Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 20, 2015 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Trading Symbol | PCG | |
Entity Registrant Name | PG&E CORP | |
Entity Central Index Key | 1,004,980 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 490,453,856 | |
Pacific Gas And Electric Company [Member] | ||
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Trading Symbol | PCG | |
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | |
Entity Central Index Key | 75,488 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 264,374,809 |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Operating Revenues | ||||
Electric | $ 3,868 | $ 4,012 | $ 10,344 | $ 10,246 |
Natural gas | 682 | 927 | 2,322 | 2,536 |
Total operating revenues | 4,550 | 4,939 | 12,666 | 12,782 |
Operating Expenses | ||||
Cost of electricity | 1,681 | 1,782 | 3,958 | 4,341 |
Cost of natural gas | 50 | 134 | 442 | 694 |
Operating and maintenance | 1,621 | 1,287 | 5,028 | 3,914 |
Depreciation, amortization, and decommissioning | 653 | 671 | 1,935 | 1,766 |
Total operating expenses | 4,005 | 3,874 | 11,363 | 10,715 |
Operating Income | 545 | 1,065 | 1,303 | 2,067 |
Interest income | 2 | 2 | 6 | 7 |
Interest expense | (194) | (174) | (575) | (547) |
Other income, net | 24 | 36 | 100 | 98 |
Income Before Income Taxes | 377 | 929 | 834 | 1,625 |
Income tax provision | 67 | 115 | 84 | 310 |
Net Income | 310 | 814 | 750 | 1,315 |
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 |
Income Available for Common Shareholders | $ 307 | $ 811 | $ 740 | $ 1,305 |
Weighted Average Common Shares Outstanding, Basic | 486 | 472 | 481 | 466 |
Weighted Average Common Shares Outstanding, Diluted | 489 | 474 | 484 | 468 |
Net Earnings Per Common Share, Basic | $ 0.63 | $ 1.72 | $ 1.54 | $ 2.80 |
Net Earnings Per Common Share, Diluted | 0.63 | 1.71 | 1.53 | 2.79 |
Dividends Declared Per Common Share | $ 0.46 | $ 0.46 | $ 1.37 | $ 1.37 |
Pacific Gas And Electric Company [Member] | ||||
Operating Revenues | ||||
Electric | $ 3,868 | $ 4,012 | $ 10,344 | $ 10,244 |
Natural gas | 682 | 927 | 2,322 | 2,536 |
Total operating revenues | 4,550 | 4,939 | 12,666 | 12,780 |
Operating Expenses | ||||
Cost of electricity | 1,681 | 1,782 | 3,958 | 4,341 |
Cost of natural gas | 50 | 134 | 442 | 694 |
Operating and maintenance | 1,622 | 1,293 | 5,028 | 3,911 |
Depreciation, amortization, and decommissioning | 653 | 671 | 1,935 | 1,765 |
Total operating expenses | 4,006 | 3,880 | 11,363 | 10,711 |
Operating Income | 544 | 1,059 | 1,303 | 2,069 |
Interest income | 2 | 1 | 6 | 6 |
Interest expense | (191) | (171) | (567) | (535) |
Other income, net | 22 | 19 | 68 | 56 |
Income Before Income Taxes | 377 | 908 | 810 | 1,596 |
Income tax provision | 72 | 115 | 95 | 325 |
Net Income | 305 | 793 | 715 | 1,271 |
Preferred stock dividend requirement | 3 | 3 | 10 | 10 |
Income Available for Common Shareholders | $ 302 | $ 790 | $ 705 | $ 1,261 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Net income | $ 310 | $ 814 | $ 750 | $ 1,315 |
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, $13, $12 and $16 at respective dates) | 0 | (18) | (17) | (24) |
Total other comprehensive income (loss) | 0 | (18) | (17) | (24) |
Comprehensive Income | 310 | 796 | 733 | 1,291 |
Preferred stock dividend requirement of subsidiary | (3) | (3) | (10) | (10) |
Comprehensive Income Attributable to Common Shareholders | 307 | 793 | 723 | 1,281 |
Pacific Gas And Electric Company [Member] | ||||
Net income | 305 | 793 | 715 | 1,271 |
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 | $ 305 | $ 793 | $ 715 | $ 1,271 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Net change in investments tax | 0 | 13 | 12 | 16 |
Pacific Gas And Electric Company [Member] | ||||
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current Assets | ||
Cash and cash equivalents | $ 154 | $ 151 |
Restricted cash | 287 | 298 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $57 and $66 at respective dates) | 1,194 | 960 |
Accrued unbilled revenue | 907 | 776 |
Regulatory balancing accounts | 1,857 | 2,266 |
Other | 303 | 377 |
Regulatory assets | 475 | 444 |
Inventories | ||
Gas stored underground and fuel oil | 149 | 172 |
Materials and supplies | 322 | 304 |
Income taxes receivable | 156 | 198 |
Other | 327 | 443 |
Total current assets | 6,131 | 6,389 |
Property, Plant, and Equipment | ||
Electric | 47,141 | 45,162 |
Gas | 16,419 | 15,678 |
Construction work in progress | 2,259 | 2,220 |
Other | 2 | 2 |
Total property, plant, and equipment | 65,821 | 63,062 |
Accumulated depreciation | (20,174) | (19,121) |
Net property, plant, and equipment | 45,647 | 43,941 |
Other Noncurrent Assets | ||
Regulatory assets | 6,584 | 6,322 |
Nuclear decommissioning trusts | 2,417 | 2,421 |
Income taxes receivable | 97 | 91 |
Other | 1,113 | 963 |
Total other noncurrent assets | 10,211 | 9,797 |
TOTAL ASSETS | 61,989 | 60,127 |
Current Liabilities | ||
Short-term borrowings | 881 | 633 |
Accounts payable | ||
Trade creditors | 1,286 | 1,244 |
Regulatory balancing accounts | 803 | 1,090 |
Other | 435 | 476 |
Disputed claims and customer refunds | 452 | 434 |
Interest payable | 140 | 197 |
Other | 2,111 | 1,846 |
