigation, as alleged in the superseding indictment. 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 Federal Matters The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters rel ating to the indicte d case discussed above. It is uncertain whether any additional charges will be brought against the Utility. Capital Expenditures Relating to Pipeline Safety Enhancement Plan At December 31, 2015, approximately $ 664 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 to the statement of income in future periods to the extent total fore casted PSEP-related capital costs are higher than currently expected. Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. A decision was issued in each investigative proceeding to determine the violations that the Utility committed. The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes pen alties on the Utility totaling $1.6 billion c omprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine. At December 31, 2015, the Consolidated Balance Sheets include $400 million in current regu latory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016. On January 14, 2016, the CPUC issued final decisions to close these investigative proceedings. The Penalty Decision requires that at lea st $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base. The CPUC will determine which safety projects and programs will be funded by sharehol ders in the Utility’s pending 2015 GT&S rate case. If the $850 million is not exhausted by designated safety-related projects and programs in the 2015 GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the ful l $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility woul d record additional charges if such costs are not otherwise authorized by the CPUC. As a result, the total shareholder-funded obligation could exceed $850 million. For the year ended December 31, 2015, the Utility recorded additional charges in operati ng and maintenance expenses in the Consolidated Statements of Income of $907 million as a result of the Penalty Decision. The cumulative charges at December 31, 2015, and the additional future charges to reach the $1.6 billion total are shown in the follow ing table: Year Cumulative Future Ended Charges Charges December 31, December 31, and Total (in millions) 2015 2015 Costs Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 407 407 282 689 Disallowed revenue for pipeline safety expenses (3) - - 161 161 CPUC estimated cost of other remedies (4) - - - 50 Total Penalty Decision fines and remedies $ 907 $ 1,107 $ 473 $ 1,600 (1) In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million. (2) The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate c ase. The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2 015 GT&S rate case decision. (3) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred . 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 w hen 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, un less an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about futur e 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 pe rtaining 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. Investigation of the Butte Fire In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the Butte Fire to determine whether a tree contacted a powe r line operated by the Utility and was the cause of the fire. Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Cal Fire’s investigation is expected to conclude in 2016. Approximately 27 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving more than 600 individual plaintiffs and their insurance companies. Plaintiffs and the Utility filed petitions with the California Judicial Council to coordinate these cases. The petitions were assigned to the Calaveras Superior Court for a recommendation to the Judicial Council. On January 21, 2016, the Calaveras Superior Court issued an order recommending to the Judicial Council that the cases be coordinated in the Superior Court of California, Sacramento County, for all purposes including trial. Among other factors, the Court found that coordination requires a court with a significant number of judges and complex litigation support personnel, neither of which are present in Calaveras County. It is estimated that losses related to structures, contents, other personal property, and fire suppression costs associated with the Butte fire, will range from $350 million to $450 million. This range is based on estimates about the number, size, and type of structures damaged or destroyed, assumptions about the contents of such structur es and other personal property damage, and information about the amount of fire suppression costs associated with prior similar fires. The Utility believes that it is reasonably possible that it would be liable for some or all of these and other costs, su ch as costs associated with tree damage, personal injury, business interruption losses, and other damages. The Utility is unable to reasonably estimate these other costs at this time due to the limited information available. The Utility has insuranc e coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility's liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition or results o f operations could be materially affected. Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards On September 17, 2015, the CPUC issued an order granting TURN’s and the ORA’s long-standing applications for rehearing of the CPUC decisio ns that awarded energy efficiency incentive payments to the California investor-owned utilities for the 2006-2008 energy efficiency program cycle. Under the ratemaking mechanism applicable to the 2006-2008 program cycle, the maximum amount of incentives t hat the Utility could have earned (or the maximum amount that the Utility could have been required to reimburse customers) over the 2006-2008 program cycle was $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened energy efficiency proceeding, the CPUC will evaluate whether incentives awarded to the California investor-owned utilities were just and reasonable, and whether any refunds are due. The parties are required to submit proposals to resolve the issues in the proceeding by March 18, 2016. Comments on the proposals are due on April 8, 2016 and evidentiary hearings, if needed, would be held in July 2016. It is uncertain when the CPUC will issue a decision and whether the Utility will be requi red to refund amounts or incur other obligations related to the 2006-2008 program cycle. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts or incur other obligations related to this matt er, but they are unable to reasonably estimate the amount of such refunds or other obligations. Other Contingencies Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled $ 63 million at December 31, 2015, and $55 million at December 31, 2014. These amounts are included in other current liabilities in the Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. 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 los s 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 a re 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) December 31, 2015 December 31, 2014 Topock natural gas compressor station (1) $ 300 $ 291 Hinkley natural gas compressor station (1) 140 158 Former manufactured gas plant sites owned by the Utility or third parties 271 257 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 164 150 Fossil fuel-fired generation facilities and sites 94 98 Total environmental remediation liability $ 969 $ 954 (1) See “Natural Gas Compressor Station Sites” below. At December 31, 2015 the Utility expected to recover $ 695 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 (inc luding 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 Utilit y 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 b een 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. On November 4, 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states th at the Utility must continue and improve its remediation efforts; define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporti ng program, and finalizes deadlines for the Utility to meet interim cleanup targets. The clean-up and abatement order did not have a material impact on the Utility’s consolidated financial statements. The Utility’s environmental remediation liability at December 31, 2015 reflects the Utility’s 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 f inal remediation plan 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. 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 November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental i mpact report in December 2016. After the Utility modifies its design in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017. The Utility’s environmental remediation li ability at December 31, 2015 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 Envi ronmental 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 $ 1.9 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 oth er 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 operation s 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 los ses 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 $ 3.5 billion per nuclear incident and $ 2.8 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, 2015, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $60 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 $3.5 billion for each insured loss. In contrast, NEIL would t reat 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 $3.5 billion policy limit amount. Under the P rice-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 $13.5 billion. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $13.5 billion of liability protection is provided under a loss-sharing program among uti lities 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 assess ment 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 f rom 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 th

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information Of Parent	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Administrative service revenue $ 51 $ 51 $ 41 Operating expenses (53) (53) (42) Interest income 1 1 1 Interest expense (10) (14) (25) Other income (expense) 30 (1) (57) Equity in earnings of subsidiaries 852 1,413 848 Income before income taxes 871 1,397 766 Income tax benefit 3 39 48 Net income $ 874 $ 1,436 $ 814 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $10, and $80, at respective dates) $ (1) $ (14) $ 113 Net change in investments (net of taxes of $12, $17, and $26, at respective dates) (17) (25) 38 Total other comprehensive income (loss) (18) (39) 151 Compreh ensive Income $ 856 $ 1,397 $ 965 Weighted Average Common Shares Outstanding, Basic 484 468 444 Weighte d Average Common Shares Outstanding, Diluted 487 470 445 Net earnings per common share, basic $ 1.81 $ 3.07 $ 1.83 Net earnings per common share, diluted $ 1.79 $ 3.06 $ 1.83 PG&E CORPORATION SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED BALANCE SHEETS Balance at December 31, (in millions) 2015 2014 ASSETS Current Assets Cash and cash equivalents $ 64 $ 96 Advances to affiliates 22 31 Income taxes receivable 24 29 Other 1 38 Total current assets 111 194 Noncurrent Assets Equipment 2 2 Accumulated depreciation (2) (1) Net equipment - 1 Investments in subsidiaries 16,837 16,003 Other investments 130 117 Deferred income taxes 250 260 Total noncurrent assets 17,217 16,381 Total Assets $ 17,328 $ 16,575 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable – other 3 67 Other 246 269 Total current liabilities 249 336 Noncurrent Liabilities Long-term debt 350 350 Other 153 141 Total noncurrent liabilities 503 491 Common Shareholders’ Equity Common stock 11,282 10,421 Reinvested earnings 5,301 5,316 Accumulated other comprehensive income (loss) (7) 11 Total common shareholders’ equity 16,576 15,748 Total Liabilities and Shareholders’ Equity $ 17,328 $ 16,575 PG&E CORPORATION SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) CONDENSED STATEMENTS OF CASH FLOWS (in millions) Year ended December 31, 2015 2014 2013 Cash Flows from Operating Activities: Net income $ 874 $ 1,436 $ 814 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 66 65 54 Equity in earnings of subsidiaries (852) (1,413) (848) Deferred income taxes and tax credits-net 10 (72) (10) Noncurrent income taxes receivable/payable - 5 - Current income taxes receivable/payable 5 (16) 20 Other (70) 43 (20) Net cash provided by operating activities 33 48 10 Cash F lows From Investing Activities: Investment in subsidiaries (705) (978) (1,371) Dividends received from subsidiaries (1) 716 716 716 Proceeds from tax equity investments - 368 275 Other - - (8) Net cash provided by (used in) investing activities 11 106 (388) Cash F lows From Financing Activities: Borrowings (repayments) under revolving credit facilities - (260) 140 Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 million - 347 - Repayments of long-term debt - (350) - Common stock issued 780 802 1,045 Common stock dividends paid (2) (856) (828) (782) Other - - (1) Net cash provided by (used in) financing activities (76) (289) 402 Net ch ange in cash and cash equivalents (32) (135) 24 Cash and cash equivalents at January 1 96 231 207 Cash and cash equivalents at December 31 $ 64 $ 96 $ 231 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (9) $ (15) $ (23) Income taxes, net - 1 21 Supplemental disclosure of noncash investing and financing activities Noncash common stock issuances $ 21 $ 21 $ 22 Common stock dividends declared but not yet paid 224 217 208 (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 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule II - Consolidated Valu

Schedule II - Consolidated Valuation And Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
Schedule II - Consolidated Valuation And Qualifying Accounts	PG&E Corporation SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2015, 2014, and 2013 (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: 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 2013: Allowance for uncollectible accounts (1) $ 87 $ 53 $ - $ 60 $ 80 (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, 2015, 2014, and 2013 (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: 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 2013: Allowance for uncollectible accounts (1) $ 87 $ 53 $ - $ 60 $ 80 (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 Accoun25

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Regulation And Regulated Operations	Regulation and Regulated Operations The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. T he 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 expecte d 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 r egulatory 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 a nd 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 c ustomers 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 mo st of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three years. T he Utility’s ability to recover r evenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the v olume 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. G enerally, 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 electri city 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 autho rizes 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 f or 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 “ Resolution of Remaining Chapter 11 Disputed Claims” in Note 13 below.)
Allowance For Doubtful Accounts Receivable	Allowance for Doubtful Accounts Receivable PG&E Corporation and the Utility recognize an allowance for doubtful accounts to reco rd 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 c ustomer collectability.
Inventories	Inventories Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed a s the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.
Emission Allowances	Emission Allowances The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Cost s are carried at weighted-average and are recoverable through rates.
Property, Plant, And Equipment	Property, Plant, and Equipment Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows: Estimated Useful Balance at December 31, (in millions, except estimated useful lives) Lives (years) 2015 2014 Electricity generating facilities (1) 5 to 100 $ 9,860 $ 9,374 Electricity distribution facilities 15 to 55 28,476 26,633 Electricity transmission facilities 15 to 75 10,196 9,155 Natural gas distribution facilities 5 to 60 10,397 9,741 Natural gas transportation and storage facilities 5 to 65 6,352 5,937 Construction work in progress 2,059 2,220 Total property, plant, and equipment 67,340 63,060 Accumulated depreciation (20,617) (19,120) Net property, plant, and equipment $ 46,723 $ 43,940 (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 13 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 de preciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.80 % in 2015 , 3.77% in 2014 , and 3.51% in 2013 . 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 depreci ation. 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 $ 48 million and $ 107 million during 2015 , $45 million and $100 million during 2014 , and $47 million and $101 million during 2013 .
Asset Retirement Obligations	Asset Retirement Obligations The following table summarizes the changes in ARO liability during 2015 and 2014 , including nuclear decommissioning obligations: (in millions) 2015 2014 ARO liability at beginning of year $ 3,575 $ 3,538 Revision in estimated cash flows 13 (16) Accretion 169 163 Liabilities settled (114) (110) ARO liability at end of year $ 3,643 $ 3,575 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, photovol taic facilities, 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. Nuclear Decommissioning Obligation Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissio ning 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, 2015 and 2014 . The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $ 3.5 billion at December 31, 2015 and 2014 (or $ 6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements .
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 $407 million in 2015 for estimated capital spending that is probable of disallowance related to the Penalty Decision and $116 million and $196 million i n 2014 and 2013 , 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 13 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 Utilit y'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.” Sin ce 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 impair ments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
Variable Interest Entities	Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any charac teristics 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, 2015, 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 r ights 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 electrici ty 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, 2015, it did not consolidate any of them.

