PG&E (PCG) 10-Q 29 Jul 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 20, 2015
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	PCG
Entity Registrant Name	PG&E CORP
Entity Central Index Key	1,004,980
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		482,010,056
Pacific Gas And Electric Company [Member]
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	PCG
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Central Index Key	75,488
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		264,374,809

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating Revenues
Electric	$ 3,463	$ 3,233	$ 6,476	$ 6,234
Natural gas	754	719	1,640	1,609
Total operating revenues	4,217	3,952	8,116	7,843
Operating Expenses
Cost of electricity	1,277	1,349	2,277	2,559
Cost of natural gas	118	200	392	560
Operating and maintenance	1,484	1,328	3,407	2,627
Depreciation, amortization, and decommissioning	651	557	1,282	1,095
Total operating expenses	3,530	3,434	7,358	6,841
Operating Income	687	518	758	1,002
Interest income	3	2	4	5
Interest expense	(192)	(188)	(381)	(373)
Other income, net	18	43	76	62
Income Before Income Taxes	516	375	457	696
Income tax provision	110	104	17	195
Net Income	406	271	440	501
Preferred stock dividend requirement of subsidiary	4	4	7	7
Income Available for Common Shareholders	$ 402	$ 267	$ 433	$ 494
Weighted Average Common Shares Outstanding, Basic	480	467	479	463
Weighted Average Common Shares Outstanding, Diluted	483	469	483	465
Net Earnings Per Common Share, Basic	$ 0.84	$ 0.57	$ 0.90	$ 1.07
Net Earnings Per Common Share, Diluted	0.83	0.57	0.90	1.06
Dividends Declared Per Common Share	$ 0.46	$ 0.46	$ 0.91	$ 0.91
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	$ 3,462	$ 3,232	$ 6,476	$ 6,232
Natural gas	754	719	1,640	1,609
Total operating revenues	4,216	3,951	8,116	7,841
Operating Expenses
Cost of electricity	1,277	1,349	2,277	2,559
Cost of natural gas	118	200	392	560
Operating and maintenance	1,483	1,321	3,406	2,618
Depreciation, amortization, and decommissioning	651	556	1,282	1,094
Total operating expenses	3,529	3,426	7,357	6,831
Operating Income	687	525	759	1,010
Interest income	3	3	4	5
Interest expense	(189)	(185)	(376)	(364)
Other income, net	20	17	46	37
Income Before Income Taxes	521	360	433	688
Income tax provision	115	110	23	210
Net Income	406	250	410	478
Preferred stock dividend requirement	4	4	7	7
Income Available for Common Shareholders	$ 402	$ 246	$ 403	$ 471

Condensed Consolidated Stateme3

Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net income	$ 406	$ 271	$ 440	$ 501
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0, at respective dates)	0	0	0	0
Net change in investments (net of taxes of $0, $7, $12 and $3 at respective dates)	0	(11)	(17)	(6)
Total other comprehensive income (loss)	0	(11)	(17)	(6)
Comprehensive Income	406	260	423	495
Preferred stock dividend requirement of subsidiary	(4)	(4)	(7)	(7)
Comprehensive Income Attributable to Common Shareholders	402	256	416	488
Pacific Gas And Electric Company [Member]
Net income	406	250	410	478
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0 and $0, at respective dates)	0	0	0	0
Total other comprehensive income (loss)	0	0	0	0
Comprehensive Income	$ 406	$ 250	$ 410	$ 478

Condensed Consolidated Stateme4

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Net change in investments tax	0	7	12	3
Pacific Gas And Electric Company [Member]
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 249	$ 151
Restricted cash	287	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $66 at respective dates)	1,049	960
Accrued unbilled revenue	936	776
Regulatory balancing accounts	2,204	2,266
Other	352	377
Regulatory assets	441	444
Inventories
Gas stored underground and fuel oil	141	172
Materials and supplies	315	304
Income taxes receivable	192	198
Other	280	443
Total current assets	6,446	6,389
Property, Plant, and Equipment
Electric	46,687	45,162
Gas	16,208	15,678
Construction work in progress	2,075	2,220
Other	2	2
Total property, plant, and equipment	64,972	63,062
Accumulated depreciation	(19,962)	(19,121)
Net property, plant, and equipment	45,010	43,941
Other Noncurrent Assets
Regulatory assets	6,476	6,322
Nuclear decommissioning trusts	2,504	2,421
Income taxes receivable	94	91
Other	1,101	963
Total other noncurrent assets	10,175	9,797
TOTAL ASSETS	61,631	60,127
Current Liabilities
Short-term borrowings	1,016	633
Accounts payable
Trade creditors	1,178	1,244
Regulatory balancing accounts	876	1,090
Other	458	476
Disputed claims and customer refunds	448	434
Interest payable	203	197
Other	2,123	1,846
Total current liabilities	6,302	5,920
Noncurrent Liabilities
Long-term debt	15,544	15,050
Regulatory liabilities	6,330	6,290
Pension and other postretirement benefits	2,536	2,561
Asset retirement obligations	3,609	3,575
Deferred income taxes	8,732	8,513
Other	2,307	2,218
Total noncurrent liabilities	$ 39,058	$ 38,207
Commitments and Contingencies (Note 9)
Shareholders' Equity
Common stock	$ 10,717	$ 10,421
Reinvested earnings	5,308	5,316
Accumulated other comprehensive income (loss)	(6)	11
Total shareholders' equity	16,019	15,748
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	16,271	16,000
TOTAL LIABILITIES AND EQUITY	61,631	60,127
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	148	55
Restricted cash	287	298
Accounts receivable
Customers (net of allowance for doubtful accounts of $56 and $66 at respective dates)	1,049	960
Accrued unbilled revenue	936	776
Regulatory balancing accounts	2,204	2,266
Other	351	375
Regulatory assets	441	444
Inventories
Gas stored underground and fuel oil	141	172
Materials and supplies	315	304
Income taxes receivable	160	168
Other	280	409
Total current assets	6,312	6,227
Property, Plant, and Equipment
Electric	46,687	45,162
Gas	16,208	15,678
Construction work in progress	2,075	2,220
Total property, plant, and equipment	64,970	63,060
Accumulated depreciation	(19,961)	(19,120)
Net property, plant, and equipment	45,009	43,940
Other Noncurrent Assets
Regulatory assets	6,476	6,322
Nuclear decommissioning trusts	2,504	2,421
Income taxes receivable	94	91
Other	998	864
Total other noncurrent assets	10,072	9,698
TOTAL ASSETS	61,393	59,865
Current Liabilities
Short-term borrowings	1,011	633
Accounts payable
Trade creditors	1,177	1,243
Regulatory balancing accounts	876	1,090
Other	482	444
Disputed claims and customer refunds	448	434
Interest payable	200	195
Other	1,899	1,604
Total current liabilities	6,093	5,643
Noncurrent Liabilities
Long-term debt	15,194	14,700
Regulatory liabilities	6,330	6,290
Pension and other postretirement benefits	2,449	2,477
Asset retirement obligations	3,609	3,575
Deferred income taxes	8,992	8,773
Other	2,263	2,178
Total noncurrent liabilities	$ 38,837	$ 37,993
Commitments and Contingencies (Note 9)
Shareholders' Equity
Preferred stock	$ 258	$ 258
Common stock	1,322	1,322
Additional paid-in capital	6,703	6,514
Reinvested earnings	8,175	8,130
Accumulated other comprehensive income (loss)	5	5
Total shareholders' equity	16,463	16,229
TOTAL LIABILITIES AND EQUITY	$ 61,393	$ 59,865

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Allowance for doubtful accounts	$ 56	$ 66
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	481,575,453	475,913,404
Pacific Gas And Electric Company [Member]
Allowance for doubtful accounts	$ 56	$ 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