Total current liabilities | 6,108 | 5,920 |
Noncurrent Liabilities | ||
Long-term debt | 15,545 | 15,050 |
Regulatory liabilities | 6,294 | 6,290 |
Pension and other postretirement benefits | 2,523 | 2,561 |
Asset retirement obligations | 3,620 | 3,575 |
Deferred income taxes | 8,773 | 8,513 |
Other | 2,306 | 2,218 |
Total noncurrent liabilities | $ 39,061 | $ 38,207 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Common stock | $ 11,183 | $ 10,421 |
Reinvested earnings | 5,391 | 5,316 |
Accumulated other comprehensive income (loss) | (6) | 11 |
Total shareholders' equity | 16,568 | 15,748 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 16,820 | 16,000 |
TOTAL LIABILITIES AND EQUITY | 61,989 | 60,127 |
Pacific Gas And Electric Company [Member] | ||
Current Assets | ||
Cash and cash equivalents | 62 | 55 |
Restricted cash | 287 | 298 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $57 and $66 at respective dates) | 1,194 | 960 |
Accrued unbilled revenue | 907 | 776 |
Regulatory balancing accounts | 1,857 | 2,266 |
Other | 300 | 375 |
Regulatory assets | 475 | 444 |
Inventories | ||
Gas stored underground and fuel oil | 149 | 172 |
Materials and supplies | 322 | 304 |
Income taxes receivable | 154 | 168 |
Other | 327 | 409 |
Total current assets | 6,034 | 6,227 |
Property, Plant, and Equipment | ||
Electric | 47,141 | 45,162 |
Gas | 16,419 | 15,678 |
Construction work in progress | 2,259 | 2,220 |
Total property, plant, and equipment | 65,819 | 63,060 |
Accumulated depreciation | (20,173) | (19,120) |
Net property, plant, and equipment | 45,646 | 43,940 |
Other Noncurrent Assets | ||
Regulatory assets | 6,584 | 6,322 |
Nuclear decommissioning trusts | 2,417 | 2,421 |
Income taxes receivable | 97 | 91 |
Other | 1,006 | 864 |
Total other noncurrent assets | 10,104 | 9,698 |
TOTAL ASSETS | 61,784 | 59,865 |
Current Liabilities | ||
Short-term borrowings | 881 | 633 |
Accounts payable | ||
Trade creditors | 1,286 | 1,243 |
Regulatory balancing accounts | 803 | 1,090 |
Other | 455 | 444 |
Disputed claims and customer refunds | 452 | 434 |
Interest payable | 139 | 195 |
Other | 1,932 | 1,604 |
Total current liabilities | 5,948 | 5,643 |
Noncurrent Liabilities | ||
Long-term debt | 15,195 | 14,700 |
Regulatory liabilities | 6,294 | 6,290 |
Pension and other postretirement benefits | 2,435 | 2,477 |
Asset retirement obligations | 3,620 | 3,575 |
Deferred income taxes | 9,018 | 8,773 |
Other | 2,264 | 2,178 |
Total noncurrent liabilities | $ 38,826 | $ 37,993 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Preferred stock | $ 258 | $ 258 |
Common stock | 1,322 | 1,322 |
Additional paid-in capital | 7,127 | 6,514 |
Reinvested earnings | 8,298 | 8,130 |
Accumulated other comprehensive income (loss) | 5 | 5 |
Total shareholders' equity | 17,010 | 16,229 |
TOTAL LIABILITIES AND EQUITY | $ 61,784 | $ 59,865 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Allowance for doubtful accounts | $ 57 | $ 66 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 490,177,833 | 475,913,404 |
Pacific Gas And Electric Company [Member] | ||
Allowance for doubtful accounts | $ 57 | $ 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 | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash Flows from Operating Activities | ||
Net income | $ 750 | $ 1,315 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 1,935 | 1,766 |
Allowance for equity funds used during construction | (80) | (72) |
Deferred income taxes and tax credits, net | 260 | 209 |
Disallowed capital expenditures | 270 | 0 |
Other | 247 | 258 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | (322) | (177) |
Inventories | 5 | (43) |
Accounts payable | 95 | (57) |
Income taxes receivable/payable | 42 | 397 |
Other current assets and liabilities | (87) | 358 |
Regulatory assets, liabilities, and balancing accounts, net | 78 | (994) |
Other noncurrent assets and liabilities | (251) | (3) |
Net cash provided by operating activities | 2,942 | 2,957 |
Cash Flows from Investing Activities | ||
Capital expenditures | (3,662) | (3,564) |
Decrease in restricted cash | 11 | 2 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,023 | 1,059 |
Purchases of nuclear decommissioning trust investments | (1,124) | (1,065) |
Other | 18 | 107 |
Net cash used in investing activities | (3,734) | (3,461) |
Cash Flows from Financing Activities | ||
Repayments under revolving credit facilities | 0 | (260) |
Net issuances (repayments) of commercial paper, net of discount of $2 and $1 at respective dates | 545 | (789) |
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 and $6, at respective dates, for PG&E Corporation and $14 and $3, at respective dates, for the Utility | 486 | 1,819 |
Repayments of long-term debt | 0 | (889) |
Common stock issued | 689 | 743 |
Common stock dividends paid | (638) | (617) |
Other | 13 | 40 |
Net cash provided by financing activities | 795 | 347 |
Net change in cash and cash equivalents | 3 | (157) |
Cash and cash equivalents at January 1 | 151 | 296 |
Cash and cash equivalents at September 30 | 154 | 139 |
Cash received (paid) for: | ||
Interest, net of amounts capitalized | (569) | (516) |
Income taxes, net | 0 | 409 |
Supplemental disclosures of noncash investing and financing activities | ||