Summary Of Significant Accoun26

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 Electricity generating facilities (1) 5 to 100 $ 9,860 $ 9,374 Electricity distribution facilities 15 to 55 28,476 26,633 Electricity transmission facilities 15 to 75 10,196 9,155 Natural gas distribution facilities 5 to 60 10,397 9,741 Natural gas transportation and storage facilities 5 to 65 6,352 5,937 Construction work in progress 2,059 2,220 Total property, plant, and equipment 67,340 63,060 Accumulated depreciation (20,617) (19,120) Net property, plant, and equipment $ 46,723 $ 43,940 (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 13 below.)
Schedule Of Changes In Asset Retirement Obligations	(in millions) 2015 2014 ARO liability at beginning of year $ 3,575 $ 3,538 Revision in estimated cash flows 13 (16) Accretion 169 163 Liabilities settled (114) (110) ARO liability at end of year $ 3,643 $ 3,575
Reclassification Out Of Accumulated Other Comprehensive Income TableText Block	The changes, net of income tax, in PG&E Cor poration’s accumulated other comprehensive income (loss) for the year ended December 31, 2015 consisted of the following: Pension Other Other (in millions, net of income tax) Benefits Benefits Investments Total Beginning balance $ (21) $ 15 $ 17 $ 11 Other comprehensive income before reclassifications: Unrecognized net actuarial loss (net of taxes of $51, $21, and $0, respectively) (76) (31) - (107) Regulatory account transfer (net of taxes of $51, $21, and $0, respectively) 73 31 - 104 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $7, $8, and $0, respectively) (1) 8 11 - 19 Amortization of net actuarial loss (net of taxes of $4, $1, and $0, respectively) (1) 6 3 - 9 Regulatory account transfer (net of taxes of $10, $9, and $0, respectively) (1) (13) (13) - (26) Realized gain on investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss (2) 1 (17) (18) Ending balance $ (23) $ 16 $ - $ (7) (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, 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 Regulatory account transfer (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 Regulatory account transfer (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.)

Regulatory Assets, Liabilitie27

Regulatory Assets, Liabilities, And Balancing Accounts (Tables)	12 Months Ended
	Dec. 31, 2015
Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]
Long-Term Regulatory Assets	Balance at December 31, Recovery (in millions) 2015 2014 Period Pension benefits (1) $ 2,414 $ 2,347 Indefinitely (4) Deferred income taxes (1) 3,054 2,390 47 years Utility retained generation (2) 411 456 10 years Environmental compliance costs (1) 748 717 32 years Price risk management (1) 138 127 10 years Electromechanical meters (3) - 70 - Unamortized loss, net of gain, on reacquired debt (1) 94 113 11 years Other 170 102 Various Total long-term regulatory assets $ 7,029 $ 6,322 (1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. (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 Utilit y’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) Re presents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets. (4) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.
Long-Term Regulatory Liabilities	Balance at December 31, (in millions) 2015 2014 Cost of removal obligations (1) $ 4,605 $ 4,211 Recoveries in excess of AROs (2) 631 754 Public purpose programs (3) 600 701 Other 485 624 Total long-term regulatory liabilities $ 6,321 $ 6,290 (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. Decommissioning cos ts related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissionin g 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 progr ams.
Current Regulatory Balancing Accounts Receivable	Receivable Balance at December 31, (in millions) 2015 2014 Electric distribution $ 380 $ 344 Utility generation 122 261 Gas distribution 493 566 Energy procurement 262 608 Public purpose programs 155 109 Other 348 378 Total regulatory balancing accounts receivable $ 1,760 $ 2,266
Current Regulatory Balancing Accounts Payable	Payable Balance at December 31, (in millions) 2015 2014 Energy procurement $ 112 $ 188 Public purpose programs 244 154 Other 359 748 Total regulatory balancing accounts payable $ 715 $ 1,090

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt [Abstract]
Schedule Of Long-Term Debt	December 31, (in millions) 2015 2014 PG&E Corporation Senior notes, 2.40%, due 2019 350 350 Total PG&E Corporation long-term debt 350 350 Utility Senior notes: 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 350 350 3.75% due 2024 450 450 3.50% due 2025 600 - 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 675 675 4.30% due 2045 600 500 4.25% due 2046 450 - Unamortized discount, net of premium (53) (43) Total senior notes, net of current portion 14,572 13,432 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 Less: current portion (160) - Total pollution control bonds 1,108 1,268 Total Utility long-term debt, net of current portion 15,680 14,700 Total consolidated long-term debt, net of current portion $ 16,030 $ 15,050 (1) At December 31, 2015 , interest rates on these bonds were 0.01 %. (2) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility. (3) The Utility has obtained credit support fro m an insurance company for these bonds. (4) Each series of these bonds is supported by a separate direct-pay letter of credit. Series C and D letters of credit 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	Credit Letters of Commercial Termination Facility Credit Paper Facility (in millions) Date Limit Outstanding Outstanding Availability PG&E Corporation April 2020 $ 300 (1) $ - $ - $ 300 Utility April 2020 3,000 (2) 33 1,019 1,948 Total revolving credit facilities $ 3,300 $ 33 $ 1,019 $ 2,248 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 millio n lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.
Schedule Of Repayment Schedule	(in millions, except interest rates) 2016 2017 2018 2019 2020 Thereafter Total PG&E Corporation Average fixed interest rate - - - 2.40 % - - 2.40 Fixed rate obligations $ - $ - $ - $ 350 $ - $ - $ 350 Utility Average fixed interest rate - 5.63 % 8.25 % - 3.50 % 4.91 % 5.05 Fixed rate obligations $ - $ 700 $ 800 $ - $ 800 $ 12,670 $ 14,970 Variable interest rate as of December 31, 2015 0.01 % - - 0.01 % 0.01 % - 0.01 Variable rate obligations (1) $ 160 $ - $ - $ 149 $ 614 $ - $ 923 Total consolidated debt $ 160 $ 700 $ 800 $ 499 $ 1,414 $ 12,670 $ 16,243 (1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, June 5, 2019, or December 1, 2020.

Common Stock And Share-Based 29

Common Stock And Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule Of Compensation Expense For Share-Based Incentive Awards	(in millions) 2015 2014 2013 Restricted stock units $ 47 $ 42 $ 36 Performance shares 46 36 28 Total compensation expense (pre-tax) $ 93 $ 78 $ 64 Total compensation expense (after-tax) $ 55 $ 47 $ 38
Schedule Of Restricted Stock Units	The following table summarize s restricted stock unit activity for 2015 : Number of Weighted Average Grant- Restricted Stock Units Date Fair Value Nonvested at January 1 2,538,357 $ 43.39 Granted 820,834 $ 53.30 Vested (1,304,150) $ 43.51 Forfeited (82,142) $ 45.63 Nonvested at December 31 1,972,899 $ 47.33
Schedule Of Performance Shares	The following table summarizes activity for performance shares in 2015 : Number of Weighted Average Grant- Performance Shares Date Fair Value Nonvested at January 1 1,693,939 $ 42.37 Granted 669,519 68.27 Vested (421,262) 33.57 Forfeited (1) (491,584) 35.56 Nonvested at December 31 1,450,612 $ 59.24 (1) Includes performance shares that expired with 50% value as a result of total shareholder return results.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Income available for common shareholders $ 874 $ 1,436 $ 814 Weighted average common shares outstanding, basic 484 468 444 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 1 Weighted average common share outstanding, diluted 487 470 445 Tot al earnings per common share, diluted $ 1.79 $ 3.06 $ 1.83

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes [Abstract]
Schedule Of Components Of Income Tax Expense (Benefit)	PG&E Corporation Utility Year Ended December 31, (in millions) 2015 2014 2013 2015 2014 2013 Current: Federal $ (89) $ (84) $ (218) $ (88) $ (84) $ (222) State 11 (41) (26) 6 (29) (23) Deferre d: Federal 131 396 552 136 426 604 State (76) 78 (35) (69) 75 (28) Tax credits (4) (4) (5) (4) (4) (5) Income tax provision $ (27) $ 345 $ 268 $ (19) $ 384 $ 326
Schedule Of Deferred Tax Assets And Liabilities	PG&E Corporation Utility Year Ended December 31, (in millions) 2015 2014 2015 2014 Deferred income tax assets: Customer advances for construction $ 69 $ 88 $ 69 $ 88 Environmental reserve 85 111 85 111 Compensation and benefits 219 244 145 173 Tax carryforwards 1,703 1,177 1,462 946 Greenhouse gas allowances 340 56 340 56 Other 44 74 61 100 Total deferred income tax assets $ 2,460 $ 1,750 $ 2,162 $ 1,474 Deferred income tax liabilities: Regulatory balancing accounts $ 691 $ 512 $ 691 $ 512 Property related basis differences 9,656 8,683 9,638 8,666 Income tax regulatory asset (1) 1,244 974 1,245 974 Other 75 88 75 86 Total deferred income tax liabilities $ 11,666 $ 10,257 $ 11,649 $ 10,238 Total net deferred income tax liabilities $ 9,206 $ 8,507 $ 9,487 $ 8,764 Classification of net deferred income tax liabilities: Included in current liabilities (assets) $ - $ (6) $ - $ (9) Included in noncurrent liabilities 9,206 8,513 9,487 8,773 Total net deferred income tax liabilities $ 9,206 $ 8,507 $ 9,487 $ 8,764 (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, 2015 2014 2013 2015 2014 2013 Federal statutory income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % Increase (decrease) in income tax rate resulting from: State income tax (net of federal benefit) (1) (4.9) 1.4 (3.1) (4.8) 1.6 (2.2) Effect of regulatory treatment of fixed asset differences (2) (33.6) (15.0) (4.2) (33.7) (14.7) (3.8) Tax credits (1.3) (0.7) (0.4) (1.3) (0.7) (0.4) Benefit of loss carryback (1.5) (0.8) (1.1) (1.5) (0.8) (1.0) Non deductible penalties (3) 4.3 0.3 0.8 4.3 0.3 0.7 Other, net (1.1) (0.8) (2.2) (0.2) 0.4 (0.9) Effective tax rate (3.1) % 19.4 % 24.8 % (2.2) % 21.1 % 27.4 % (1) Includes the effect of state flow-through ratemaking treatment. In 2015, amounts include an agreement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions. (2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs in 2015 and 2014 as authorized by the 2014 GRC decision. Amounts are impacted by the level of income before income taxes. (3) Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision. (For more information about the Penalty Decision see Note 13 below.)
Schedule Of Change In Unrecognized Tax Benefits	PG& E Corporation Utility (in millions) 2015 2014 2013 2015 2014 2013 Balance at beginning of year $ 713 $ 666 $ 581 $ 707 $ 660 $ 575 Additions for tax position taken during a prior year 40 7 12 40 7 12 Reductions for tax position taken d uring a prior year (349) (9) (6) (349) (9) (6) Additio ns for tax position taken during the current year 64 61 79 64 61 79 Settlements - (12) - - (12) - Balance at end of year $ 468 $ 713 $ 666 $ 462 $ 707 $ 660
Schedule of Operating Loss And Tax Credit Carryforward Balances	December 31, Expiration (in millions) 2015 Year Federal: Net operating loss carryforward $ 4,856 2029 - 2035 Tax credit carryforward 110 2029 - 2035 Charitable contribution loss carryforward 178 2017 - 2020 State: Net operating loss carryforward $ 80 2033 - 2034 Tax credit carryforward 59 Various Charitable contribution loss carryforward 119 2019 - 2020