Condensed Consolidated Stateme7

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash Flows from Operating Activities
Net income	$ 440	$ 501
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,282	1,095
Allowance for equity funds used during construction	(53)	(46)
Deferred income taxes and tax credits, net	219	51
Disallowed capital expenditures	128	0
Other	149	139
Effect of changes in operating assets and liabilities:
Accounts receivable	(241)	(30)
Inventories	20	(7)
Accounts payable	78	(101)
Income taxes receivable/payable	6	(39)
Other current assets and liabilities	77	94
Regulatory assets, liabilities, and balancing accounts, net	(62)	(311)
Other noncurrent assets and liabilities	(184)	(66)
Net cash provided by operating activities	1,859	1,280
Cash Flows from Investing Activities
Capital expenditures	(2,410)	(2,320)
Decrease in restricted cash	11	2
Proceeds from sales and maturities of nuclear decommissioning trust investments	779	877
Purchases of nuclear decommissioning trust investments	(879)	(873)
Other	13	21
Net cash used in investing activities	(2,486)	(2,293)
Cash Flows from Financing Activities
Repayments under revolving credit facilities	0	(260)
Net issuances of commercial paper, net of discount of $2 and $1 at respective dates	681	237
Proceeds from issuance of short-term debt, net of issuance costs	0	300
Short-term debt matured	(300)	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $14, at respective dates, for PG&E Corporation and $14 and $11, at respective dates, for the Utility	486	1,236
Repayments of long-term debt	0	(889)
Common stock issued	252	589
Common stock dividends paid	(424)	(408)
Other	30	44
Net cash provided by financing activities	725	849
Net change in cash and cash equivalents	98	(164)
Cash and cash equivalents at January 1	151	296
Cash and cash equivalents at June 30	249	132
Cash received (paid) for:
Interest, net of amounts capitalized	(334)	(318)
Income taxes, net	0	(1)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	219	215
Capital expenditures financed through accounts payable	177	224
Noncash common stock issuances	10	10
Terminated capital leases	0	68
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	410	478
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,282	1,094
Allowance for equity funds used during construction	(53)	(46)
Deferred income taxes and tax credits, net	219	18
Disallowed capital expenditures	128	0
Other	119	108
Effect of changes in operating assets and liabilities:
Accounts receivable	(242)	(31)
Inventories	20	(7)
Accounts payable	134	(72)
Income taxes receivable/payable	8	(35)
Other current assets and liabilities	67	141
Regulatory assets, liabilities, and balancing accounts, net	(62)	(311)
Other noncurrent assets and liabilities	(170)	(76)
Net cash provided by operating activities	1,860	1,261
Cash Flows from Investing Activities
Capital expenditures	(2,410)	(2,320)
Decrease in restricted cash	11	2
Proceeds from sales and maturities of nuclear decommissioning trust investments	779	877
Purchases of nuclear decommissioning trust investments	(879)	(873)
Other	13	17
Net cash used in investing activities	(2,486)	(2,297)
Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $2 and $1 at respective dates	676	125
Proceeds from issuance of short-term debt, net of issuance costs	0	300
Short-term debt matured	(300)	0
Proceeds from issuance of long-term debt, net of premium, discount, and issuance costs of $14, at respective dates, for PG&E Corporation and $14 and $11, at respective dates, for the Utility	486	889
Repayments of long-term debt	0	(539)
Preferred stock dividends paid	(7)	(7)
Common stock dividends paid	(358)	(358)
Equity contribution from PG&E Corporation	185	580
Other	37	51
Net cash provided by financing activities	719	1,041
Net change in cash and cash equivalents	93	5
Cash and cash equivalents at January 1	55	65
Cash and cash equivalents at June 30	148	70
Cash received (paid) for:
Interest, net of amounts capitalized	(330)	(307)
Income taxes, net	0	(1)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	177	224
Terminated capital leases	$ 0	$ 68

Condensed Consolidated Stateme8

Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Discount on net issuances of commercial paper	$ 2	$ 1
Premium, discount, and issuance costs on proceeds from long-term debt	14	14
Pacific Gas And Electric Company [Member]
Discount on net issuances of commercial paper	2	1
Premium, discount, and issuance costs on proceeds from long-term debt	$ 14	$ 11

Organization And Basis Of Prese

Organization And Basis Of Presentation	6 Months Ended
	Jun. 30, 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 i n northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. On April 9, 2015, the CPUC approved final decisions in the three investigations pending against the Utility relating to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and ot her 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 proc eeding to determine the violations that the Utility committed. The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion c omprised of: (1) a $300 million fine to be paid to the State Gen eral 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. The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base. The remainder will be allocated to safety-related expen ses. (See Note 9.) This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes t o the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility operate in one segment. The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation and the Ut ility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2014 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Bal ance Sheets in the 2014 Form 10-K. This quarterly report should be read in conjunction with the 2014 Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amoun ts 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, asset retirement obligations, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are a ppropriate and reasonable. Actual results could differ materially from those estimates.

New And Significant Accounting

New And Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
New And Significant Accounting Policies	NOTE 2: SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2014 Form 10-K. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterp rise 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 June 30, 2015 , it assessed wheth er 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-ma king rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered ele ctricity 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 June 30, 2015 , it did not consolidate any of them. Pension and Other Postretirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Bot h plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2015 and 2014 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 118 $ 96 $ 14 $ 11 Interest cost 169 173 18 19 Expected return on plan assets (218) (201) (28) (26) Amortization of prior service cost 3 5 5 5 Amortization of net actuarial loss 3 1 1 1 Net periodic benefit cost 75 74 10 10 Regulatory account transfer (1) 9 9 - - Total $ 84 $ 83 $ 10 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 237 $ 195 $ 27 $ 22 Interest cost 337 346 36 38 Expected return on plan assets (436) (403) (56) (52) Amortization of prior service cost 7 10 10 11 Amortization of net actuarial loss 6 1 2 1 Net periodic benefit cost 151 149 19 20 Regulatory account transfer (1) 18 19 - - Total $ 169 $ 168 $ 19 $ 20 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The chan ges, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ (6) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 2 3 5 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (3) (4) (7) Net current period other comprehensive loss - - - Ending balance $ (21) $ 15 $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 47 $ 55 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - 5 5 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 3 3 - 6 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $2, $2, and $0, respectively) (1) (4) (4) - (8) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (11) (11) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3, $4, and $0, respectively) (1) 4 6 - 10 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 3 1 - 4 Regulatory account transfer (net of taxes of $6, $5, and $0, respectively) (1) (7) (7) - (14) Change in investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss - - (17) (17) Ending balance $ (21) $ 15 $ - $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $7, respectively) - - 10 10 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $4, and $0, respectively) (1) 6 7 - 13 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $4, $4, and $0, respectively) (1) (7) (8) - (15) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (6) (6) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) There was no material difference between PG&E Corp oration and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation. Accounting Standards Issued But Not Yet Adopted Fair Value Measurement In May 2015, the FASB issued ASU No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using the net asset value per share. The accounting standards update will be effective for fiscal years beginning after Decembe r 15, 2015. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their disclosures and will adopt this standard starting in the first quarter of 2016. Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the 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 tre atment for cloud computing arrangements. The accounting standards update will be effective on January 1, 2016. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and rela ted disclosures and 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 D ebt 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 Accounting Standard Upd ate, effective 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 Corpor ation and the Utility do not expect this reclassification to have a material impact on their consolidated financial statements. PG&E Corporation and the Utility will adopt this standard starting in the first quarter of 2016. Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance . In July 2015, the FASB deferred the effective date of this amendment for public companies 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 ev aluating the impact the guidance will have on their consolidated financial statements and related disclosures.

Regulatory Assets, Liabilities,

Regulatory Assets, Liabilities, And Balancing Accounts	6 Months Ended
	Jun. 30, 2015
Regulatory Assets, Liabilities, And Balancing Accounts	NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets Long-term regulatory assets are composed of the following: Balance at June 30, December 31, (in millions) 2015 2014 Pension benefits $ 2,316 $ 2,347 Deferred income taxes 2,649 2,390 Environmental compliance costs 686 717 Utility retained generation 434 456 Price risk management 142 127 Unamortized loss, net of gain, on reacquired debt 103 113 Electromechanical meters 36 70 Other 110 102 Total long-term regulatory assets $ 6,476 $ 6,322 Regulatory Liabilities Long-term regulatory liabilities are composed of the following: Balance at June 30, December 31, (in millions) 2015 2014 Cost of removal obligations $ 4,414 $ 4,211 Recoveries in excess of asset retirement obligations 719 754 Public purpose programs 708 701 Other 489 624 Total long-term regulatory liabilities $ 6,330 $ 6,290 Regulatory Balancing Accounts The Utility’s recovery of revenue requirements and costs is generally decoupled from the volume of sales. The Utility tracks (1) differences between the Utility’s authorized revenue requirement and 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 ba lancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabili ties, respectively, in the Condensed Consolidated Balance Sheets. 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 regulato ry balancing accounts receivable and payable are composed of the following: Receivable Balance at June 30, December 31, (in millions) 2015 2014 Electric distribution $ 672 $ 344 Utility generation 392 261 Gas distribution 504 566 Energy procurement 308 608 Public purpose programs 82 109 Other 246 378 Total regulatory balancing accounts receivable $ 2,204 $ 2,266 Payable Balance at June 30, December 31, (in millions) 2015 2014 Energy procurement $ 173 $ 188 Public purpose programs 177 154 Other (1) 526 748 Total regulatory balancing accounts payable $ 876 $ 1,090 (1) At June 30, 2015 and December 31, 2014 , Other regulatory balancing accounts payable mostly included energy supplier settlements related to the Utility’s outstanding bankruptcy claims. (See “Resolution of Remaining Chapter 11 Disputed Clai ms” in Note 9 below).