Common stock dividends declared but not yet paid | 223 | 216 |
Capital expenditures financed through accounts payable | 245 | 232 |
Noncash common stock issuances | 15 | 16 |
Terminated capital leases | 0 | 71 |
Pacific Gas And Electric Company [Member] | ||
Cash Flows from Operating Activities | ||
Net income | 715 | 1,271 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 1,935 | 1,765 |
Allowance for equity funds used during construction | (80) | (72) |
Deferred income taxes and tax credits, net | 245 | 173 |
Disallowed capital expenditures | 270 | 0 |
Other | 200 | 212 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | (321) | (174) |
Inventories | 5 | (43) |
Accounts payable | 148 | (3) |
Income taxes receivable/payable | 14 | 407 |
Other current assets and liabilities | (45) | 366 |
Regulatory assets, liabilities, and balancing accounts, net | 78 | (994) |
Other noncurrent assets and liabilities | (232) | 6 |
Net cash provided by operating activities | 2,932 | 2,914 |
Cash Flows from Investing Activities | ||
Capital expenditures | (3,662) | (3,564) |
Decrease in restricted cash | 11 | 2 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,023 | 1,059 |
Purchases of nuclear decommissioning trust investments | (1,124) | (1,065) |
Other | 18 | 22 |
Net cash used in investing activities | (3,734) | (3,546) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $2 and $1 at respective dates | 545 | (789) |
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 and $6, at respective dates, for PG&E Corporation and $14 and $3, at respective dates, for the Utility | 486 | 1,472 |
Repayments of long-term debt | 0 | (539) |
Preferred stock dividends paid | (10) | (10) |
Common stock dividends paid | (537) | (537) |
Equity contribution from PG&E Corporation | 605 | 705 |
Other | 20 | 50 |
Net cash provided by financing activities | 809 | 652 |
Net change in cash and cash equivalents | 7 | 20 |
Cash and cash equivalents at January 1 | 55 | 65 |
Cash and cash equivalents at September 30 | 62 | 85 |
Cash received (paid) for: | ||
Interest, net of amounts capitalized | (561) | (500) |
Income taxes, net | 0 | 408 |
Supplemental disclosures of noncash investing and financing activities | ||
Capital expenditures financed through accounts payable | 245 | 232 |
Terminated capital leases | $ 0 | $ 71 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Discount on net issuances of commercial paper | $ 2 | $ 1 |
Premium, discount, and issuance costs on proceeds from long-term debt | 14 | 6 |
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 | $ 3 |
Organization And Basis Of Prese
Organization And Basis Of Presentation | 9 Months Ended |
Sep. 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 in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. A decision was issued in each investigative proceeding to determine the violations that the Utility committed. The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion c omprised of: (1) a $300 million fine paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. The Penalty Decision requires that at least $ 689 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 expenses. (See Note 9 below.) This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility 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 Utility’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 Balance 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 amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, 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 appropriate and reasonable. Actual results could differ materially from those estimates. |
New And Significant Accounting
New And Significant Accounting Policies | 9 Months Ended |
Sep. 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 enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at September 30, 2015 , it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 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. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2015 and 2014 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 123 $ 92 $ 14 $ 12 Interest cost 168 175 18 19 Expected return on plan assets (219) (202) (28) (25) Amortization of prior service cost 4 5 4 6 Amortization of net actuarial loss 1 1 1 1 Net periodic benefit cost 77 71 9 13 Regulatory account transfer (1) 8 13 - - Total $ 85 $ 84 $ 9 $ 13 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 360 $ 287 $ 41 $ 34 Interest cost 505 521 54 57 Expected return on plan assets (655) (605) (84) (77) Amortization of prior service cost 11 15 14 17 Amortization of net actuarial loss 7 2 3 2 Net periodic benefit cost 228 220 28 33 Regulatory account transfer (1) 26 31 - - Total $ 254 $ 251 $ 28 $ 33 (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 changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 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) 3 2 5 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (4) (3) (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 September 30, 2014 Beginning balance $ (7) $ 15 $ 36 $ 44 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - (4) (4) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $3, and $0, respectively) (1) 3 3 - 6 Regulatory account transfer (net of taxes of $3, $4, and $0, respectively) (1) (3) (3) - (6) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (14) (14) Net current period other comprehensive loss - - (18) (18) Ending balance $ (7) $ 15 $ 18 $ 26 (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) Nine Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $6, and $0, respectively) (1) 7 8 - 15 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 4 2 - 6 Regulatory account transfer (net of taxes of $7, $7, and $0, respectively) (1) (11) (10) - (21) 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) Nine Months Ended September 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $4, respectively) - - 6 6 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $6, $7, and $0, respectively) (1) 9 10 - 19 Amortization of net actuarial loss (net of taxes of $1, $1, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $7, $8, and $0, respectively) (1) (10) (11) - (21) Change in investments (net of taxes of $0, $0, and $20, respectively) - - (30) (30) Net current period other comprehensive loss - - (24) (24) Ending balance $ (7) $ 15 $ 18 $ 26 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above, 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 ASU will be effective for fiscal years beginning after December 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 treatment for cloud computing arrangements. The ASU 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 related 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 Debt Issuance Costs , which amends existing presentation of debt issuance costs. PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other. The amendments in this ASU, 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 Corporation 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 August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date , deferring 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 evaluating the impact the guidance will have on their consolidated financial statements and related disclosures. |
Regulatory Assets, Liabilities,
Regulatory Assets, Liabilities, And Balancing Accounts | 9 Months Ended |
Sep. 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 September 30, December 31, (in millions) 2015 2014 Pension benefits $ 2,304 $ 2,347 Deferred income taxes 2,771 2,390 Environmental compliance costs 705 717 Utility retained generation 423 456 Price risk management 143 127 Unamortized loss, net of gain, on reacquired debt 98 113 Electromechanical meters 18 70 Other 122 102 Total long-term regulatory assets $ 6,584 $ 6,322 Regulatory Liabilities Long-term regulatory liabilities are composed of the following: Balance at September 30, December 31, (in millions) 2015 2014 Cost of removal obligations $ 4,509 $ 4,211 Recoveries in excess of asset retirement obligations 610 754 Public purpose programs 701 701 Other 474 624 Total long-term regulatory liabilities $ 6,294 $ 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 balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the 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 regulatory balancing accounts receivable and payable are composed of the following: Receivable Balance at September 30, December 31, (in millions) 2015 2014 Electric distribution $ 265 $ 344 Utility generation 24 261 Gas distribution 718 566 Energy procurement 390 608 Public purpose programs 136 109 Other 324 378 Total regulatory balancing accounts receivable $ 1,857 $ 2,266 Payable Balance at September 30, December 31, (in millions) 2015 2014 Energy procurement $ 181 $ 188 Public purpose programs 173 154 Other 449 748 Total regulatory balancing accounts payable $ 803 $ 1,090 |
Debt
Debt | 9 Months Ended |
Sep. 30, 2015 | |
Debt | NOTE 4: DEBT Revolving Credit Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2015 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2020 $ 300 (1) $ - $ - $ 300 Utility April 2020 3,000 (2) 34 881 2,085 Total revolving credit facilities $ 3,300 $ 34 $ 881 $ 2,385 (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. On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities. The amendments and restatements extended the 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. 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 reduction to the amount available under their respective revolving credit facilities. 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 September 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 were 0.01%. At September 30, 2015 , the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements were 0.01%. |
Equity
Equity | 9 Months Ended |
Sep. 30, 2015 | |