Derivatives And Hedging Activ32

Derivatives And Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivatives And Hedging Activities [Abstract]
Volumes Of Outstanding Derivative Contracts	Contract Volume Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 333,091,813 308,130,101 Options 111,550,004 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 3,663,512 5,346,787 Congestion Revenue Rights (3) 216,383,389 224,124,341 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges du e to transmission grid limitations.
Outstanding Derivative Balances	At December 31, 2015 , 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 $ 97 $ (4) $ 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Total commodity risk $ 27 $ - $ 90 $ 117 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
Gains And Losses On Derivative Instruments	Commodity Risk For the year ended December 31, (in millions) 2015 2014 2013 Unrealized gain/(loss) - regulatory assets and liabilities (1) $ (6) $ 124 $ 238 Realized loss - cost of electricity (2) (14) (83) (178) Realized loss - cost of natural gas (2) (10) (8) (22) Total commodity risk $ (30) $ 33 $ 38 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash col lateral 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) 2015 2014 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (2) $ (47) Related derivatives in an asset position - - Collateral posting in the normal course of business related to these derivatives - 44 Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (3) (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, 2015
Fair Value Measurements [Abstract]
Assets And Liabilities Measured At Fair Value On A Recurring Basis	Fair Value Measurements At December 31, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Money market investments 36 - - - 36 Global equity securities 1,520 13 - - 1,533 Fixed-income securities 694 521 - - 1,215 Total nuclear decommissioning trusts (2) 2,250 534 - - 2,784 Price risk management instruments (Note 9) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Money market investments 7 - - - 7 Global equity securities - 26 - - 26 Fixed-income securities - 132 - - 132 Total long-term disability trust 7 158 - - 165 Total assets $ 2,321 $ 829 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 Total liabilities $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 314 million, primarily related to deferred taxes on appreciation of investment value. 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.
Sensitivity Analysis	Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power purchase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2014 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 232 $ 63 Market approach CRR auction prices $ (15.97) - 8.17 Pow er purchase agreements $ - $ 100 Discounted cash flow Forward prices $ 16.04 - 56.21 (1) Represents price per megawatt-hour
Level 3 Reconciliation	Price Risk Management Instruments (in millions ) 2015 2014 Asset (liability) balance as of January 1 $ 69 $ (30) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 20 99 Asset (liability) balance as of December 31 $ 89 $ 69 (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, 2015 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value Debt (Note 4) PG&E Corporation $ 350 $ 354 $ 350 $ 352 Utility 14,918 16,422 13,778 15,851
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, 2015 Nuclear decommissioning trusts Money market investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 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 (1) Represents amounts before deducting $ 314 million and $324 million at December 31, 2015 and 2014 , respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule Of Long Term Debt Repayments	As of (in millions) December 31, 2015 Less than 1 year $ 18 1–5 years 470 5–10 years 273 More than 10 years 454 Total maturities of debt securities $ 1,215
Schedule Of Activity For Debt And Equity Securities	2015 2014 2013 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 1,268 $ 1,336 $ 1,619 Gross realized gains on sales of securities held as available-for-sale 55 118 94 Gross realized losses on sales of securities held as available-for-sale (37) (12) (13)

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status	Pension Plan (in millions) 2015 2014 Change in plan assets: Fair value of plan assets at beginning of year $ 14,216 $ 12,527 Actual return on plan assets (176) 1,946 Company contributions 334 332 Benefits and expenses paid (629) (589) Fair value of plan assets at end of year $ 13,745 $ 14,216 Change in benefit obligation: Benefit obligation at beginning of year $ 16,696 $ 14,077 Service cost for benefits earned 479 383 Interest cost 673 695 Actuarial (gain) loss (922) 2,131 Plan amendments 1 (1) Transitional costs 1 - Benefits and expenses paid (629) (589) Benefit obligation at end of year (1) $ 16,299 $ 16,696 Funded Status: Current liability $ (6) $ (6) Noncurrent liability (2,547) (2,474) Net liability at end of year $ (2,553) $ (2,480) (1) PG&E Corporation’s accumulated benefit obligation was $ 14.7 billion and $14.9 billion at December 31, 2015 and 2014 , respectively. Postretirement Benefits Other th an Pensions (in millions) 2015 2014 Change in plan assets: Fair value of plan assets at beginning of year $ 2,092 $ 1,892 Actual return on plan assets (26) 241 Company contributions 61 57 Plan participant contribution 68 63 Benefits and expenses paid (160) (161) Fair value of plan assets at end of year $ 2,035 $ 2,092 Change in benefit obligation: Benefit obligation at beginning of year $ 1,811 $ 1,597 Service cost for benefits earned 55 45 Interest cost 71 76 Actuarial (gain) loss (98) 166 Transitional costs 1 - Benefits and expenses paid (146) (140) Federal subsidy on benefits paid 4 4 Plan participant contributions 68 63 Benefit obligation at end of year $ 1,766 $ 1,811 Funded Status: (1) Noncurrent asset $ 344 $ 368 Noncurrent liability (75) (87) Net asset at end of year $ 269 $ 281 (1) At December 31, 2015 and 2014 , 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) 2015 2014 2013 Service cost $ 479 $ 383 $ 468 Interest cost 673 695 627 Expected return on plan assets (873) (807) (650) Amortization of prior service cost 15 20 20 Amortization of net actuarial loss 10 2 111 Net periodic benefit cost 304 293 576 Less: transfer to regulatory account (1) 34 42 (238) Total e xpense recognized $ 338 $ 335 $ 338 (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) 2015 2014 2013 Service cost $ 55 $ 45 $ 53 Interest cost 71 76 74 Expected return on plan assets (112) (103) (79) Amortization of prior service cost 19 23 23 Amortization of net actuarial loss 4 2 6 Net periodic benefit cost $ 37 $ 43 $ 77
Estimated Amortized Net Periodic Benefit For 2012	(in millions) Pension Plan PBOP Plans Unrecognized prior service cost $ 8 $ 15 Unrecognized net loss 24 4 Total $ 32 $ 19
Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost	Pension Plan PBOP Plans December 31, December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.37 % 4.00 % 4.89 % 4.27 - 4.48 % 3.89 - 4.09 % 4.70 - 5.00 % Rate of future compensation increases 4.00 % 4.00 % 4.00 % - - - Expected return on plan assets 6.10 % 6.20 % 6.50 % 3.20 - 6.60 % 3.30 - 6.70 % 3.50 - 6.70 %
Schedule Of Assumed Health Care Cost Trend	The assumed health care cost trend rate as of December 31, 2015 was 7.2 %, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 4 % . A one-percentage-point change in assumed health care cost trend rate would have the following effects: One-Perce ntage-Point One-Percentage-Point (in millions) Increase Decrease Effect on postretirement benefit obligation $ 113 $ (114) Effect on service and interest cost 9 (9)
Target Asset Allocation Percentages	Pension Plan PBOP Plans 2016 2015 2014 2016 2015 2014 Global equity 25 % 25 % 25 % 32 % 31 % 30 % Absolute return 5 % 5 % 5 % 3 % 3 % 3 % Real assets 10 % 10 % 10 % 7 % 8 % 8 % Fixed income 60 % 60 % 60 % 58 % 58 % 59 % Total 100 % 100 % 100 % 100 % 100 % 100 %
Schedule Of Changes In Fair Value Of Plan Assets	Fair Value Measurements At December 31, 2015 2014 (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Pension Plan: Short-term investments $ 247 $ 369 $ - $ 616 $ 352 $ 311 $ - $ 663 Global equity 903 2,243 - 3,146 918 2,311 - 3,229 Absolute return - - 660 660 - - 577 577 Real assets 581 - 753 1,334 620 - 675 1,295 Fixed-income 1,841 5,516 640 7,997 2,068 5,718 638 8,424 Total $ 3,572 $ 8,128 $ 2,053 $ 13,753 $ 3,958 $ 8,340 $ 1,890 $ 14,188 PBOP Plans: Short-term investments $ 20 $ - $ - $ 20 $ 28 $ - $ - $ 28 Global equity 104 545 - 649 124 549 - 673 Absolute return - - 65 65 - - 55 55 Real assets 69 - 77 146 72 - 49 121 Fixed-income 150 1,010 - 1,160 163 1,055 1 1,219 Total $ 343 $ 1,555 $ 142 $ 2,040 $ 387 $ 1,604 $ 105 $ 2,096 Total plan assets at fair value $ 15,793 $ 16,284
Schedule Of Level 3 Reconciliation	Pension Plan (in millions) Absolute Fixed- For the year ended December 31, 2015 Return Income Real Assets Total Balance at beginning of year $ 577 $ 638 $ 675 $ 1,890 Actual return on plan assets: Relating to assets still held at the reporting date (7) 9 63 65 Relating to assets sold during the period - 1 - 1 Purchases, issuances, sales, and settlements: Purchases 90 2 17 109 Settlements - (10) (2) (12) Balance at end of year $ 660 $ 640 $ 753 $ 2,053 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 PBOP Plans (in millions) Absolute Fixed- For the year ended December 31, 2015 Return Income Real Assets Total Balance at beginning of year $ 55 $ 1 $ 49 $ 105 Actual return on plan assets: Relating to assets still held at the reporting date (1) - 5 4 Relating to assets sold during the period - - - - Purchases, issuances, sales, and settlements: Purchases 11 - 23 34 Settlements - (1) - (1) Balance at end of year $ 65 $ - $ 77 $ 142 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
Schedule Of Estimated Benefits Expected To Be Paid	Pension PBOP Federal (in millions) Plan Plans Subsidy 2016 $ 695 $ 89 $ (6) 2017 739 95 (7) 2018 780 101 (7) 2019 818 107 (8) 2020 854 113 (8) Thereafter in the succeeding five years 4,728 593 (17)