Debt

Debt	6 Months Ended
	Jun. 30, 2015
Debt	NOTE 4: DEBT Short-term Borrowings Revolving Credit Facilities and Commercial Paper Program On April 27, 2015, PG& E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013. The amendments and restatements extended the termination 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. The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial p aper programs at June 30, 2015 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2020 $ 300 (1) $ - $ 5 $ 295 Utility April 2020 3,000 (2) 33 1,011 1,956 Total revolving credit facilities $ 3,300 $ 33 $ 1,016 $ 2,251 (1) Includes a $50 million sublimit for letters of credit and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans. In July 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, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a r eduction to the amount available under their respective revolving credit facilities. Long-term Debt Issuances and Maturities In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. In addition, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured in May 2015. Variable Rate Interest At June 30, 2015 , the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.01 % to 0.03 %. At June 30, 2015 , the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.02% to 0.03 %.

Equity

Equity	6 Months Ended
	Jun. 30, 2015
Equity	NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2015 were as follows: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2014 $ 16,000 $ 16,229 Comprehensive income 423 410 Equity contributions - 185 Common stock issued 262 - Share-based compensation 34 4 Common stock dividends declared (441) (358) Preferred stock dividend requirement - (7) Preferred stock dividend requirement of subsidiary (7) - Balance at June 30, 2015 $ 16,271 $ 16,463 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. In the first quarter of 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. No shares were sold during the three months ended June 30, 2015 . PG& E Corporation issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the six months ended June 30, 2015 , 4.3 million shares were issued for cash proceeds of $ 178 million under t hese plans.

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2015
Earnings Per Share	NOTE 6: EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended Six Months Ended June 30, June 30, (in millions, except per share amounts) 2015 2014 2015 2014 Income available for common shareholders $ 402 $ 267 $ 433 $ 494 Weighted average common shares outstanding, basic 480 467 479 463 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 4 2 Weighted average common share outstanding, diluted 483 469 483 465 Total earnings per common share, diluted $ 0.83 $ 0.57 $ 0.90 $ 1.06 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2015
Derivatives	NOTE 7: DERIVATIVES Use of Derivative Instruments The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both 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 Condensed 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 Condensed Consolidated Balance Sheets. These in struments 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 asse ts and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing acc ounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility ov er a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accoun ted for under the accrual method of accounting. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at June 30, December 31, Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 267,835,872 308,130,101 Options 125,392,380 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 4,904,985 5,346,787 Congestion Revenue Rights (3) 197,344,663 224,124,341 (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 June 30, 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 $ 70 $ (4) $ 15 $ 81 Other noncurrent assets – other 156 (5) - 151 Current liabilities – other (70) 4 23 (43) Noncurrent liabilities – other (147) 5 19 (123) Net commodity risk $ 9 $ - $ 57 $ 66 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) Net commodity risk $ 33 $ - $ 54 $ 87 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended Six Months Ended June 30, June 30, (in millions) 2015 2014 2015 2014 Unrealized gain (loss) - regulatory assets and liabilities (1) $ 28 $ 27 $ (24) $ 85 Realized gain (loss) - cost of electricity (2) 10 (8) 3 (26) Realized loss - cost of natural gas (2) (4) (3) (5) (3) Net commodity risk $ 34 $ 16 $ (26) $ 56 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact o f cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2015 , the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility wo uld be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were trigg ered was as follows: Balance at June 30, December 31, (in millions) 2015 2014 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (2) $ (47) 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	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements	NOTE 8: 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 f air 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 – Oth er inputs that are directly or indirectly observable in the marketplace. Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimiz e the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (assets held in rabbi trusts and other investments are held by PG&E C orporation and not the Utility): Fair Value Measurements At June 30, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 109 $ - $ - $ - $ 109 Nuclear decommissioning trusts Money market investments 32 - - - 32 Global equity securities 1,587 13 - - 1,600 Fixed-income securities 681 541 - - 1,222 Total nuclear decommissioning trusts (2) 2,300 554 - - 2,854 Price risk management instruments (Note 7) Electricity 1 8 212 6 227 Gas 1 4 - - 5 Total price risk management instruments 2 12 212 6 232 Rabbi trusts Fixed-income securities - 42 - - 42 Life insurance contracts - 72 - - 72 Total rabbi trusts - 114 - - 114 Long-term disability trust Money market investments 4 - - - 4 Global equity securities - 22 - - 22 Fixed-income securities - 117 - - 117 Total long-term disability trust 4 139 - - 143 Total assets $ 2,415 $ 819 $ 212 $ 6 $ 3,452 Liabilities: Price risk management instruments (Note 7) Electricity $ 47 $ 4 $ 164 $ (51) $ 164 Gas - 2 - - 2 Total liabilities $ 47 $ 6 $ 164 $ (51) $ 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 $ 350 million, primarily related to deferred taxes on appreciati on 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 in the 2014 Form 10-K) 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 in the 2014 Form 10-K) 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 utili ze investment strategies aimed at matching the performance of indexed funds. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the six months ended June 30, 2015 and 2014 . Trust Assets Nuclear decommissioning trust assets and othe r trust assets are composed primarily of equity securities, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Equity securiti es primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges ac ross 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 agenc y securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determ ined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power pu rchase 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 forwa rds and swaps that are identical to exchange-traded forwards and swaps, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of California Independent System Operator-imposed congestion charges in the day-ahead market. CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices. Limited market da ta is available in the California Independent System Operator auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to the Chief Risk Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management funct ions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonabl eness. 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; theref ore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.) Fair Value at (in millions) At June 30, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 212 $ 62 Market approach CRR auction prices $ (47.09) - 8.17 Power purchase agreements $ - $ 102 Discounted cash flow Forward prices $ 22.04 - 57.00 (1) 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 Power pur chase agreements $ - $ 100 Discounted cash flow Forward prices $ 16.04 - 56.21 (1) Represents price per megawatt-hour Level 3 Reconciliation The following tables present the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2015 and 2014 : Price Risk Management Instruments (in millions) 2015 2014 Asset (liability) balance as of April 1 $ 42 $ (22) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 6 11 Asset (liability) balance as of June 30 $ 48 $ (11) (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. 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) (21) 19 Asset (liability) balance as of June 30 $ 48 $ (11) (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 variab le rate pollution control bond loan agreements approximate their carrying values at June 30, 2015 and December 31, 2014 , as they are short-term in nature or have intere st rates that reset daily. The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at June 3 0, 2015 and December 31, 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 val ues that approximate their fair values): At June 30, 2015 At December 31, 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 351 $ 350 $ 352 Utility 14,272 15,715 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 June 30, 2015 Nuclear decommissioning trusts Money market investments $ 32 $ - $ - $ 32 Global Equity securities 516 1,091 (7) 1,600 Fixed Income securities 1,169 60 (7) 1,222 Total (1) $ 1,717 $ 1,151 $ (14) $ 2,854 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 $ 350 million and $324 million at June 30, 2015 and December 31, 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) June 30, 2015 Less than 1 year $ 19 1–5 years 458 5–10 years 277 More than 10 years 468 Total maturities of debt securities $ 1,222 The following table provides a summary of activity for the debt and equity securities: Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 362 347 779 877 Gross realized gains on securities held as available-for-sale 12 28 47 84 Gross realized losses on securities held as available-for-sale (10) (2) (13) (3)