Equity | NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 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 733 715 Equity contributions - 605 Common stock issued 704 - Share-based compensation 58 8 Common stock dividends declared (665) (537) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2015 $ 16,820 $ 17,010 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 additional shares have been sold under the equity distribution agreement. In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offering for cash proceeds of $352 million, net of fees. PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2015 , 6.1 million shares were issued for cash proceeds of $ 263 million under these plans. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 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 Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2015 2014 2015 2014 Income available for common shareholders $ 307 $ 811 $ 740 $ 1,305 Weighted average common shares outstanding, basic 486 472 481 466 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 3 2 Weighted average common share outstanding, diluted 489 474 484 468 Total earnings per common share, diluted $ 0.63 $ 1.71 $ 1.53 $ 2.79 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive. |
Derivatives
Derivatives | 9 Months Ended |
Sep. 30, 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 instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives as long as the current ratemaking mechanism remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at September 30, December 31, Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 276,847,153 308,130,101 Options 134,380,439 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 4,884,523 5,346,787 Congestion Revenue Rights (3) 186,018,832 224,124,341 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. Presentation of Derivative Instruments in the Financial Statements At September 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 $ 63 $ (2) $ 11 $ 72 Other noncurrent assets – other 130 (2) - 128 Current liabilities – other (84) 2 34 (48) Noncurrent liabilities – other (145) 2 24 (119) Net commodity risk $ (36) $ - $ 69 $ 33 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 Nine Months Ended September 30, September 30, (in millions) 2015 2014 2015 2014 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (45) $ (6) $ (69) $ 79 Realized gain (loss) - cost of electricity (2) 1 (22) 4 (48) Realized loss - cost of natural gas (2) (3) (4) (8) (7) Net commodity risk $ (47) $ (32) $ (73) $ 24 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At September 30, 2015 , the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows: Balance at September 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 | 9 Months Ended |
Sep. 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 fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Other inputs that are directly or indirectly observable in the marketplace. Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (assets held in rabbi trusts and other investments are held by PG&E Corporation and not the Utility): Fair Value Measurements At September 30, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 92 $ - $ - $ - $ 92 Nuclear decommissioning trusts Money market investments 21 - - - 21 Global equity securities 1,445 12 - - 1,457 Fixed-income securities 710 523 - - 1,233 Total nuclear decommissioning trusts (2) 2,176 535 - - 2,711 Price risk management instruments (Note 7) Electricity - 4 185 7 196 Gas - 4 - - 4 Total price risk management instruments - 8 185 7 200 Rabbi trusts Fixed-income securities - 45 - - 45 Life insurance contracts - 71 - - 71 Total rabbi trusts - 116 - - 116 Long-term disability trust Money market investments 7 - - - 7 Global equity securities - 18 - - 18 Fixed-income securities - 106 - - 106 Total long-term disability trust 7 124 - - 131 Total assets $ 2,275 $ 783 $ 185 $ 7 $ 3,250 Liabilities: Price risk management instruments (Note 7) Electricity $ 60 $ 3 $ 164 $ (62) $ 165 Gas - 2 - - 2 Total liabilities $ 60 $ 5 $ 164 $ (62) $ 167 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 294 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2014 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 94 $ - $ - $ - $ 94 Nuclear decommissioning trusts Money market investments 17 - - - 17 Global equity securities 1,585 13 - - 1,598 Fixed-income securities 741 389 - - 1,130 Total nuclear decommissioning trusts (2) 2,343 402 - - 2,745 Price risk management instruments (Note 9 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 utilize investment strategies aimed at matching the performance of indexed funds. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the nine months ended September 30, 2015 and 2014 . Trust Assets Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes are readily observable and available. Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of 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 data 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 functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.) Fair Value at (in millions) At September 30, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 185 $ 51 Market approach CRR auction prices $ (15.97) - 8.17 Power purchase agreements $ - $ 113 Discounted cash flow Forward prices $ 17.64 - 38.80 (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 purchase 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 nine months ended September 30, 2015 and 2014 : Price Risk Management Instruments (in millions) 2015 2014 Asset (liability) balance as of July 1 $ 48 $ (11) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (27) (9) Asset (liability) balance as of