Related Party Agreements And 35

Related Party Agreements And Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Agreements And Transactions [Abstract]
Schedule Of Significant Related Party Transactions	Year Ended December 31, (in millions) 2015 2014 2013 Utility revenues from: Administrative services provided to PG&E Corporation $ 6 $ 5 $ 7 Utility expenses from: Administrative services received from PG&E Corporation $ 53 $ 54 $ 45 Utility employee benefit due to PG&E Corporation 82 70 57

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Impact Of The Penalty Decision	Year Cumulative Future Ended Charges Charges December 31, December 31, and Total (in millions) 2015 2015 Costs Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 407 407 282 689 Disallowed revenue for pipeline safety expenses (3) - - 161 161 CPUC estimated cost of other remedies (4) - - - 50 Total Penalty Decision fines and remedies $ 907 $ 1,107 $ 473 $ 1,600 (1) In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million. (2) The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate c ase. The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2 015 GT&S rate case decision. (3) These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred .
Schedule of Environmental Remediation Liability	Balance at (in millions) December 31, 2015 December 31, 2014 Topock natural gas compressor station (1) $ 300 $ 291 Hinkley natural gas compressor station (1) 140 158 Former manufactured gas plant sites owned by the Utility or third parties 271 257 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 164 150 Fossil fuel-fired generation facilities and sites 94 98 Total environmental remediation liability $ 969 $ 954 (1) See “Natural Gas Compressor Station Sites” below.
Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments	The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations fo r natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2015 : Power Purchase Agreements Renewable Conventional Natural Nuclear (in millions) Energy Energy Other Gas Fuel Total 2016 $ 2,177 $ 772 $ 504 $ 421 $ 113 $ 3,987 2017 2,201 787 380 150 100 3,618 2018 2,075 706 359 105 96 3,341 2019 2,087 694 290 105 98 3,274 2020 2,077 674 213 103 133 3,200 Thereafter 29,098 1,729 997 543 185 32,552 Total purchase commitments $ 39,715 $ 5,362 $ 2,743 $ 1,427 $ 725 $ 49,972
Schedule of Future Minimum Payments For Operating Leases	PG& E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2016 and 2052 . At December 31, 2015 , the future minimum payments related to these commitments were as follows: (in millions) Operating Leases 2016 $ 40 2017 41 2018 40 2019 38 2020 37 Thereafter 194 Total minimum lease payments $ 390

Schedule I - Condensed Financ37

Schedule I - Condensed Financial Information Of Parent (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Administrative service revenue $ 51 $ 51 $ 41 Operating expenses (53) (53) (42) Interest income 1 1 1 Interest expense (10) (14) (25) Other income (expense) 30 (1) (57) Equity in earnings of subsidiaries 852 1,413 848 Income before income taxes 871 1,397 766 Income tax benefit 3 39 48 Net income $ 874 $ 1,436 $ 814 Other Comprehensive Income Pension and other postretirement benefit plans obligations (net of taxes of $0, $10, and $80, at respective dates) $ (1) $ (14) $ 113 Net change in investments (net of taxes of $12, $17, and $26, at respective dates) (17) (25) 38 Total other comprehensive income (loss) (18) (39) 151 Compreh ensive Income $ 856 $ 1,397 $ 965 Weighted Average Common Shares Outstanding, Basic 484 468 444 Weighte d Average Common Shares Outstanding, Diluted 487 470 445 Net earnings per common share, basic $ 1.81 $ 3.07 $ 1.83 Net earnings per common share, diluted $ 1.79 $ 3.06 $ 1.83
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) 2015 2014 ASSETS Current Assets Cash and cash equivalents $ 64 $ 96 Advances to affiliates 22 31 Income taxes receivable 24 29 Other 1 38 Total current assets 111 194 Noncurrent Assets Equipment 2 2 Accumulated depreciation (2) (1) Net equipment - 1 Investments in subsidiaries 16,837 16,003 Other investments 130 117 Deferred income taxes 250 260 Total noncurrent assets 17,217 16,381 Total Assets $ 17,328 $ 16,575 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable – other 3 67 Other 246 269 Total current liabilities 249 336 Noncurrent Liabilities Long-term debt 350 350 Other 153 141 Total noncurrent liabilities 503 491 Common Shareholders’ Equity Common stock 11,282 10,421 Reinvested earnings 5,301 5,316 Accumulated other comprehensive income (loss) (7) 11 Total common shareholders’ equity 16,576 15,748 Total Liabilities and Shareholders’ Equity $ 17,328 $ 16,575
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, 2015 2014 2013 Cash Flows from Operating Activities: Net income $ 874 $ 1,436 $ 814 Adjustments to reconcile net income to net cash provided by operating activities: Stock-based compensation amortization 66 65 54 Equity in earnings of subsidiaries (852) (1,413) (848) Deferred income taxes and tax credits-net 10 (72) (10) Noncurrent income taxes receivable/payable - 5 - Current income taxes receivable/payable 5 (16) 20 Other (70) 43 (20) Net cash provided by operating activities 33 48 10 Cash F lows From Investing Activities: Investment in subsidiaries (705) (978) (1,371) Dividends received from subsidiaries (1) 716 716 716 Proceeds from tax equity investments - 368 275 Other - - (8) Net cash provided by (used in) investing activities 11 106 (388) Cash F lows From Financing Activities: Borrowings (repayments) under revolving credit facilities - (260) 140 Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 million - 347 - Repayments of long-term debt - (350) - Common stock issued 780 802 1,045 Common stock dividends paid (2) (856) (828) (782) Other - - (1) Net cash provided by (used in) financing activities (76) (289) 402 Net ch ange in cash and cash equivalents (32) (135) 24 Cash and cash equivalents at January 1 96 231 207 Cash and cash equivalents at December 31 $ 64 $ 96 $ 231 Supplemental disclosure of cash flow information Cash received (paid) for: Interest, net of amounts capitalized $ (9) $ (15) $ (23) Income taxes, net - 1 21 Supplemental disclosure of noncash investing and financing activities Noncash common stock issuances $ 21 $ 21 $ 22 Common stock dividends declared but not yet paid 224 217 208 (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 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule II - Consolidated Va38

Schedule II - Consolidated Valuation And Qualifying Accounts (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014, and 2013 (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: 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 2013: Allowance for uncollectible accounts (1) $ 87 $ 53 $ - $ 60 $ 80 (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, 2015, 2014, and 2013 (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: 2015: Allowance for uncollectible accounts (1) $ 66 $ 43 $ - $ 55 $ 54 2014: Allowance for uncollectible accounts (1) $ 80 $ 41 $ - $ 55 $ 66 2013: Allowance for uncollectible accounts (1) $ 87 $ 53 $ - $ 60 $ 80 (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 Accoun39

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Public Utility, Property, Plant and Equipment [Line Items]
Disallowed capital expenditures	$ 407	$ 116	$ 196
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
AFUDC interest recorded	48	45	47
AFUDC equity recorded	107	100	101
Nuclear decommissioning obligation accrued	2,500	2,500
Estimated cost recovery on spent nuclear fuel storage proceeding every year	3,500	3,500
Approximate estimated nuclear decommissioning cost in future dollars	6,100	6,100
Disallowed capital expenditures	$ 407	$ 116	$ 196
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Composite depreciation rate	3.80%	3.77%	3.51%

Summary Of Significant Accoun40

Summary Of Significant Accounting Policies (Schedule Of Estimated Useful Lives And Balances Of Utility's Property, Plant And Equipment) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Accumulated depreciation		$ (20,617)	$ (19,120)
Net property, plant, and equipment		46,723	43,940
Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		67,340	63,060
Electricity generating facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	[1]	$ 9,860	9,374
Electricity generating facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 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		$ 28,476	26,633
Electricity distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		15 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		$ 10,196	9,155
Electricity transmission [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		15 years
Electricity transmission [Member] | Utility [Member] | Maximum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		75 years
Natural gas distribution facilities [Member] | Utility [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Total property, plant, and equipment		$ 10,397	9,741
Natural gas distribution facilities [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 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		$ 6,352	5,937
Natural gas transportation and storage [Member] | Utility [Member] | Minimum [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life		5 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		$ 2,059	$ 2,220
[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 13 below.)

Summary Of Significant Accoun41

Summary Of Significant Accounting Policies (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Balance at beginning of year	$ 3,575	$ 3,538
Revision in estimated cash flows	13	(16)
Accretion	169	163
Liabilities settled	(114)	(110)
Balance at end of year	$ 3,643	$ 3,575

New and Significant Accounting

New and Significant Accounting Policies (Reclassifications Out of Accumulated Other Comprehensived Income) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		$ 11	$ 50
Change in investments		(17)	(25)	$ 38
Total other comprehensive income (loss)		(18)	(39)	151
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		(7)	11	50
Net actuarial loss tax		0	10	80
Change in investments tax		12	17	26
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(26)	(28)
Amortization of prior service cost	[1]	19	26
Amortization of net actuarial loss	[1]	9	2
Realized gain on investments		(17)	(30)
Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		(107)	(616)
Unrecognized prior service cost			1
Transfer to regulatory account		104	601
Change in investments			5
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		15	15
Unrecognized net actuarial loss		4
Unrecognized prior service cost		15
Amortization of prior service cost		19	23	23
Amortization of net actuarial loss		4	2	6
Total other comprehensive income (loss)		1	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		16	15	15
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(13)	(15)
Amortization of prior service cost	[1]	11	14
Amortization of net actuarial loss	[1]	3	1
Realized gain on investments		0	0
Net actuarial loss tax		1	1
Transfer To Regulatory Account Tax		9	10
Amortization of prior service cost tax		8	9
Realized gain on investments tax		0	0
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrecognized net actuarial loss		(31)	(28)
Unrecognized prior service cost			0
Transfer to regulatory account		31	28
Change in investments			0
Net actuarial loss tax		21	19
Transfer To Regulatory Account Tax		21	19
Change in investments tax			0
Amortization of prior service cost tax			0
Other Investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		17	42
Total other comprehensive income (loss)		(17)	(25)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		0	17	42
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	0	0
Amortization of prior service cost	[1]	0	0
Amortization of net actuarial loss	[1]	0	0
Realized gain on investments		(17)	(30)
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		12	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
Transfer to regulatory account		0	0
Change in investments			5
Net actuarial loss tax		0	0
Transfer To Regulatory Account Tax		0	0
Change in investments tax			4
Amortization of prior service cost tax			0
Pension [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance		(21)	(7)
Total other comprehensive income (loss)		(2)	(14)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance		(23)	(21)	$ (7)
Realized gain on investments tax		0
Pension [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Transfer to regulatory account	[1]	(13)	(13)
Amortization of prior service cost	[1]	8	12
Amortization of net actuarial loss	[1]	6	1
Realized gain on investments		0	0
Net actuarial loss tax		4	1
Transfer To Regulatory Account Tax		10	9
Amortization of prior service cost tax		7	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		(76)	(588)
Unrecognized prior service cost			1
Transfer to regulatory account		73	573
Change in investments			0
Net actuarial loss tax		51	404
Transfer To Regulatory Account Tax		$ 51	394
Change in investments tax			0
Amortization of prior service cost tax			$ 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, Liabilitie43

Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	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)	10 years
Environmental compliance costs regulatory asset recovery (years)	32 years
Price risk management regulatory assets recovery (years)	10 years
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)	11 years
Current regulatory liabilities	$ 676	$ 261
Current regulatory assets	517	$ 444
Bill Credit to Natural Gas Customers	$ 400

Regulatory Assets, Liabilitie44

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 7,029	$ 6,322
Deferred income taxes regulatory asset recovery maximum (years)		47 years
Weighted average remaining life of Utility retained generation assets (years)		10 years
Environmental compliance costs regulatory asset recovery (years)		32 years
Price risk management regulatory assets recovery (years)		10 years
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)		11 years
Retained Generation Asset Costs		$ 1,200
Pension benefits regulatory assets recovery (years)		Indefinitely
Other regulatory assets recovery (years)		Various
Current regulatory assets		$ 517	444
Pension Plans Defined Benefit [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	2,414	2,347
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	3,054	2,390
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[2]	411	456
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	748	717
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	138	127
Electromechanical meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[3]	0	70
Current regulatory assets		70
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	[1]	94	113
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets		$ 170	$ 102
[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. As of December 31, 2015, the remaining balance of $70 million is included in current regulatory assets on the Consolidated Balance Sheets.