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies	NOTE 9: CONTINGENCIES AND COMMITMENTS PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. The Utility also has substantial financial com mitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters. Enforce ment and Litigation Matters Improper CPUC Communications In the Penalty Decision (further described below), the CPUC stated that it will begin a new investigation to examine allegations by the City of San Bruno that communications between the Utility’s employees and CPUC personnel violated the CPUC’s rules relating to ex parte communications. Ex parte communications include any communication between a decision maker and an interested person concerning substantive issues in certain identified categories of formal proceedings before the CPUC. The Utility believes that the communications cited by San Bruno are not prohibited ex parte communications. If the CPUC determines that the communications constitute ex parte violations, it is reasonably possible t hat the CPUC will impose penalties or other remedies, but the Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determi ning the final penalties. In September 2014, t he Utility notified the CPUC of ex parte communications between the Utility and the CPUC regarding the 2015 GT&S rate case. In November 2014, the CPUC imposed a fine of $1.05 million on the Utility for these communications. In addition, the CPUC disallowed the Utility from recovering up to the entire amount of the revenue increase that may be authorized in the pending GT&S rate case and that otherwise would have been collected from ratepayers over a five-mon th period. The CPUC will determine the amount of this disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements. In October and December 2014, the Utility also notified the CPUC of additional email communications between the Utility and the CPUC regarding various matters (not limited to the GT&S rate case) that the Utility believes may constitute or describe ex parte communications. For these additional communications, the Utility believes it is probable that CPUC enforcement action will be taken. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalti es. On May 21, 2015, the Utility filed various documents (including copies of internal email correspondence) with the CPUC to complete its response to orders issued by CPUC administrative law judges regarding potential ex parte communications between the Utility and CPUC personnel. The Utility also notified the CPUC of an additional potential ex parte communication made in the 2011 General Rate Case to supplement a notification that the Utility voluntarily provided on October 6, 2014. It is uncertain what action the CPUC or other parties will take in response to these additional reported communications. It is possible that additional orders will be issued to which the Utility will be required to respond. The CPUC could impose fines and penalties on the Util ity relating to communications reported to the CPUC or with respect to additional communications that the Utility may identify and report in response to new orders that may be issued or in connection with new or ongoing investigations or legal proceedings. The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have also begun investigations in connection with the ex parte communications. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility . Other CPUC Matters CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping On November 20, 2014, the CPUC began an investigation into whether the Utility violated applica ble laws pertaining to record-keeping practices for its natural gas distribution service and facilities. The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utili ties Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurre d in Carmel, California on March 3, 2014. On April 10, 2015, the assigned Commissioner issued a scoping memo and ruling stating that the scope of the proceeding is whether or not the Utility violated any applicable laws, rules, or regulations “by its reco rd-keeping policies and practices with respect to maintaining safe operation of its gas distribution system.” The scope of the proceeding also may include matters resulting from the SED’s ongoing reviews of the Utility’s record-keeping practices relating to mapping, pre-excavation location and marking, and pressure validation for distribution facilities, among other issues. The procedural schedule requires the SED’s and intervenors’ testimony to be submitted starting in September 2015 with the Utility’s r esponse due in November 2015, followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016. PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or require the Utility to implement operational remedies. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties and given the fact that the extent of any alleged violations is currently unknown. In addition, the Utility could incur material costs to implement operational remedies, which may not be recoverable. 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 b uilding structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period a nd 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 S ED 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 rem ove encroachments. T he 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 Cita tions 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 additio n, the California utilities are required to inform the SED of self-identified or self-corrected violations. The SED has authority to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can c onsider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whethe r corrective actions were taken. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of 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 natural gas 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 una ble 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 given the wide discretion the SED has in determining whether to bring enforcement action and the number of fa ctors that can be considered in determining the amount of fines. Federal Matters Federal Criminal Indictment On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the U tility in federal district court that succeeded 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 N atural Gas Pipeline Safety Act relating to recordkeeping, 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 investigat ion into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also seeks an alternative fine under the Alternative Fines Act which states, in part: “ If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” Based on the su perseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternative fine would be approximately $1.13 billion. The Utility ente red 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 obstruct th e 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 Condensed Consolidated Financial Statements as such amounts are not considered to be probable. The trial is set to begin March 8, 2016. 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. (For more information refer to Note 14 of the Notes to the Consolidated Financial Statements appearing under Item 8 in the 2014 Form 10-K). It is uncertain whether any charges will be brought against the Utility . The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case. Capital Expenditures relating to Pipeline Safety Enhancement Plan At June 30, 2015, approximately $ 645 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Condensed Consolidated Balance Sheets. The Utility would be required to record charges to the statement of income in future periods to the extent PSEP-related capital costs are higher than currently expected. Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission The Penalty Decision (see Note 1 above) imposes penalties 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 CPU C estimates will cost the Utility at least $50 million. For the three months and six months ended June 30, 2015, the Utility recorded additional charges of $75 million and $628 million, respectively, as a result of the Penalty Decision. The cumulative charges at June 30, 2015, and the anticipated future financial impact are shown in the following table: Anticipated Six Months Cumulative Future Ended Charges Financial Total (in millions) June 30, 2015 June 30, 2015 Impact Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 128 128 561 689 Disallowed revenue for pipeline safety expenses (3) - - 161 161 CPUC estimated cost of other remedies (4) - 20 30 50 Total Penalty Decision fines and remedies recorded $ 628 $ 848 $ 752 $ 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 case. The Utility estimates that approximately $75 million and $128 million of capital spending (which include less than $1 million for remedy relat ed capital costs) in the three months and six months ended June 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision. (3) These costs are being expensed as incurred. Future GT&S revenue s will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred. At June 30, 2015, the Condensed Consolidated Balance Sheets include $300 million in other current liabilities for the fines payable, and $400 million in current regulatory liabilities for the one-time bill credit due to the Utility’s natural gas customers. The charges recorded are refle cted in operating and maintenance expenses in the June 30, 2015, Condensed Consolidated Statements of Income. The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be pre cluded from including these capital costs in rate base. The remainder will be allocated to safety-related expenses. The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case. I f the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. It is uncertain what costs the CP UC will ultimately count towards the $850 million shareholder-funded obligation. To the extent the Utility’s actual costs exceed qualified amounts and are not authorized for recovery, the Utility may be required to record additional charges in future peri ods. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify the safety-related project and programs that will be subject to the disallowance. Other Legal and Regulatory Contingencies Accruals for other leg al and regulatory contingencies (excluding amounts related to the enforcement and litigation matters described above) totaled $ 43 million at June 30, 2015, and $55 million at De cember 31, 2014. These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. Environmental Remediation Contingencies The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following: Balance at (in millions) June 30, 2015 December 31, 2014 Topock natural gas compressor station (1) $ 297 $ 291 Hinkley natural gas compressor station (1) 149 158 Former manufactured gas plant sites owned by the Utility or third parties 263 257 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 153 150 Fossil fuel-fired generation facilities and sites 96 98 Total environmental remediation liability $ 958 $ 954 (1) See “Natural Gas Compressor Station Sites” below. At June 30, 2015 , the Utility expected to recover $ 676 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. The Utility will also incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater con tamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility is also required to take measures to abate the effects of the contamination on the environment. Hinkley Site The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility's remediation and abatement efforts at the Hinkley site are overseen by the Regional Board. In January 2015, the Regional Board issued an updated draft clean-up and abatement order that proposes the Utility continues and improves its remedial treatment methods and contains a proposed monitoring and reporting program. The Regional Board is expected to issue a revised draft clean-up and abate ment order in August 2015. After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order (which may include deadlines to meet specified interim clean up targets) at its November 2015 meeting. T he Utility’s environmental remediation liability at June 30, 2015 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and interim remed iation measures. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, and the nature and extent of the chromium contamination. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows. Topock Site The Utility's remediation and abat ement efforts at the Topock site are overseen by the DTSC and the U.S. Department of the Interior. While the Utility has been working with these agencies to develop a final remediation plan, the Utility has been employing various interim remediation measu res, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. In September 2014, the Utility submitted its near-final remediation plan to the agencies for approval. The Uti lity’s plan 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 plan, and t he 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 impact report in Decemb er 2016. After the Utility modifies its plan 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 liability at June 30, 2015 r eflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the scope and timing of required remediation work. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows. Reasonably Possible Environmental Contingencies Although the Utility has provided for known environmental obligations that are probable and reasonably estimable , the Utility’s undiscounted future costs could increase to as much as $ 1.8 billion (including amounts related to the Hinkley and Topock sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs. The Utility may incur actual costs in the fu ture that are materially different than this estimate and such costs could have a material impact on results of operations during the period in which they are recorded. Resolution of Remaining Chapter 11 Disputed Claims Various electricity suppliers file d claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. The Utility has entered into a number of settlement agreements with vari ous electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. At December 31, 2014 , the Consolidated Balance Sheets reflected $ 434 million in net claims, within Disputed claims and customer refunds, and $ 291 million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash. There were no significant changes to th ese balances during the six months ended June 30, 2015 . Tax Matters The IRS is currently reviewing several matters in the 2011, 2012, and 2013 tax returns. The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining which repair costs are deductible for the electric transmission and distribution businesses. PG&E Corporation and the Utility expect that the IRS will complete its review of the deductible repair costs for t he electric transmission and distribution businesses in 2015. The IRS is also expected to issue guidance during 2015 that determines which repair costs are deductible for the natural gas transmission and distribution businesses. PG&E Corporation’s and th e Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the audits related to the 2011, 2012, and 2013 tax returns. As of June 30, 2015, it is reasonably p ossible that unrecognized tax benefits will decrease by approximately $ 370 million within the next 12 months, and most of this decrease would not impact net income. There were no other significant developments to tax matters during the six months ended June 30, 2015. (Refer to Note 8 of the Notes to the Consolidated F inancial Statements in Item 8 of the 2014 Form 10-K.) Purchase Commitments In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, 2014 the Utility had undiscounted future expected obligations of approximately $53.3 billion. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 20 14 Form 10-K.) During the six months ended June 30, 2015, the Utility entered into several renewable energy and other power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additi onal commitments of approximately $465 million over the next 25 years.