September 30 $ 21 $ (20) (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) (48) 10 Asset (liability) balance as of September 30 $ 21 $ (20) (1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets. Financial Instruments PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2015 and December 31, 2014 , as they are short-term in nature or have interest rates that reset daily. The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at September 30, 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 values that approximate their fair values): At September 30, 2015 At December 31, 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 354 $ 350 $ 352 Utility 14,273 15,858 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 September 30, 2015 Nuclear decommissioning trusts Money market investments $ 21 $ - $ - $ 21 Global equity securities 510 963 (16) 1,457 Fixed-income securities 1,168 70 (5) 1,233 Total (1) $ 1,699 $ 1,033 $ (21) $ 2,711 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 $ 294 million and $324 million at September 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) September 30, 2015 Less than 1 year $ 21 1–5 years 465 5–10 years 290 More than 10 years 457 Total maturities of debt securities $ 1,233 The following table provides a summary of activity for the debt and equity securities: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 244 $ 182 $ 1,023 $ 1,059 Gross realized gains on securities held as available-for-sale 3 30 50 114 Gross realized losses on securities held as available-for-sale (12) - (25) (3) |
Commitments And Contingencies
Commitments And Contingencies | 9 Months Ended |
Sep. 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 commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters. Enforcement and Litigation Matters CPUC Matters Improper CPUC Communications 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. 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. In November 2014, the CPUC imposed a fine of $1.05 million on the Utility for these communications. In addition, the CPUC may disallow 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-month period. The CPUC will determine the amount of this disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements, which is expected to be issued in 2016. 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. 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. Additionally, 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. 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 penalties. 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. 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 that 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 determining the final penalties. 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 . CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014, for which the CPUC has previously imposed a penalty of $10.85 million. On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. Testimony from intervenors was submitted in October 2015. The Utility’s response is due on November 12, 2015, followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016. The CPUC can impose penalties of up to $50,000 per day, per violation, for violations that occurred after January 1, 2012. (The statutory maximum penalty for violations that occurred before January 1, 2012 is $20,000 per violation.) The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this wide discretion in determining penalties. PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or that the Utility will incur unrecoverable costs 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 (discussed above) 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. Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility’s failure to continuously survey its system and remove encroachments. 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 Citations The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. Although the SED can consider the discretionary factors discussed above (see “ CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping” above) in determining the number of violations and whether to impose fines, the SED is required to impose the maximum statutory penalty of $50,000 for each separate violation and has the discretion to impose daily fines for continuing violations . The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines. 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 Utility 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 Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also 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 superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternative fine would be approximately $1.13 billion. The trial is scheduled to begin March 8, 2016. The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment. The Utility has filed several motions requesting that the court dismiss many of the counts based on various legal arguments. The court has heard oral argument on all the motions and the Utility is waiting for the court’s decisions. 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. 