Regulatory Assets, Liabilitie45

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 6,321	$ 6,290
Cost Of Removal Obligation [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[1]	4,605	4,211
Recoveries In Excess Of ARO [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[2]	631	754
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	[3]	600	701
Other Regulatory Assets ( Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities		$ 485	$ 624
[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, Liabilitie46

Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 1,760	$ 2,266
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	715	1,090
Electric Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	380	344
Utility Generation [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	122	261
Public Purpose Programs [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	155	109
Public Purpose Programs [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	244	154
Gas Distribution [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	493	566
Energy Procurement [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	262	608
Energy Procurement [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	112	188
Other [Member] | Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	348	378
Other [Member] | Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts	$ 359	$ 748

Debt (Narrative) (Details)

Debt (Narrative) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt [Line Items]
Interest including LIBOR on credit facilities		Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’s election, on (1) a London Interbank Offered Rate (“LIBOR”) 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 overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.
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
Short-term debt matured		$ (300)	$ 0	$ 0
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[1]	$ 3,000
Commercial paper average yield		0.42%
Line of Credit Facility, Expiration Date		Apr. 27, 2020
Short-term debt matured		$ (300)	$ 0	$ 0
PG&E Corporation [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity	[2]	$ 300
Commercial paper average yield		0.38%
Line of Credit Facility, Expiration Date		Apr. 27, 2020
Credit Facilities [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity		$ 3,300
Commercial Paper [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average outstanding borrowings		678
Maximum outstanding balance		1,500
Commercial Paper [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average outstanding borrowings		64
Maximum outstanding balance		$ 128
[1]	Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.
[2]	Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

Debt (Schedule Of Long-Term Deb

Debt (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Debt [Line Items]
Total long-term debt, net of current portion		$ 16,030	$ 15,050
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Total long-term debt, net of current portion		15,680	14,700
Utility [Member]
Debt [Line Items]
Unamortized discount, net of premium		(53)	(43)
Total senior notes, net of current portion		14,572	13,432
Less: current portion		160
Total pollution control bonds		1,108	1,268
PG&E Corporation [Member]
Debt [Line Items]
Total long-term debt, net of current portion		350	350
Senior Notes, 2.40% Due 2019 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Senior notes		350	350
Senior Notes, 3.40% Due 2024 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		350	350
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] | Utility [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] | Utility [Member]
Debt [Line Items]
Senior notes		300	300
Senior Notes, 3.75% Due 2024 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		450	450
Senior Notes, 3.50%, Due 2025 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		600	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	675
Senior Notes, 4.30% Due 2045 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		600	500
Senior Notes, 4.25%, Due 2046 [Member] | Utility [Member]
Debt [Line Items]
Senior notes		450	0
Pollution Control Bonds, Series 1996 C,E,F 1997 B, Variable Rates, Due 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[1],[2]	614	614
Pollution Control Bonds, Series 2004 A-D, 4.75%, Due 2023 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[3]	345	345
Pollution Control Bonds, Series 2009 A-D, Variable Rates, Due 2016 And 2026 [Member] | Utility [Member]
Debt [Line Items]
Pollution control bonds	[1],[4]	$ 309	$ 309
Interest rate on bonds, minimum		0.01%
Interest rate on bonds, maximum		0.01%
[1]	At December 31, 2015, interest rates on these bonds were 0.01%.
[2]	Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.
[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. Series C and D letters of credit 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 Long-Term D49

Debt (Schedule Of Long-Term Debt Repayments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Debt [Line Items]
Total consolidated long-term debt	$ 16,243
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	5.05%
Fixed rate obligations	$ 14,970
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 923	[1]
PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	$ 350
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, 2015	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, 2015	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, 2015	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	$ 499
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, 2015	0.01%
Variable rate obligations	$ 149	[1]
2019 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	2.40%
Fixed rate obligations	$ 350
2020 [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 1,414
2020 [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	3.50%
Fixed rate obligations	$ 800
Variable interest rate as of December 31, 2015	0.01%
Variable rate obligations	$ 614	[1]
2020 [Member] | PG&E Corporation [Member]
Debt [Line Items]
Average fixed interest rate	0.00%
Fixed rate obligations	$ 0
Thereafter [Member]
Debt [Line Items]
Total consolidated long-term debt	$ 12,670
Thereafter [Member] | Pacific Gas And Electric Company [Member]
Debt [Line Items]
Average fixed interest rate	4.91%
Fixed rate obligations	$ 12,670
Variable interest rate as of December 31, 2015	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, June 5, 2019, or December 1, 2020.

Debt (Schedule Of Line Of Credi

Debt (Schedule Of Line Of Credit) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Jul. 02, 2015	Apr. 27, 2015
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Facility Limit	[1]	$ 3,000
Letters of Credit outstanding		33
Commercial Paper		1,019
Facility Availability		1,948
Letters of credit, sublimit		500		$ 1,000
Swingline loans, sublimit		75		300
Commercial Paper Sublimit		$ 2,500	$ 1,750
PG&E Corporation [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Facility Limit	[2]	$ 300
Letters of Credit outstanding		0
Commercial Paper		0
Facility Availability		300
Letters of credit, sublimit		50		$ 100
Swingline loans, sublimit		100
Commercial Paper Sublimit		300
Credit Facilities [Member]
Debt [Line Items]
Facility Limit		3,300
Letters of Credit outstanding		33
Commercial Paper		1,019
Facility Availability		$ 2,248
[1]	Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.
[2]	Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

Common Stock And Share-Based 51

Common Stock And Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Common stock, shares outstanding	492,025,443	475,913,404
Dividend per share	$ 0.455
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	$ 11,282	$ 10,421
Equity Contract [Member]
Equity distribution agreement amount	$ 500
Common stock shares issued	1,400,000
Fees and Commissions	$ 1
Common stock	$ 74
Underwritten Public Offering [Member]
Sale of common stock in an underwritten public offering	6,800,000
Common stock issued, amount	$ 352
Four Zero One K Plan D R S P P Shared Based Compensation Plans [Member]
Common stock shares issued	7,900,000
Common stock	$ 354
Utility [Member]
Net restricted assets for revolving credit facility ratio requirement	1,520
Net restricted assets for equity component requirement	15,200
Additional Common Stock Dividends	$ 110

Common Stock And Share-Based 52

Common Stock And Share-Based Compensation (Long-Term Incentive Plan) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	15,674,803
Total Compensation Expense (pre-tax)	$ 93	$ 78	$ 64
Total Compensation Expense (after-tax)	55	47	38
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	47	42	36
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total Compensation Expense (pre-tax)	$ 46	$ 36	$ 28

Common Stock And Share-Based 53

Common Stock And Share-Based Compensation (Restricted Stock Units) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Stock And Share-Based Compensation [Abstract]
Total fair value	$ 57	$ 34	$ 30
Total unrecognized compensation costs	$ 45
Remaining weighted average period, Years	1 year 5 months 23 days
Nonvested at January 1, Number of Restricted Stock Units	2,538,357
Granted, Number of Restricted Stock Units	820,834
Vested, Number of Restricted Stock Units	(1,304,150)
Forfeited, Number of Restricted Stock Units	(82,142)
Nonvested at December 31, Number of Restricted Stock Units	1,972,899	2,538,357
Nonvested at January 1, Weighted Average Grant-Date Fair Value	$ 43.39
Granted, Weighted Average Grant Date Fair Value	53.30	$ 43.76	$ 42.92
Vested, Weighted Average Grant Date Fair Value	43.51
Forfeited, Weighted Average Grant Date Fair Value	45.63
Nonvested at December 31, Weighted Average Grant-Date Fair Value	$ 47.33	$ 43.39

Common Stock And Share-Based 54

Common Stock And Share-Based Compensation (Performance Shares) (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average period (years)		1 year 5 months 12 days
Performance Shares, Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee service share based compensation nonvested performance shares total compensation cost not yet recognized		$ 36
Nonvested at January 1, Number of Performance Shares		1,693,939
Granted, Number of Performance Shares		669,519
Vested, Number of Performance Shares		(421,262)
Forfeited, Number of Performance Shares	[1]	(491,584)
Nonvested at December 31, Number of Performance Shares		1,450,612	1,693,939
Nonvested at January 1, Weighted Average Exercise Price		$ 42.37
Granted, Weighted Average Exercise Price		68.27	$ 51.81	$ 33.45
Vested, Weighted Average Exercise Price		33.57
Forfeited, Weighted Average Exercise Price	[1]	35.56
Nonvested at December 31, Weighted Average Exercise Price		$ 59.24	$ 42.37
[1]	Includes performance shares that expired with 50% value as a result of total shareholder return results.