New And Significant Accountin18

New And Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities	Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterp rise 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 June 30, 2015 , it assessed wheth er 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-ma king rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered ele ctricity 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 June 30, 2015 , it did not consolidate any of them.
Pension And Other Postretirement Benefits	Pension and Other Postretirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Bot h plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2015 and 2014 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 118 $ 96 $ 14 $ 11 Interest cost 169 173 18 19 Expected return on plan assets (218) (201) (28) (26) Amortization of prior service cost 3 5 5 5 Amortization of net actuarial loss 3 1 1 1 Net periodic benefit cost 75 74 10 10 Regulatory account transfer (1) 9 9 - - Total $ 84 $ 83 $ 10 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 237 $ 195 $ 27 $ 22 Interest cost 337 346 36 38 Expected return on plan assets (436) (403) (56) (52) Amortization of prior service cost 7 10 10 11 Amortization of net actuarial loss 6 1 2 1 Net periodic benefit cost 151 149 19 20 Regulatory account transfer (1) 18 19 - - Total $ 169 $ 168 $ 19 $ 20 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
Amounts Reclassified Out of Accumulated Other Comprehensive Income	Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The chan ges, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ (6) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 2 3 5 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (3) (4) (7) Net current period other comprehensive loss - - - Ending balance $ (21) $ 15 $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 47 $ 55 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - 5 5 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 3 3 - 6 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $2, $2, and $0, respectively) (1) (4) (4) - (8) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (11) (11) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3, $4, and $0, respectively) (1) 4 6 - 10 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 3 1 - 4 Regulatory account transfer (net of taxes of $6, $5, and $0, respectively) (1) (7) (7) - (14) Change in investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss - - (17) (17) Ending balance $ (21) $ 15 $ - $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $7, respectively) - - 10 10 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $4, and $0, respectively) (1) 6 7 - 13 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $4, $4, and $0, respectively) (1) (7) (8) - (15) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (6) (6) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) There was no material difference between PG&E Corp oration and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.

New And Significant Accountin19

New And Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Components Of Net Periodic Benefit Cost	Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 118 $ 96 $ 14 $ 11 Interest cost 169 173 18 19 Expected return on plan assets (218) (201) (28) (26) Amortization of prior service cost 3 5 5 5 Amortization of net actuarial loss 3 1 1 1 Net periodic benefit cost 75 74 10 10 Regulatory account transfer (1) 9 9 - - Total $ 84 $ 83 $ 10 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 237 $ 195 $ 27 $ 22 Interest cost 337 346 36 38 Expected return on plan assets (436) (403) (56) (52) Amortization of prior service cost 7 10 10 11 Amortization of net actuarial loss 6 1 2 1 Net periodic benefit cost 151 149 19 20 Regulatory account transfer (1) 18 19 - - Total $ 169 $ 168 $ 19 $ 20 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income	Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ (6) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 2 3 5 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (3) (4) (7) Net current period other comprehensive loss - - - Ending balance $ (21) $ 15 $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 47 $ 55 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - 5 5 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 3 3 - 6 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $2, $2, and $0, respectively) (1) (4) (4) - (8) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (11) (11) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $3, $4, and $0, respectively) (1) 4 6 - 10 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 3 1 - 4 Regulatory account transfer (net of taxes of $6, $5, and $0, respectively) (1) (7) (7) - (14) Change in investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive loss - - (17) (17) Ending balance $ (21) $ 15 $ - $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Six Months Ended June 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $7, respectively) - - 10 10 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $4, and $0, respectively) (1) 6 7 - 13 Amortization of net actuarial loss (net of taxes of $0, $0, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $4, $4, and $0, respectively) (1) (7) (8) - (15) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (16) (16) Net current period other comprehensive loss - - (6) (6) Ending balance $ (7) $ 15 $ 36 $ 44 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)

Regulatory Assets, Liabilitie20

Regulatory Assets, Liabilities, And Balancing Accounts (Tables)	6 Months Ended
	Jun. 30, 2015
Long-Term Regulatory Assets	Balance at June 30, December 31, (in millions) 2015 2014 Pension benefits $ 2,316 $ 2,347 Deferred income taxes 2,649 2,390 Environmental compliance costs 686 717 Utility retained generation 434 456 Price risk management 142 127 Unamortized loss, net of gain, on reacquired debt 103 113 Electromechanical meters 36 70 Other 110 102 Total long-term regulatory assets $ 6,476 $ 6,322
Long-Term Regulatory Liabilities	Balance at June 30, December 31, (in millions) 2015 2014 Cost of removal obligations $ 4,414 $ 4,211 Recoveries in excess of asset retirement obligations 719 754 Public purpose programs 708 701 Other 489 624 Total long-term regulatory liabilities $ 6,330 $ 6,290
Regulatory Balancing Accounts Receivable	Receivable Balance at June 30, December 31, (in millions) 2015 2014 Electric distribution $ 672 $ 344 Utility generation 392 261 Gas distribution 504 566 Energy procurement 308 608 Public purpose programs 82 109 Other 246 378 Total regulatory balancing accounts receivable $ 2,204 $ 2,266
Regulatory Balancing Accounts Payable	Payable Balance at June 30, December 31, (in millions) 2015 2014 Energy procurement $ 173 $ 188 Public purpose programs 177 154 Other (1) 526 748 Total regulatory balancing accounts payable $ 876 $ 1,090 (1) At June 30, 2015 and December 31, 2014 , Other regulatory balancing accounts payable mostly included energy supplier settlements related to the Utility’s outstanding bankruptcy claims. (See “Resolution of Remaining Chapter 11 Disputed Clai ms” in Note 9 below).

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure Debt [Abstract]
Schedule of Line of Credit Facilities	The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial p aper programs at June 30, 2015 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2020 $ 300 (1) $ - $ 5 $ 295 Utility April 2020 3,000 (2) 33 1,011 1,956 Total revolving credit facilities $ 3,300 $ 33 $ 1,016 $ 2,251 (1) Includes a $50 million sublimit for letters of credit and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Changes In Equity	PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2014 $ 16,000 $ 16,229 Comprehensive income 423 410 Equity contributions - 185 Common stock issued 262 - Share-based compensation 34 4 Common stock dividends declared (441) (358) Preferred stock dividend requirement - (7) Preferred stock dividend requirement of subsidiary (7) - Balance at June 30, 2015 $ 16,271 $ 16,463

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2015
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted	Three Months Ended Six Months Ended June 30, June 30, (in millions, except per share amounts) 2015 2014 2015 2014 Income available for common shareholders $ 402 $ 267 $ 433 $ 494 Weighted average common shares outstanding, basic 480 467 479 463 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 4 2 Weighted average common share outstanding, diluted 483 469 483 465 Total earnings per common share, diluted $ 0.83 $ 0.57 $ 0.90 $ 1.06

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2015
Volumes Of Outstanding Derivative Contracts	Contract Volume at June 30, December 31, Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 267,835,872 308,130,101 Options 125,392,380 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 4,904,985 5,346,787 Congestion Revenue Rights (3) 197,344,663 224,124,341 (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.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	At June 30, 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 $ 70 $ (4) $ 15 $ 81 Other noncurrent assets – other 156 (5) - 151 Current liabilities – other (70) 4 23 (43) Noncurrent liabilities – other (147) 5 19 (123) Net commodity risk $ 9 $ - $ 57 $ 66 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) Net commodity risk $ 33 $ - $ 54 $ 87
Gains And Losses On Derivative Instruments	Commodity Risk Three Months Ended Six Months Ended June 30, June 30, (in millions) 2015 2014 2015 2014 Unrealized gain (loss) - regulatory assets and liabilities (1) $ 28 $ 27 $ (24) $ 85 Realized gain (loss) - cost of electricity (2) 10 (8) 3 (26) Realized loss - cost of natural gas (2) (4) (3) (5) (3) Net commodity risk $ 34 $ 16 $ (26) $ 56 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact o f cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered	Balance at June 30, December 31, (in millions) 2015 2014 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (2) $ (47) 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)	6 Months Ended
	Jun. 30, 2015
Assets And Liabilities Measured At Fair Value On A Recurring Basis	Fair Value Measurements At June 30, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 109 $ - $ - $ - $ 109 Nuclear decommissioning trusts Money market investments 32 - - - 32 Global equity securities 1,587 13 - - 1,600 Fixed-income securities 681 541 - - 1,222 Total nuclear decommissioning trusts (2) 2,300 554 - - 2,854 Price risk management instruments (Note 7) Electricity 1 8 212 6 227 Gas 1 4 - - 5 Total price risk management instruments 2 12 212 6 232 Rabbi trusts Fixed-income securities - 42 - - 42 Life insurance contracts - 72 - - 72 Total rabbi trusts - 114 - - 114 Long-term disability trust Money market investments 4 - - - 4 Global equity securities - 22 - - 22 Fixed-income securities - 117 - - 117 Total long-term disability trust 4 139 - - 143 Total assets $ 2,415 $ 819 $ 212 $ 6 $ 3,452 Liabilities: Price risk management instruments (Note 7) Electricity $ 47 $ 4 $ 164 $ (51) $ 164 Gas - 2 - - 2 Total liabilities $ 47 $ 6 $ 164 $ (51) $ 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 $ 350 million, primarily related to deferred taxes on appreciati on 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 in the 2014 Form 10-K) 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 in the 2014 Form 10-K) 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.
Level 3 Measurements And Sensitivity Analysis	Fair Value at (in millions) At June 30, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 212 $ 62 Market approach CRR auction prices $ (47.09) - 8.17 Power purchase agreements $ - $ 102 Discounted cash flow Forward prices $ 22.04 - 57.00 (1) 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 Power pur chase 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 April 1 $ 42 $ (22) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) 6 11 Asset (liability) balance as of June 30 $ 48 $ (11) (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. 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) (21) 19 Asset (liability) balance as of June 30 $ 48 $ (11) (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 June 30, 2015 At December 31, 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 351 $ 350 $ 352 Utility 14,272 15,715 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 June 30, 2015 Nuclear decommissioning trusts Money market investments $ 32 $ - $ - $ 32 Global Equity securities 516 1,091 (7) 1,600 Fixed Income securities 1,169 60 (7) 1,222 Total (1) $ 1,717 $ 1,151 $ (14) $ 2,854 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 $ 350 million and $324 million at June 30, 2015 and December 31, 2014 , respectively, primarily related to deferred taxes on appreciation of investment value.
Schedule Of Maturities On Debt Instruments	As of (in millions) June 30, 2015 Less than 1 year $ 19 1–5 years 458 5–10 years 277 More than 10 years 468 Total maturities of debt securities $ 1,222
Schedule Of Activity For Debt And Equity Securities	Three Months Ended Six Months Ended June 30, June 30, 2015 2014 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 362 347 779 877 Gross realized gains on securities held as available-for-sale 12 28 47 84 Gross realized losses on securities held as available-for-sale (10) (2) (13) (3)