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). The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility . Capital Expenditures Relating to Pipeline Safety Enhancement Plan At September 30, 2015, approximately $ 657 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 total forecasted 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 CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine. At September 30, 2015, the Condensed Consolidated Balance Sheets include $400 million in current regulatory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016. The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base. The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case. If the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how the CPUC will identify the costs that are counted toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC. As a result, the total shareholder-funded obligation could exceed $850 million. For the three months and nine months ended September 30, 2015, the Utility recorded additional charges in operating and maintenance expenses in the Consolidated Statements of Income of $142 million and $770 million, respectively, as a result of the Penalty Decision. The cumulative charges at September 30, 2015, and the additional future charges to reach the $1.6 billion total are shown in the following table: Nine Months Cumulative Future Ended Charges Charges Total September 30, September 30, and (in millions) 2015 2015 Costs Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 270 270 419 689 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 $ 770 $ 990 $ 610 $ 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 $142 million and $270 million of capital spending (which include less than $1 million for remedy related capital costs)in the three months and nine months ended September 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 revenues will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additional remedy-related costs of approximately $ 61 million. The Utility could incur remedy-related costs that are higher than current estimates. Other Legal and Regulatory Contingencies Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards On September 17, 2015, the CPUC issued an order granting TURN’s and the ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California investor-owned utilities for the 2006-2008 energy efficiency program cycle. Under the ratemaking mechanism applicable to the 2006-2008 program cycle, the maximum amount of incentives that the Utility could have earned (or the maximum amount that the Utility could have been required to reimburse customers) over the 2006-2008 program cycle was $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle . In the re-opened energy efficiency proceeding, the CPUC will evaluate whether incentives awarded to the California investor-owned utilities were just and reasonable, and whether any refunds are due. It is uncertain when the CPUC will issue a decision and whether the Utility will be required to refund amounts or incur other obligations related to the 2006-2008 program cycle. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations. Investigation of the Butte Fire In September 2015, a wildfire (known as the “Butte Fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the fire including whether a live tree may have contacted a power line owned and operated by the Utility, in the vicinity of the ignition point. The Utility also is conducting an investigation. Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Although the cause of the fire has not yet been determined, PG&E Corporation and the Utility believe that it is reasonably possible that the Utility will incur a material amount of losses associated with third-party claims for property damage, fire suppression costs, personal injury, or other claims. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigation into the cause of the fire and uncertainty about the extent and value of real and personal property damaged by the fire which spread over 70,000 acres much of which is remote and rugged terrain. The Utility has insurance coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility’s liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected. Other Contingencies Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies” ) totaled $61 million at September 30, 2015, and $55 million at December 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 September 30, December 31, (in millions) 2015 2014 Topock natural gas compressor station (1) $ 296 $ 291 Hinkley natural gas compressor station (1) 136 158 Former manufactured gas plant sites owned by the Utility or third parties 267 257 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 94 98 Total environmental remediation liability $ 946 $ 954 (1) See “Natural Gas Compressor Station Sites” below. At September 30, 2015 , the Utility expected to recover $ 678 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility also is 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. On October 16, 2015, the Regional Board issued a revised draft clean-up and abatement order, updating previous versions of the draft order released in September 2015 and January 20 15. The updated draft order proposes that the Utility continue and improve its remediation efforts; defines the boundaries of the chromium plume, and take other action. The draft order also proposes to set plume capture requirements, proposes deadlines for the Utility to meet interim cleanup targets, and proposes to establish a monitoring and reporting program. After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order at its November 2015 meeting. The Utility’s environmental remediation liability at September 30, 2015 reflects the Utility’s best estimate of probable future costs associated with the continuation of interim remediation measures and the anticipated final clean-up and abatement order. 