Preferred Stock (Narrative) (De

Preferred Stock (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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
Preferred stock, shares issued	75,000,000
$25 Par Value [Member] | Pacific Gas And Electric Company [Member]
Preferred Stock [Line Items]
Preferred stock, par value	$ 25
$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
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	1.5
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) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / shares
Minimum [Member]
Preferred Stock [Line Items]
Redemption Price | $ / shares	$ 25.75
Maximum [Member]
Preferred Stock [Line Items]
Redemption Price | $ / shares	$ 27.25
Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [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%
Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [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]
Preferred stock interest rate	4.36%
6.00% Series [Member] | Nonredeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
Preferred stock interest rate	6.00%
5.00% Series A [Member] | Redeemable Preferred Stock [Member] | Pacific Gas And Electric Company [Member] | Maximum [Member]
Preferred Stock [Line Items]
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 ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Income available for common shareholders	$ 874	$ 1,436	$ 814
Weighted average common shares outstanding, basic	484	468	444
Add Incremental Shares From Assumed conversions:
Employee share-based compensation	3	2	1
Weighted average common shares outstanding, diluted	487	470	445
Total earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Provision) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current, Federal	$ (89)	$ (84)	$ (218)
Current, State	11	(41)	(26)
Deferred, Federal	131	396	552
Deferred, State	(76)	78	(35)
Tax credits	(4)	(4)	(5)
Income Tax Provision	(27)	345	268
Pacific Gas And Electric Company [Member]
Current, Federal	(88)	(84)	(222)
Current, State	6	(29)	(23)
Deferred, Federal	136	426	604
Deferred, State	(69)	75	(28)
Tax credits	(4)	(4)	(5)
Income Tax Provision	(19)	384	326
PG&E Corporation [Member]
Income Tax Provision	$ 3	$ 39	$ 48

Income Taxes (Schedule Of Defer

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Pacific Gas And Electric Company [Member]
Customer advances for construction		$ 69	$ 88
Environmental reserve		85	111
Compensation		145	173
Tax carryforwards		1,462	946
Greenhouse Gas Allowances		340	56
Other		61	100
Total deferred income tax assets		2,162	1,474
Regulatory balancing accounts		691	512
Property related basis differences		9,638	8,666
Income tax regulatory asset	[1]	1,245	974
Other		75	86
Total deferred income tax liabilities		11,649	10,238
Total net deferred income tax liabilities		9,487	8,764
Included in current liabilities (assets)		0	(9)
Included in noncurrent liabilities		9,487	8,773
PG&E Corporation [Member]
Customer advances for construction		69	88
Environmental reserve		85	111
Compensation		219	244
Tax carryforwards		1,703	1,177
Greenhouse Gas Allowances		340	56
Other		44	74
Total deferred income tax assets		2,460	1,750
Regulatory balancing accounts		691	512
Property related basis differences		9,656	8,683
Income tax regulatory asset	[1]	1,244	974
Other		75	88
Total deferred income tax liabilities		11,666	10,257
Total net deferred income tax liabilities		9,206	8,507
Included in current liabilities (assets)		0	(6)
Included in noncurrent liabilities		$ 9,206	$ 8,513
[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, 2015	Dec. 31, 2014	Dec. 31, 2013
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]	(4.80%)	1.60%	(2.20%)
Effect of regulatory treatment of fixed asset differences	[2]	(33.70%)	(14.70%)	(3.80%)
Tax credits		(1.30%)	(0.70%)	(0.40%)
Benefit of loss carryback		(1.50%)	(0.80%)	(1.00%)
Non deductible penalties	[3]	4.30%	0.30%	0.70%
Other, net		(0.20%)	0.40%	(0.90%)
Effective tax rate		(2.20%)	21.10%	27.40%
PG&E Corporation [Member]
Federal statutory income tax rate		35.00%	35.00%	35.00%
State income tax (net of federal benefit)	[1]	(4.90%)	1.40%	(3.10%)
Effect of regulatory treatment of fixed asset differences	[2]	(33.60%)	(15.00%)	(4.20%)
Tax credits		(1.30%)	(0.70%)	(0.40%)
Benefit of loss carryback		(1.50%)	(0.80%)	(1.10%)
Non deductible penalties	[3]	4.30%	0.30%	0.80%
Other, net		(1.10%)	(0.80%)	(2.20%)
Effective tax rate		(3.10%)	19.40%	24.80%
[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.
[3]	Represents the effects of non-tax deductible fines and penalties associated with the Penalty Decision. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

Income Taxes (Schedule Of Chang

Income Taxes (Schedule Of Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Balance at beginning of year	$ 707	$ 660	$ 575
Additions for tax position taken during a prior year	40	7	12
Reductions for tax position taken during a prior year	(349)	(9)	(6)
Additions for tax position taken during the current year	64	61	79
Settlements	0	(12)	0
Balance at end of year	462	707	660
PG&E Corporation [Member]
Balance at beginning of year	713	666	581
Additions for tax position taken during a prior year	40	7	12
Reductions for tax position taken during a prior year	(349)	(9)	(6)
Additions for tax position taken during the current year	64	61	79
Settlements	0	(12)	0
Balance at end of year	$ 468	$ 713	$ 666

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Total UTB that, if recognized, would impact the effective income tax rate as of the end of the year	$ 50
Decrease of unrecognized tax benefit	60
State [Member]
Net operating loss carryforwards	80
Tax credit carryforward, amount	59
Loss carryforwards, charitable contribution	$ 119
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2019
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2020
Federal [Member]
Net operating loss carryforwards	$ 4,856
Capital loss carryforwards	29
Tax credit carryforward, amount	110
Loss carryforwards, charitable contribution	$ 178
Tax Credit Carryforward Expiration Date [Minimum]	Dec. 31, 2029
Tax Credit Carryforward Expiration Date [Maximum]	Dec. 31, 2035
Charitable Contribution Carryforward Expiration Date [Minimum]	Dec. 31, 2017
Charitable Contribution Carryforward Expiration Date [Maximum]	Dec. 31, 2020
Minimum [Member] | State [Member]
Tax credit carryforward expiration date	Dec. 31, 2033
Minimum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2029
Maximum [Member] | State [Member]
Tax credit carryforward expiration date	Dec. 31, 2034
Maximum [Member] | Federal [Member]
Tax credit carryforward expiration date	Dec. 31, 2035

Derivatives And Hedging Activ63

Derivatives And Hedging Activities (Volumes Of Outstanding Derivative Contracts) (Details)		Dec. 31, 2015MMBTUMWh	Dec. 31, 2014MMBTUMWh
Forwards And Swaps [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	333,091,813	308,130,101
Forwards And Swaps [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh		3,663,512	5,346,787
Options [Member] | Natural Gas (MMBtus)[Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MMBTU	[1],[2]	111,550,004	164,418,002
Congestion Revenue Rights [Member] | Electricity (Megawatt-hours) [Member]
Derivative [Line Items]
Derivative Number of Instruments Held | MWh	[3]	216,383,389	224,124,341
[1]	Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.
[2]	Million British Thermal Units.
[3]	CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Derivatives And Hedging Activ64

Derivatives And Hedging Activities (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ 97	$ 73
Cash Collateral	25	19
Total Derivative Balances	118	88
Derivative Liability Offsetting Derivative Asset	(4)	(4)
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	172	178
Cash Collateral	0	0
Total Derivative Balances	170	165
Derivative Liability Offsetting Derivative Asset	(2)	(13)
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance		(78)
Gross Derivative Balance	(102)
Cash Collateral	44	26
Total Derivative Balances	(54)	(48)
Derivative Asset Offsetting Derivative Liability	4	4
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(140)	(140)
Cash Collateral	21	9
Total Derivative Balances	(117)	(118)
Derivative Asset Offsetting Derivative Liability	2	13
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Gross Derivative Balance	27	33
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	90	54
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balances	$ 117	$ 87

Derivatives And Hedging Activ65

Derivatives And Hedging Activities (Gains And Losses On Derivative Instruments) (Details) - PGE Corporation Utility [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized (loss) gain - regulatory assets and liabilities	[1]	$ (6)	$ 124	$ 238
Realized loss-cost of electricity	[2]	(14)	(83)	(178)
Realized loss-cost of natural gas	[2]	(10)	(8)	(22)
Total commodity risk instruments		$ (30)	$ 33	$ 38
[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 Activ66

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 ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Derivatives And Hedging Activities [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized		$ (2)	$ (47)
Related derivatives in an asset position		0	0
Collateral posting in the normal course of business related to these derivatives		0	44
Net position of derivative contracts/additional collateral posting requirements	[1]	$ (2)	$ (3)
[1]	This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility?s credit risk-related contingencies.

Fair Value Measurements (Assets

Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 314	$ 324
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		64	94
Total assets		2,321	2,478
Other investments			33
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		829	687
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		259	232
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	19	2
Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		64	94
Total assets		3,428	3,399
Other investments			33
Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[2]	2,784
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		36	17
Global equity securities		1,520	1,585
Fixed-income securities		694	741
Total assets	[2]	2,250	2,343
Nuclear Decommissioning Trusts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Global equity securities		13	13
Fixed-income securities		521	389
Total assets	[2]	534	402
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		36	17
Global equity securities		1,533	1,598
Fixed-income securities		1,215	1,130
Total assets	[2]		2,745
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
Gas			1
Electric		69	47
Total liabilities		69	47
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		10	18
Electric		9	17
Gas		1	1
Electric		1	5
Gas		2	3
Total liabilities		3	8
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		259	232
Electric		259	232
Electric		170	163
Total liabilities		170	163
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[1]	19	2
Electric	[1]	18	2
Gas	[1]	1
Electric	[1]	(70)	(52)
Gas	[1]	(1)
Total liabilities	[1]	(71)	(52)
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		288	253
Electric		286	251
Gas		2	2
Electric		170	163
Gas		1	3
Total liabilities		171	166
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		57	42
Life insurance contracts		70	72
Total assets		127	114
Rabbi Trusts [Member] | Estimate Of Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed-income securities		57	42
Life insurance contracts		70	72
Total assets		127	114
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	7
Total assets		7	7
Long-Term Disability Trust [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Global equity securities		26	25
Fixed-income securities		132	128
Total assets		158	153
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	7
Global equity securities		26	25
Fixed-income securities		132	128
Total assets		$ 165	$ 160
[1]	Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
[2]	Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Detail) $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 259	$ 232
Liabilities, Fair Value		$ 63	$ 63
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		$ 107	$ 100
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] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	(161.36)	(15.97)
Minimum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	15.08	16.04
Maximum [Member] | CRR Auction Prices [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	8.76	8.17
Maximum [Member] | Forward Prices [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	37.27	56.21
[1]	Represents price per megawatt-hour

Fair Value Measurements (Leve69

Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value, Inputs, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1		$ 69	$ (30)
Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts	[1]	20	99
Liability balance as of December 31		$ 89	$ 69
[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 ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
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	14,918	13,778
Fair Value Inputs Level2 [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	354	352
Fair Value Inputs Level2 [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 16,422	$ 15,851

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Unrealized Gains Losses Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value		$ 314		$ 324
Money Market Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		36		17
Total Unrealized Gains		0		0
Total Unrealized Losses		0		0
Total Fair Value		36		17
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		508		520
Total Unrealized Gains		1,034		1,087
Total Unrealized Losses		(9)		(9)
Total Fair Value		1,533		1,598
Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,165		1,059
Total Unrealized Gains		58		75
Total Unrealized Losses		(8)		(4)
Total Fair Value		1,215		1,130
Securities (Assets) [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,709	[1],[2]	1,601
Total Unrealized Gains		1,092	[1],[2]	1,190
Total Unrealized Losses		(17)	[1],[2]	(13)
Total Fair Value		$ 2,784	[1],[2]	2,778
Other securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost				5
Total Unrealized Gains				28
Total Unrealized Losses				0
Total Fair Value				33
Nuclear Decommissioning Trusts [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	[1]			1,596
Total Unrealized Gains	[1]			1,162
Total Unrealized Losses	[1]			(13)
Total Fair Value	[1]			$ 2,745
[1]	Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
[2]	Represents amounts before deducting $314 million and $324 million at December 31, 2015 and 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurements (Sche72