Commitments And Contingencies (

Commitments And Contingencies (Tables)	6 Months Ended
	Jun. 30, 2015
Impact Of The Penalty Decision	Anticipated Six Months Cumulative Future Ended Charges Financial Total (in millions) June 30, 2015 June 30, 2015 Impact Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 128 128 561 689 Disallowed revenue for pipeline safety expenses (3) - - 161 161 CPUC estimated cost of other remedies (4) - 20 30 50 Total Penalty Decision fines and remedies recorded $ 628 $ 848 $ 752 $ 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 case. The Utility estimates that approximately $75 million and $128 million of capital spending (which include less than $1 million for remedy relat ed capital costs) in the three months and six months ended June 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision. (3) These costs are being expensed as incurred. Future GT&S revenue s will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.
Schedule Of Environmental Remediation Liability	Balance at (in millions) June 30, 2015 December 31, 2014 Topock natural gas compressor station (1) $ 297 $ 291 Hinkley natural gas compressor station (1) 149 158 Former manufactured gas plant sites owned by the Utility or third parties 263 257 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 153 150 Fossil fuel-fired generation facilities and sites 96 98 Total environmental remediation liability $ 958 $ 954 (1) See “Natural Gas Compressor Station Sites” below.

Organization And Basis of Pre27

Organization And Basis of Presentation (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended			12 Months Ended
		Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015		Jun. 30, 2014	Dec. 31, 2014
Organization And Basis Of Presentation [Line Items]
Total Penalties Issued by CPUC				$ 628
Fine payable to the state			$ 100	100	[1]		$ 200
Bill Credit to Natural Gas Customers				400
Charge for disallowed capital		$ 74		128		$ 0
C P U C Remedial Measures	[2]			0
C P U C Disallowed Future P S E P Spending				850
Total Penalty Decision [Member]
Organization And Basis Of Presentation [Line Items]
Total Penalties Issued by CPUC				1,600
Fine payable to the state	[1]			300
Bill Credit to Natural Gas Customers				400
Charge for disallowed capital				688.5
C P U C Remedial Measures	[2]			50
Pacific Gas And Electric Company [Member]
Organization And Basis Of Presentation [Line Items]
Charge for disallowed capital				$ 128		$ 0
[1]	In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.
[2]	In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.

New And Significant Accountin28

New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned		$ 118	$ 96	$ 237	$ 195
Interest cost		169	173	337	346
Expected return on plan assets		(218)	(201)	(436)	(403)
Amortization of prior service cost		3	5	7	10
Amortization of net actuarial loss		3	1	6	1
Net periodic benefit cost		75	74	151	149
Less: transfer to regulatory account	[1]	9	9	18	19
Total		84	83	169	168
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned		14	11	27	22
Interest cost		18	19	36	38
Expected return on plan assets		(28)	(26)	(56)	(52)
Amortization of prior service cost		5	5	10	11
Amortization of net actuarial loss		1	1	2	1
Net periodic benefit cost		10	10	19	20
Less: transfer to regulatory account	[1]	0	0	0	0
Total		$ 10	$ 10	$ 19	$ 20
[1]	The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in futures rates.

New And Significant Accountin29

New And Significant Accounting Policies (Reclassifications Out Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	$ (6)	$ 55	$ 11	$ 50
Change in investments	0	(11)	(17)	(6)
Net current period other comprehensive income (loss)	0	(11)	(17)	(6)
Ending balance	(6)	44	(6)	44
Net change in investments tax	0	7	12	3
Net actuarial loss tax	0	0	0	0
Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Change in investments		5		10
Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	5	6	10	13
Amortization of net actuarial loss	2	2	4	2
Transfer to regulatory account	(7)	(8)	(14)	(15)
Realized gain on investments		(16)	(17)	(16)
Pension Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	(21)	(7)	(21)	(7)
Amortization of prior service cost	3	5	7	10
Amortization of net actuarial loss	3	1	6	1
Net current period other comprehensive income (loss)	0	0	0	0
Ending balance	(21)	(7)	(21)	(7)
Pension Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Change in investments		0		0
Pension Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	2	3	4	6
Amortization of net actuarial loss	1	1	3	1
Transfer to regulatory account	(3)	(4)	(7)	(7)
Realized gain on investments		0	0	0
Amortization of prior service cost tax	1	2	3	4
Net actuarial loss tax	2	0	3	0
Regulatory account transfer	3	2	6	4
Other Benefits [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance	15	15	15	15
Amortization of prior service cost	5	5	10	11
Amortization of net actuarial loss	1	1	2	1
Net current period other comprehensive income (loss)	0	0	0	0
Ending balance	15	15	15	15
Other Benefits [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Change in investments		0		0
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost	3	3	6	7
Amortization of net actuarial loss	1	1	1	1
Transfer to regulatory account	(4)	(4)	(7)	(8)
Realized gain on investments		0	0	0
Amortization of prior service cost tax	2	2	4	4
Net actuarial loss tax	1	0	1	0
Regulatory account transfer	3	2	5	4
Other Investments [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Beginning balance		47	17	42
Net current period other comprehensive income (loss)		(11)	(17)	(6)
Ending balance	0	36	0	36
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Change in investments		5		10
Net change in investments tax	0	3	0	7
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Amortization of prior service cost		0	0	0
Amortization of net actuarial loss		0	0	0
Transfer to regulatory account		0	0	0
Realized gain on investments		(16)	(17)	(16)
Change in investments tax	$ 0	$ 10	$ 12	$ 10

Regulatory Assets, Liabilitie30

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - Entity [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 6,476	$ 6,322
Pension Benefits [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,316	2,347
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,649	2,390
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	434	456
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	686	717
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	142	127
Electromechanical Meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	36	70
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	103	113
Other Long Term Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 110	$ 102

Regulatory Assets, Liabilitie31

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - Entity [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 6,330	$ 6,290
Cost Of Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	4,414	4,211
Recoveries In Excess Of AROs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	719	754
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	708	701
Other Long Term Regulatory Assets (Liabilities) [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 489	$ 624

Regulatory Assets, Liabilitie32

Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Regulatory Balancing Accounts Receivable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 2,204	$ 2,266
Regulatory Balancing Accounts Receivable [Member] | Electric distribution [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	672	344
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	392	261
Regulatory Balancing Accounts Receivable [Member] | Gas distribution [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	504	566
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	308	608
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	82	109
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	246	378
Regulatory Balancing Accounts Payable [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	876	1,090
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	173	188
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	177	154
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 526	$ 748

Debt (Narrative) (Details)

Debt (Narrative) (Details) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, face amount	$ 614
Pollution Control Bonds Series 2009 A-D [Member]
Debt [Line Items]
Debt instrument, face amount	$ 309
Minimum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.01%
Minimum [Member] | Pollution Control Bonds Series 2009 A-D [Member]
Debt [Line Items]
Debt instrument, interest rate	0.02%
Maximum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]
Debt [Line Items]
Debt instrument, interest rate	0.03%
Maximum [Member] | Pollution Control Bonds Series 2009 A-D [Member]
Debt [Line Items]
Debt instrument, interest rate	0.03%
Utility [Member] | Senior Notes, 3.50%, Due 2025 [Member]
Debt [Line Items]
Debt instrument, interest rate	3.50%
Senior Notes	$ 400
Utility [Member] | Senior Notes, 4.30%, Due 2045 [Member]
Debt [Line Items]
Debt instrument, interest rate	4.30%
Senior Notes	$ 100
Utility [Member] | Floating Rate Senior Notes [Member]
Debt [Line Items]
Senior Notes	$ 300
PG&E Corporation [Member]
Debt [Line Items]
Line of Credit termination date	Apr. 27, 2020

Debt (Schedule Of Line Of Credi

Debt (Schedule Of Line Of Credit) (Details) - USD ($) $ in Millions		3 Months Ended
		Jun. 30, 2015	Mar. 31, 2015
Pacific Gas And Electric Company [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Letters of Credit Sublimit		$ 500	$ 1,000
Swingline Loans Sublimit		75	300
Commercial Paper Sublimit		$ 2,500	1,750
Swingline Loan Repay Term		7 days
Utility [Member]
Debt [Line Items]
Facility limit	[1]	$ 3,000
Letters Of Credit Outstanding Amount		33
Commercial Paper		1,011
Facility Availability		$ 1,956
P G E Corporation [Member]
Debt [Line Items]
Expiration date for credit agreement		Apr. 27, 2020
Facility limit	[2]	$ 300
Letters Of Credit Outstanding Amount		0
Commercial Paper		5
Facility Availability		295
Letters of Credit Sublimit		50	$ 100
Swingline Loans Sublimit		100
Commercial Paper Sublimit		$ 300
Swingline Loan Repay Term		7 days
Credit Facilities [Member]
Debt [Line Items]
Facility limit		$ 3,300
Letters Of Credit Outstanding Amount		33
Commercial Paper		1,016
Facility Availability		$ 2,251
[1]	Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.
[2]	Includes a $50 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

Equity (Narrative) (Detail)

Equity (Narrative) (Detail) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2015	Mar. 31, 2015
Fees and commissions		$ 1
Equity Contract [Member]
Equity Distribution Agreement, shares issued		1,400,000
Equity distribution agreement amount	$ 500
Stock Issued During Period Value Under Equity Distribution Agreement		$ 74
401K Plan, DRSPP, and Shared Based Compensation Plans [Member]
Stock issued during period for stock options exercised and under 401(K) plan and DRSPP, shares	4,300,000
Stock Issued During Period Value Stock Options Exercised	$ 178

Equity (Changes In Equity) (Det

Equity (Changes In Equity) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Balance at December 31, 2014			$ 15,748
Balance at December 31, 2014			16,000
Comprehensive Income Net Of Tax	$ 406	$ 260	423	$ 495
Common stock issued			262
Share-based compensation			34
Common stock dividends declared			(441)
Preferred stock dividend requirement of subsidiary	(4)	(4)	(7)	(7)
Balance at March 31, 2015	16,271		16,271
Balance at March 31, 2015	16,019		16,019
Pacific Gas And Electric Company [Member]
Balance at December 31, 2014			16,229
Comprehensive Income Net Of Tax	406	250	410	478
Common stock issued			0
Share-based compensation			4
Common stock dividends declared			(358)
Preferred stock dividend requirement	(4)	$ (4)	(7)	(7)
Equity contributions			185	$ 580
Balance at March 31, 2015	$ 16,463		$ 16,463

Earnings Per Share (Reconciliat

Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - Entity [Domain] - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income available for common shareholders	$ 402	$ 267	$ 433	$ 494
Weighted average common shares outstanding, basic	480	467	479	463
Employee share-based compensation	3	2	4	2
Weighted average common shares outstanding, diluted	483	469	483	465
Total earnings per common share, diluted	$ 0.83	$ 0.57	$ 0.90	$ 1.06

Derivatives (Volumes Of Outstan

Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details)		Jun. 30, 2015	Dec. 31, 2014
Forwards And Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[1],[2]	267,835,872	308,130,101
Forwards And Swaps [Member] | Electricity [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held		4,904,985	5,346,787
Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[1],[2]	125,392,380	164,418,002
Congestion Revenue Rights [Member] | Electricity [Member]
Derivative [Line Items]
Derivative Number Of Instruments Held	[3]	197,344,663	224,124,341
[1]	Amounts shown are for the combined positions of the electric fuels and core gas portfolios.
[2]	Million British Thermal Units.
[3]	CRRs are financial instruments that enable the holders to manage variability in congestion costs based on demand when there is insufficient transmission capacity.

Derivatives (Outstanding Deriva

Derivatives (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ 70	$ 73
Cash Collateral	15	19
Total Derivative Balance	81	88
Netting	(4)	(4)
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	156	178
Cash Collateral	0	0
Total Derivative Balance	151	165
Netting	(5)	(13)
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(70)	(78)
Cash Collateral	23	26
Total Derivative Balance	(43)	(48)
Netting	4	4
Other Noncurrent Liabilities [Member
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(147)	(140)
Cash Collateral	19	9
Total Derivative Balance	(123)	(118)
Netting	5	13
Gross Derivative Balance [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	9	33
Netting [Member]
Derivatives And Hedging Activities [Line Items]
Netting	0	0
Cash Collateral [Member
Derivatives And Hedging Activities [Line Items]
Cash Collateral	57	54
Total Derivatve Balance [Member]
Derivatives And Hedging Activities [Line Items]
Total Derivative Balance	$ 66	$ 87

Derivatives (Gains And Losses O

Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net unrealized gain (loss) - regulatory assets and liabilities	[1]	$ 28	$ 27	$ (24)	$ 85
Realized gain (loss) - cost of electricity	[2]	10	(8)	3	(26)
Realized loss - cost of natural gas	[2]	(4)	(3)	(5)	(3)
Total commodity risk		$ 34	$ 16	$ (26)	$ 56
[1]	Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
[2]	These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Derivatives (Additional Cash Co

Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized		$ (2)	$ (47)
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		Jun. 30, 2015		Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		$ 109		$ 94
Total assets		3,452		3,399
Total liabilities		166		166
Amount primarily related to deferred taxes on appreciation of investment value		350		324
Other Investments				33
Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		32		17
Total assets		2,854	[1]	2,745	[2]
Fixed-income securities		1,222		1,130
Global equity securities		1,600		1,598
Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		232		253
Electricity		227		251
Natural Gas		5		2
Electricity		164		163
Natural Gas		2		3
Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		114		114
Fixed-income securities		42		42
Life insurance contracts		72		72
Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		4		7
Total assets		143		160
Fixed-income securities		117		128
Global equity securities		22		25
Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		109		94
Total assets		2,415		2,478
Total liabilities		47		47
Other Investments				33
Fair Value Measurements, Level 1 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		32		17
Total assets		2,300	[1]	2,343	[2]
Fixed-income securities		681		741
Global equity securities		1,587		1,585
Fair Value Measurements, Level 1 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		2		1
Electricity		1		0
Natural Gas		1		1
Electricity		47		47
Natural Gas		0		0
Fair Value Measurements, Level 1 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0		0
Fixed-income securities		0		0
Life insurance contracts		0		0
Fair Value Measurements, Level 1 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		4		7
Total assets		4		7
Fixed-income securities		0		0
Global equity securities		0		0
Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		819		687
Total liabilities		6		8
Other Investments				0
Fair Value Measurements, Level 2 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		554	[1]	402	[2]
Fixed-income securities		541		389
Global equity securities		13		13
Fair Value Measurements, Level 2 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		12		18
Electricity		8		17
Natural Gas		4		1
Electricity		4		5
Natural Gas		2		3
Fair Value Measurements, Level 2 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		114		114
Fixed-income securities		42		42
Life insurance contracts		72		72
Fair Value Measurements, Level 2 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		139		153
Fixed-income securities		117		128
Global equity securities		22		25
Fair Value Measurements, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		212		232
Total liabilities		164		163
Other Investments				0
Fair Value Measurements, Level 3 [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		0	[1]	0	[2]
Fixed-income securities		0		0
Global equity securities		0		0
Fair Value Measurements, Level 3 [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		212		232
Electricity		212		232
Natural Gas		0		0
Electricity		164		163
Natural Gas		0		0
Fair Value Measurements, Level 3 [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets		0		0
Fixed-income securities		0		0
Life insurance contracts		0		0
Fair Value Measurements, Level 3 [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		0		0
Total assets		0		0
Fixed-income securities		0		0
Global equity securities		0		0
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	[3]	0		0
Total assets	[3]	6		2
Total liabilities	[3]	(51)		(52)
Other Investments	[3]			0
Netting [Member] | Nuclear Decommissioning Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	[3]	0		0
Total assets		0	[1]	0	[2],[3]
Fixed-income securities	[3]	0		0
Global equity securities	[3]	0		0
Netting [Member] | Price Risk Management Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[3]	6		2
Electricity	[3]	6		2
Natural Gas	[3]	0		0
Electricity	[3]	(51)		(52)
Natural Gas	[3]	0		0
Netting [Member] | Rabbi Trusts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	[3]	0		0
Fixed-income securities	[3]	0		0
Life insurance contracts	[3]	0		0
Netting [Member] | Long-Term Disability Trust [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	[3]	0		0
Total assets	[3]	0		0
Fixed-income securities	[3]	0		0
Global equity securities	[3]	$ 0		$ 0
[1]	Represents amount before deducting $350 million, primarily related to deferred taxes on appreciation of investment value.
[2]	Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
[3]	Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