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions	Dec. 31, 2015USD ($)
Fair Value Measurements [Abstract]
Less than 1 year	$ 18
1-5 years	470
5-10 years	273
More than 10 years	454
Total maturities of debt securities	$ 1,215

Fair Value Measurements (Sche73

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 1,268	$ 1,336	$ 1,619
Gross realized gains on sales of securities held as available-for-sale	55	118	94
Gross realized losses on sales of securities held as available-for-sale	$ (37)	$ (12)	$ (13)

Employee Benefit Plans (Reconci

Employee Benefit Plans (Reconciliation Of Changes In Plan Assets Benefit Obligations And Funded Status) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Noncurrent liability		$ (2,622)		$ (2,561)
Decrease in other comprehensive income		1		14	$ (113)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		2,092		1,892
Actual return on plan assets		(26)		241
Company contributions		61		57
Plan participant contribution		68		63
Benefits and expenses paid		(160)		(161)
Fair value of plan assets at December 31		2,035		2,092	1,892
Projected benefit obligation at January 1		1,811		1,597
Service cost for benefits earned		55		45
Interest cost		71		76	74
Actuarial (gain) loss		(98)		166
Benefits and expenses paid		(146)		(140)
Federal subsidy on benefits paid		4		4
Projected benefit obligation at December 31		1,766		1,811	1,597
Current liability	[1]	(75)		(87)
Net assets (liabilities) at end of year		269		281
Noncurrent asset	[1]	344		368
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1		14,216		12,527
Actual return on plan assets		(176)		1,946
Company contributions		334		332
Benefits and expenses paid		(629)		(589)
Fair value of plan assets at December 31		13,745		14,216	12,527
Projected benefit obligation at January 1		16,696		14,077
Service cost for benefits earned		479		383
Interest cost		673		695	627
Actuarial (gain) loss		(922)		2,131
Plan amendments		1		(1)
Transitional costs		1
Benefits and expenses paid		(629)		(589)
Projected benefit obligation at December 31		16,299	[2]	16,696	$ 14,077
Current liability		(6)		(6)
Noncurrent liability		(2,547)		(2,474)
Net assets (liabilities) at end of year		$ (2,553)		$ (2,480)
[1]	At December 31, 2015 and 2014, 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 $14.7 billion and $14.9 billion at December 31, 2015 and 2014, respectively.

Employee Benefit Plans (Compone

Employee Benefit Plans (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 55	$ 45	$ 53
Interest cost		71	76	74
Expected return on plan assets		(112)	(103)	(79)
Amortization of prior service cost		19	23	23
Amortization of net actuarial loss		4	2	6
Net periodic benefit cost		37	43	77
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		479	383	468
Interest cost		673	695	627
Expected return on plan assets		(873)	(807)	(650)
Amortization of prior service cost		15	20	20
Amortization of net actuarial loss		10	2	111
Net periodic benefit cost		304	293	576
Less: transfer to regulatory account	[1]	34	42	(238)
Total		$ 338	$ 335	$ 338
[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) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	$ 15
Unrecognized net actuarial loss	4
Total	19
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Unrecognized prior service cost	8
Unrecognized net actuarial loss	24
Total	$ 32

Employee Benefit Plans (Schedul

Employee Benefit Plans (Schedule Of Assumptions Used In Calculating Projected Benefit Cost And Net Periodic Benefit Cost) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.10%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate range	4.27-4.48	3.89-4.09	4.70-5.00
Expected return on plan assets percentage range	3.20-6.60	3.30-6.70	3.50-6.70
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.37%	4.00%	4.89%
Average rate of future compensation increases	4.00%	4.00%	4.00%
Expected return on plan assets	6.10%	6.20%	6.50%

Employee Benefit Plans (Sched78

Employee Benefit Plans (Schedule Of Assumed Health Care Cost Trend) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Employee Benefit Plans [Abstract]
Effect on postretirement benefit obligation, One-Percentage-Point Increase	$ 113
Effect on postretirement benefit obligation, One-Percentage-Point Decrease	(114)
Effect on service and interest cost, One-Percentage-Point Increase	9
Effect on service and interest cost, One-Percentage-Point Decrease	$ (9)
Assumed health care cost trend rate	7.20%
Ultimate trend rate	4.00%
Assumed return	6.10%
10 year actual rate of return	7.80%
Number of Aa-grade non-callable bonds used to develop the yield curve for rate used	688

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%	58.00%	59.00%
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	7.00%	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%	3.00%
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	32.00%	31.00%	30.00%
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 (Sched80

Employee Benefit Plans (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	$ 15,793	$ 16,284
Total Fair Value Of Trust Other Net Assets	13	131
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	2,040	2,096
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Total fair value of plan assets for pension and other benefit plans	13,753	14,188
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	343	387
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	3,572	3,958
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	1,555	1,604
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	8,128	8,340
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	142	105	$ 93
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	2,053	1,890	$ 1,723
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	20	28
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	616	663
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	20	28
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	247	352
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	369	311
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
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	146	121
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	1,334	1,295
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	69	72
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	581	620
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	77	49
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	753	675
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	649	673
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	3,146	3,229
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	104	124
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	903	918
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	545	549
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	2,243	2,311
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	65	55
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	660	577
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	65	55
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	$ 660	$ 577

Employee Benefit Plans (Sched81

Employee Benefit Plans (Schedule Of Level 3 Reconciliation) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	$ 16,284
Balance as of December 31	15,793	$ 16,284
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	2,096
Balance as of December 31	2,040	2,096
Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	387
Balance as of December 31	343	387
Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,604
Balance as of December 31	1,555	1,604
Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	105	93
Relating to assets still held at the reporting date	4	6
Relating to assets sold during the period	0	0
Purchases	34	7
Settlements	(1)	(1)
Balance as of December 31	142	105
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	14,188
Balance as of December 31	13,753	14,188
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	3,958
Balance as of December 31	3,572	3,958
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	8,340
Balance as of December 31	8,128	8,340
Pension Plans Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,890	1,723
Relating to assets still held at the reporting date	65	101
Relating to assets sold during the period	1	4
Purchases	109	79
Settlements	(12)	(17)
Balance as of December 31	2,053	1,890
Real Estate [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	49	38
Relating to assets still held at the reporting date	5	4
Relating to assets sold during the period	0	0
Purchases	23	7
Settlements	0	0
Balance as of December 31	77	49
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	675	544
Relating to assets still held at the reporting date	63	54
Relating to assets sold during the period	0	0
Purchases	17	78
Settlements	(2)	(1)
Balance as of December 31	753	675
Absolute Return [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	55	53
Relating to assets still held at the reporting date	(1)	2
Relating to assets sold during the period	0	0
Purchases	11	0
Settlements	0	0
Balance as of December 31	65	55
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	577	554
Relating to assets still held at the reporting date	(7)	23
Relating to assets sold during the period	0	0
Purchases	90	0
Settlements	0	0
Balance as of December 31	660	577
Corporate Fixed Income Securities [Member] | Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,219
Balance as of December 31	1,160	1,219
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	163
Balance as of December 31	150	163
Corporate Fixed Income Securities [Member] | Other Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	1,055
Balance as of December 31	1,010	1,055
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	1	2
Relating to assets still held at the reporting date	0	0
Relating to assets sold during the period	0	0
Purchases	0	0
Settlements	(1)	(1)
Balance as of December 31	0	1
Corporate Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance as of January 1	8,424
Balance as of December 31	7,997	8,424
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 January 1	2,068
Balance as of December 31	1,841	2,068
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 January 1	5,718
Balance as of December 31	5,516	5,718
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	638	625
Relating to assets still held at the reporting date	9	24
Relating to assets sold during the period	1	4
Purchases	2	1
Settlements	(10)	(16)
Balance as of December 31	$ 640	$ 638

Employee Benefit Plans (Sched82

Employee Benefit Plans (Schedule Of Estimated Benefits Expected To Be Paid) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 695
2,017	739
2,018	780
2,019	818
2,020	854
Thereafter in the succeeding five years	4,728
Employer contribution	334	$ 332
Expected employer contribution next year	327
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	89
2,017	95
2,018	101
2,019	107
2,020	113
Thereafter in the succeeding five years	593
Employer contribution	61	$ 57
Expected employer contribution next year	61
Federal Subsidy [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	(6)
2,017	(7)
2,018	(7)
2,019	(8)
2,020	(8)
Thereafter in the succeeding five years	$ (17)

Employee Benefit Plans (Sched83

Employee Benefit Plans (Schedule Of Employer Contribution Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Benefit Plans [Abstract]
Retirement Savings Plan expense	$ 89	$ 80	$ 71

Resolution Of Remaining Chapter

Resolution Of Remaining Chapter 11 Disputed Claims (Changes In The Remaining Net Disputed Claims Liability) (Details) - CAISO And PX [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Net disputed claims and customer refunds	$ 454	$ 434
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing	228	$ 291
Settlement Refund	$ 312

Related Party Agreements And 85

Related Party Agreements And Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Current receivables	$ 22	$ 17
Current payables	21	20
Administrative Services Provided To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility revenues from	6	5	$ 7
Administrative Services Received From PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	53	54	45
Utility Employee Benefit Due To PG&E Corporation [Member]
Related Party Transaction [Line Items]
Utility expenses from	$ 82	$ 70	$ 57

Commitments And Contingencies86

Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Loss Contingencies [Line Items]
Accrued legal liabilities		$ 63,000		$ 55,000
Amount of capital included in property plant and equipment		664,000
Customer bill credit		400,000
CPUC Imposed Penalty Per Day Per Violation		50
Payment To State General Fund		100,000	[1]	200,000
Total Penalty Decision Fines And Remedies		907,000
Disallowed capital expenditures		407,000		116,000	$ 196,000
Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Disallowed capital expenditures		$ 407,000		$ 116,000	$ 196,000
Butte Fire [Member]
Loss Contingencies [Line Items]
Number Of Deaths		2
Number Of Houses Destroyed		571
Number Of Structures Destroyed		965
Loss Contingency Range Of Possible Loss Maximum		$ 350,000
Loss Contingency Range Of Possible Loss Minimum		$ 450,000
Criminal Investigation [Member]
Loss Contingencies [Line Items]
Dismissed pipeline safety acts counts		15
Maximum [Member]
Loss Contingencies [Line Items]
Energy Efficiency Award For Two Thousand And Six Through Two Thousand And Eight Program Cycle		$ 180,000
Maximum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		16,800
Minimum [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
S E D fines for self reported violations		50
Penalty Decision Future Charges and Costs [Member]
Loss Contingencies [Line Items]
Disallowed Revenue For Pipeline Safety Expenses	[2]	161,000
Total Penalty Decision Fines And Remedies		443,000
Disallowed capital expenditures	[3]	282,000
Penalty Decision Cumulative Charges [Member]
Loss Contingencies [Line Items]
Customer bill credit		400,000
Payment To State General Fund	[1]	300,000
Total Penalty Decision Fines And Remedies		1,107,000
Disallowed capital expenditures	[3]	407,000
Total Penalty Decision [Member]
Loss Contingencies [Line Items]
Customer bill credit		400,000
C P U C Remedial Measures	[4]	50,000
Disallowed Revenue For Pipeline Safety Expenses	[2]	161,000
Payment To State General Fund	[1]	300,000
Total Penalty Decision Fines And Remedies		1,600,000
Disallowed capital expenditures	[3]	689,000
Carmel Incident [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
CPUC Imposed Penalty		$ 10,850
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
Penalty for each count of alleged violation		$ 500
Total maximum penalties		6,500
Gross gain derived from alleged violation		281,000
Gross loss derived from alleged violation		$ 562,000
Alleged Obstruction of NTSB Investigation [Member] | Criminal Investigation [Member] | Pacific Gas And Electric Company [Member]
Loss Contingencies [Line Items]
Number of Felony Counts		1
[1]	In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.
[2]	These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.
[3]	The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case. The Utility estimates that approximately $407 million of capital spending (which include less than $1 million for remedy related capital costs) in the year ended December 31, 2015 is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.
[4]	In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred.