Fair Value Measurements (Level

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Details) - Fair Value, Measurements, Fair Value Hierarchy [Domain] $ in Millions		6 Months Ended	12 Months Ended
		Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		$ 3,452	$ 3,399
Liabilities, Fair Value		(166)	(166)
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value		212	232
Liabilities, Fair Value		$ 62	$ 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		$ 102	$ 100
Fair value measurement Valuation technique		Discounted cash flow	Discounted cash flow
Fair value measurement Unobservable Input		Forward prices	Forward prices
Minimum [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	(47.09)	(15.97)
Minimum [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	22.04	16.04
Maximum [Member] | Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	8.17	8.17
Maximum [Member] | Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range	[1]	57	56.21
[1]	Represents price per megawatt-hour

Fair Value Measurements (Leve44

Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value Measurements, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning asset (liability) balance		$ 42	$ (22)	$ 69	$ (30)
Included in regulatory assets and liabilities or balancing accounts	[1]	6	11	(21)	19
Ending asset (liability) balance		$ 48	$ (11)	$ 48	$ (11)
[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	Jun. 30, 2015	Dec. 31, 2014
Fair Value Measurements, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 351	$ 352
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	350	350
Pacific Gas And Electric Company [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	15,715	15,851
Pacific Gas And Electric Company [Member] | Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument	$ 14,272	$ 13,778

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions		6 Months Ended		12 Months Ended
		Jun. 30, 2015		Dec. 31, 2014
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		$ 1,717	[1]	$ 1,601
Total Unrealized Gains		1,151	[1]	1,190
Total Unrealized Losses		(14)	[1]	(13)
Total Fair Value		2,854	[1]	2,778
Amount primarily related to deferred taxes on appreciation of investment value		350		324
Money Market Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		32		17
Total Unrealized Gains		0		0
Total Unrealized Losses		0		0
Total Fair Value		32		17
Other Investments [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost				5
Total Unrealized Gains				28
Total Unrealized Losses				0
Total Fair Value				33
Other Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		1,169		1,059
Total Unrealized Gains		60		75
Total Unrealized Losses		(7)		(4)
Total Fair Value		1,222		1,130
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
Global equity securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost		516		520
Total Unrealized Gains		1,091		1,087
Total Unrealized Losses		(7)		(9)
Total Fair Value		$ 1,600		$ 1,598
[1]	Represents amounts before deducting $350 million and $324 million at June 30, 2015 and December 31, 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

Fair Value Measurements (Sche47

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions	Jun. 30, 2015USD ($)
Less than 1 year	$ 19
1-5 years	458
5-10 years	277
More than 10 years	468
Total maturities of debt securities	$ 1,222

Fair Value Measurements (Sche48

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - Entity [Domain] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 362	$ 347	$ 779	$ 877
Gross realized gains on sales of securities held as available-for-sale	12	28	47	84
Gross realized losses on sales of securities held as available-for-sale	$ (10)	$ (2)	$ (13)	$ (3)

Commitments And Contingencies49

Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)
Long-term Purchase Commitment [Line Items]
Total	$ 465	$ 53,300
Maximum [Member]
Long-term Purchase Commitment [Line Items]
Long-term agreements range, years	25

Commitments And Contingencies50

Commitments And Contingencies (Impact Of Penalty Decision) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended			12 Months Ended
		Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015		Jun. 30, 2014	Dec. 31, 2014
Impact Of Penalty Decision [Line Items]
Fine payable to the state			$ 100	$ 100	[1]		$ 200
Customer bill credit				400
Disallowed capital expenditures		$ 74		128		$ 0
Disallowed revenue for pipeline safety expenses	[2]			0
CPUC estimated cost of other remedies	[3]			0
Total Penalty Decision fines and remedies recorded				628
Total Penalty Decision [Member]
Impact Of Penalty Decision [Line Items]
Fine payable to the state	[1]			300
Customer bill credit				400
Disallowed capital expenditures				688.5
Disallowed revenue for pipeline safety expenses	[2]			161
CPUC estimated cost of other remedies	[3]			50
Total Penalty Decision fines and remedies recorded				1,600
Penalty Decision Cumulative Charges [Member]
Impact Of Penalty Decision [Line Items]
Fine payable to the state	[1]			300
Customer bill credit				400
Disallowed capital expenditures	[4]			128
Disallowed revenue for pipeline safety expenses	[2]			0
CPUC estimated cost of other remedies	[3]			20
Total Penalty Decision fines and remedies recorded				848
Penalty Decision Anticipated Future Financial Impact [Member]
Impact Of Penalty Decision [Line Items]
Fine payable to the state	[1]			0
Customer bill credit				0
Disallowed capital expenditures	[4]			561
Disallowed revenue for pipeline safety expenses	[2]			161
CPUC estimated cost of other remedies	[3]			30
Total Penalty Decision fines and remedies recorded				752
Remedy Related Capital Costs [Member]
Impact Of Penalty Decision [Line Items]
Disallowed capital expenditures		$ 1
Pacific Gas And Electric Company [Member]
Impact Of Penalty Decision [Line Items]
Disallowed capital expenditures				$ 128		$ 0
[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]	In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.
[4]	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 $75 million and $128 million of capital spending (which include less than $1 million for remedy related capital costs) in the three months and six months ended June 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

Commitments And Contingencies51

Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands		3 Months Ended	6 Months Ended		12 Months Ended
		Mar. 31, 2015USD ($)	Jun. 30, 2015USD ($)		Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Accrued legal liabilities			$ 43,000		$ 55,000
Unrecognized Tax Benefits			370,000
Amount of capitalized PSEP costs included in Property, Plant, and Equipment			645,000
Payment To State General Fund		$ 100,000	100,000	[1]	200,000
Bill Credit to Natural Gas Customers			400,000
CPUC Remedial Measures	[2]		0
CPUC Disallowed Future Spending			850,000
Disallowed revenue for pipeline safety expenses	[3]		0
Total Penalty Decision fines and remedies recorded			628,000
Penalty Decision Cumulative Charges [Member]
Loss Contingencies [Line Items]
Payment To State General Fund	[1]		300,000
Bill Credit to Natural Gas Customers			400,000
CPUC Remedial Measures	[2]		20,000
Disallowed revenue for pipeline safety expenses	[3]		0
Total Penalty Decision fines and remedies recorded			848,000
Penalty Decision Anticipated Future Financial Impact [Member]
Loss Contingencies [Line Items]
Payment To State General Fund	[1]		0
Bill Credit to Natural Gas Customers			0
CPUC Remedial Measures	[2]		30,000
Disallowed revenue for pipeline safety expenses	[3]		161,000
Total Penalty Decision fines and remedies recorded			$ 752,000
Pacific Gas And Electric Company [Member] | Criminal investigation [Member] | Original Indictment [Member]
Loss Contingencies [Line Items]
Number of felony counts			12
Pacific Gas And Electric Company [Member] | Criminal investigation [Member] | Superceding Indictment [Member]
Loss Contingencies [Line Items]
Statutory penalty for each count of alleged violation			$ 500
Total maximum statutory penalties			$ 14,000
Number of felony counts			15
Gross Gain Derived From Alleged Violation			$ 281,000
Gross Loss Derived From Alleged Violation			565,000
Maximum Alternative Fine Sought			$ 1,130,000
Pacific Gas And Electric Company [Member] | Criminal investigation [Member] | Alleged obstruction of NTSB's investigation [Member]
Loss Contingencies [Line Items]
Number of felony counts			1
Pacific Gas And Electric Company [Member] | Minimum [Member]
Loss Contingencies [Line Items]
SED fines for self-reported violations			$ 50
Pacific Gas And Electric Company [Member] | Maximum [Member]
Loss Contingencies [Line Items]
SED fines for self-reported violations			16,800
Pacific Gas And Electric Company [Member] | CAISO And PX [Member]
Loss Contingencies [Line Items]
Disputed Claims Liability Balance					434,000
Other Receivables Disputed Claims					$ 291,000
Pacific Gas And Electric Company [Member] | Ex Parte Communications [Member]
Loss Contingencies [Line Items]
CPUC Imposed Fine			$ 1,050
[1]	In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.
[2]	In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.
[3]	These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

Commitments And Contingencies52

Commitments And Contingencies (Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Topock natural gas compressor station	[1]	$ 297	$ 291
Hinkley natural gas compressor station	[1]	149	158
Former manufactured gas plant sites owned by the Utility or third parties		263	257
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		153	150
Fossil fuel-fired generation facilities and sites		96	98
Total environmental remediation liability		$ 958	$ 954
[1]	See "Natural Gas Compressor Station Sites" below.

Commitments And Contingencies53

Commitments And Contingencies (Environmental Remediation Contingencies) (Details) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 676
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute	$ 1,800
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Remediation cost recovery	90.00%

Uncategorized Items - pcg-20150

Label	Element	Value
Profit Loss	us-gaap_ProfitLoss	$ 271
Profit Loss	us-gaap_ProfitLoss	406
Pacific Gas And Electric Company [Member]
Profit Loss	us-gaap_ProfitLoss	250
Profit Loss	us-gaap_ProfitLoss	$ 406