Commitments And Contingencies87

Commitments And Contingencies (Environmental Remediation Liability Composed) (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Topock natural gas compressor station	[1]	$ 300	$ 291
Hinkley natural gas compressor station	[1]	140	158
Former manufactured gas plant sites owned by the Utility or third parties		271	257
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		164	150
Fossil fuel-fired generation facilities and sites		94	98
Total environmental remediation liability		$ 969	$ 954
[1]	See Natural Gas Compressor Station Sites below.

Commitments And Contingencies88

Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 695
Utility Undiscounted Future Costs	$ 1,900
Remediation cost recovery	90.00%

Commitments And Contingencies89

Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
Humboldt Bay Unit 3 potential premium obligation	$ 60
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	13,500
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	375
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	3,500
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	2,800
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 Contingencies90

Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
2,016	$ 3,987
2,017	3,618
2,018	3,341
2,019	3,274
2,020	3,200
Thereafter	32,552
Total	49,972
Renewable Energy Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2,016	2,177
2,017	2,201
2,018	2,075
2,019	2,087
2,020	2,077
Thereafter	29,098
Total	39,715
Other Power Purchase Agreements [Member]
Long-term Purchase Commitment [Line Items]
2,016	504
2,017	380
2,018	359
2,019	290
2,020	213
Thereafter	997
Total	2,743
Nuclear Fuel Purchase Commitments [Member]
Long-term Purchase Commitment [Line Items]
2,016	113
2,017	100
2,018	96
2,019	98
2,020	133
Thereafter	185
Total	725
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
2,016	421
2,017	150
2,018	105
2,019	105
2,020	103
Thereafter	543
Total	1,427
Conventional Energy [Member]
Long-term Purchase Commitment [Line Items]
2,016	772
2,017	787
2,018	706
2,019	694
2,020	674
Thereafter	1,729
Total	$ 5,362

Commitments And Contingencies91

Commitments And Contingencies (Third-Party Power Purchase Agreements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Qualifying Facilities [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2,016
Long term contract for purchase commitments, date of contract expiration, ending date	2,028
Present value of fixed capacity payments, portion classified as current liabilities	$ 19	$ 20
Present value of fixed capacity payments, portion classified as noncurrent liabilities	35	54
Capitalized asset for fixed capacity payments for corresponding assets	54	74
Capitalized asset for fixed capacity payments, accumulated amortization	$ 147	128
Renewable Energy [Member]
Third-Party Power Purchase Agreements [Line Items]
Long term contract for purchase commitments, date of contract expiration, beginning date	2,016
Long term contract for purchase commitments, date of contract expiration, ending date	2,043
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	2,016
Long term contract for purchase commitments, date of contract expiration, ending date	2,033
Costs Of Power Purchase	$ 3.5	$ 3.6	$ 3

Commitments And Contingencies92

Commitments And Contingencies (Gas Supply, Transportation And Storage) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	$ 900	$ 1,400	$ 1,600
Natural Gas [Member]
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2,016
Long Term Contract For Purchase Commitments Expiration Ending Date	2,026

Commitments And Contingencies93

Commitments And Contingencies (Nuclear Fuel Agreements) (Details) - Nuclear Fuel [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase Commitments Expiration Beginning Date	2,016
Long Term Contract For Purchase Commitments Expiration Ending Date	2,025
Payments for Nuclear Fuel	$ 128	$ 105	$ 162

Other Commitments And Other Ope

Other Commitments And Other Operating Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies [Abstract]
2,016	$ 40
2,017	41
2,018	40
2,019	38
2,020	37
Thereafter	194
Total	390
Payments for other commitments and operating leases	$ 41	$ 42	$ 40
Property Subject To Or Available For Operating Lease Expiration Beginning Date	2,016
Property Subject To Or Available For Operating Lease Expiration Ending Date	2,052

Schedule I - Condensed Financ95

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Income Statement) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating expenses	$ (15,325)	$ (14,640)	$ (13,836)
Interest income	9	9	9
Interest expense	(773)	(734)	(715)
Other income (expense)	117	70	40
Income Before Income Taxes	861	1,795	1,096
Income tax benefit	(27)	345	268
Income Available for Common Shareholders	874	1,436	814
Other Comprehensive Income Loss Net Of Tax Portion Attributable To Parent [Abstract]
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	$ 870	$ 1,411	$ 979
Weighted average common shares outstanding, basic	484	468	444
Weighted average common shares outstanding, diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83
PG&E Corporation [Member]
Administrative service revenue	$ 51	$ 51	$ 41
Operating expenses	(53)	(53)	(42)
Interest income	1	1	1
Interest expense	(10)	(14)	(25)
Other income (expense)	30	(1)	(57)
Equity in earnings of subsidiaries	852	1,413	848
Income Before Income Taxes	871	1,397	766
Income tax benefit	3	39	48
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)	(1)	(14)	113
Net change in investments (net of taxes $12, $17, and $26, at respective dates)	(17)	(25)	38
Total other comprehensive income (loss)	(18)	(39)	151
Comprehensive Income	$ 856	$ 1,397	$ 965
Weighted average common shares outstanding, basic	484	468	444
Weighted average common shares outstanding, diluted	487	470	445
Net earnings per common share, basic	$ 1.81	$ 3.07	$ 1.83
Net earnings per common share, diluted	$ 1.79	$ 3.06	$ 1.83

Schedule I - Condensed Financ96

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash and cash equivalents	$ 123	$ 151	$ 296	$ 401
Advances to affiliates	21	20
Income taxes receivable	155	198
Other Assets, Current	347	443
Total current assets	5,822	6,389
Equipment	67,342	63,062
Accumulated depreciation	(20,619)	(19,121)
Net property, plant, and equipment	46,723	43,941
Income taxes receivable	135	91
Other	1,160	963
TOTAL ASSETS	63,339	60,127
Short-term borrowings	1,019	633
Long-term debt, classified as current	160	0
Other	1,997	1,846
Total current liabilities	6,363	5,920
Long-term debt	16,030	15,050
Other	2,326	2,218
Total noncurrent liabilities	40,148	38,207
Common stock	11,282	10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive income (loss)	(7)	11	50
Total shareholders' equity	16,576	15,748
TOTAL LIABILITIES AND EQUITY	63,339	60,127
PG&E Corporation [Member]
Cash and cash equivalents	64	96	$ 231	$ 207
Advances to affiliates	22	31
Income taxes receivable	24	29
Other Assets, Current	1	38
Total current assets	111	194
Equipment	2	2
Accumulated depreciation	(2)	(1)
Net property, plant, and equipment	0	1
Investments in subsidiaries	16,837	16,003
Other investments	130	117
Deferred income taxes	250	260
Total noncurrent assets	17,217	16,381
TOTAL ASSETS	17,328	16,575
Accounts payable - other	3	67
Other	246	269
Total current liabilities	249	336
Long-term debt	350	350
Other	153	141
Total noncurrent liabilities	503	491
Common stock	11,282	10,421
Reinvested earnings	5,301	5,316
Accumulated other comprehensive income (loss)	(7)	11
Total shareholders' equity	16,576	15,748
TOTAL LIABILITIES AND EQUITY	$ 17,328	$ 16,575

Schedule I - Condensed Financ97

Schedule I - Condensed Financial Information Of Parent (Schedule Of Condensed Statement Of Cash Flows) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net income		$ 888	$ 1,450	$ 828
Deferred income taxes and tax credits, net		693	690	1,075
Net cash provided by operating activities		3,753	3,677	3,427
Other		22	114	56
Net cash used in investing activities		(5,211)	(4,714)	(5,107)
Borrowings under revolving credit facilities		0	(260)	140
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		1,123	2,308	1,532
Long-Term Debt Repurchased		0	889	861
Common stock issued		780	802	1,045
Common stock dividends paid		(856)	(828)	(782)
Other		0	42	(41)
Net cash (used) in financing activities		1,430	892	1,575
Net change in cash and cash equivalents		(28)	(145)	(105)
Cash and cash equivalents at January 1		151	296	401
Cash and cash equivalents at December 31		123	151	296
Cash received (paid) for:
Interest, net of amounts capitalized		(684)	(633)	(623)
Income taxes, net		77	501	(41)
Noncash common stock issuances		(21)	(21)	(22)
Common stock dividends declared but not yet paid		(224)	(217)	(208)
PG&E Corporation [Member]
Net income		874	1,436	814
Depreciation and amortization		66	65	54
Equity in earnings of subsidiaries		(852)	(1,413)	(848)
Deferred income taxes and tax credits, net		10	(72)	(10)
Noncurrent income taxes receivable/payable		0	5	0
Current income taxes receivable/payable		5	(16)	20
Other		(70)	43	(20)
Net cash provided by operating activities		33	48	10
Investment in subsidiaries		(705)	(978)	(1,371)
Dividends received from subsidiaries	[1]	716	716	716
Proceeds from tax equity investments		0	368	275
Other		0	0	(8)
Net cash used in investing activities		11	106	(388)
Borrowings under revolving credit facilities		0	(260)	140
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014		0	347	0
Long-Term Debt Repurchased		0	(350)	0
Common stock issued		780	802	1,045
Common stock dividends paid	[2]	(856)	(828)	(782)
Other		0	0	(1)
Net cash (used) in financing activities		(76)	(289)	402
Net change in cash and cash equivalents		(32)	(135)	24
Cash and cash equivalents at January 1		96	231	207
Cash and cash equivalents at December 31		64	96	231
Cash received (paid) for:
Interest, net of amounts capitalized		(9)	(15)	(23)
Income taxes, net		0	1	21
Noncash common stock issuances		21	21	22
Common stock dividends declared but not yet paid		$ 224	$ 217	$ 208
[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 2015, 2014, and 2013, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

Schedule II - Consolidated Va98

Schedule II - Consolidated Valuation And Qualifying Accounts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule II - Consolidated Valuation And Qualifying Accounts [Abstract]
Allowance for uncollectible accounts, Balance at Beginning of Period	[1]	$ 66	$ 80	$ 87
Allowance for uncollectible accounts, Charged to Costs and Expenses	[1]	43	41	53
Allowance for uncollectible accounts, Deductions	[1],[2]	55	55	60
Allowance for uncollectible accounts, Balance at End of Period	[1]	$ 54	$ 66	$ 80
[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.