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 abatement 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 measures, 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 Utility’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 the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 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 September 30, 2015 reflects its best estimate of probable future costs associated with its anticipated 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 future that are materially different than this estimate and such costs could have a material impact on results of operations during the period in which they are recorded. Resolution of Remaining Chapter 11 Disputed Claims Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. 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 these balances during the nine months ended September 30, 2015 . Tax Matters The IRS is currently auditing several items in the 2011 to 2014 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 audit of the 2011 and 2012 deductible repair costs for the electric transmission and distribution businesses in 2015. The IRS also is expected to issue guidance in late 2015 or 2016 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the outstanding audits related to the 2011 and 2012 tax returns. As of September 30, 2015 , it is reasonably possible that unrecognized tax benefits will decrease by approximately $ 380 million within the next 12 months most of which would not impact net income. There were no other significant developments to tax matters during the nine months ended September 30, 2015 . (Refer to Note 8 of the Notes to the Consolidated Financial 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 2014 Form 10-K.) During the nine months ended September 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 additional commitments of approximately $780 million over the next 25 years. |
New And Significant Accountin18
New And Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 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 enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at September 30, 2015 , it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 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. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2015 and 2014 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 123 $ 92 $ 14 $ 12 Interest cost 168 175 18 19 Expected return on plan assets (219) (202) (28) (25) Amortization of prior service cost 4 5 4 6 Amortization of net actuarial loss 1 1 1 1 Net periodic benefit cost 77 71 9 13 Regulatory account transfer (1) 8 13 - - Total $ 85 $ 84 $ 9 $ 13 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 360 $ 287 $ 41 $ 34 Interest cost 505 521 54 57 Expected return on plan assets (655) (605) (84) (77) Amortization of prior service cost 11 15 14 17 Amortization of net actuarial loss 7 2 3 2 Net periodic benefit cost 228 220 28 33 Regulatory account transfer (1) 26 31 - - Total $ 254 $ 251 $ 28 $ 33 (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. |
Amounts Reclassified Out of Accumulated Other Comprehensive Income | Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 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) 3 2 5 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (4) (3) (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 September 30, 2014 Beginning balance $ (7) $ 15 $ 36 $ 44 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - (4) (4) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $3, and $0, respectively) (1) 3 3 - 6 Regulatory account transfer (net of taxes of $3, $4, and $0, respectively) (1) (3) (3) - (6) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (14) (14) Net current period other comprehensive loss - - (18) (18) Ending balance $ (7) $ 15 $ 18 $ 26 (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) Nine Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $6, and $0, respectively) (1) 7 8 - 15 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 4 2 - 6 Regulatory account transfer (net of taxes of $7, $7, and $0, respectively) (1) (11) (10) - (21) 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) Nine Months Ended September 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $4, respectively) - - 6 6 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $6, $7, and $0, respectively) (1) 9 10 - 19 Amortization of net actuarial loss (net of taxes of $1, $1, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $7, $8, and $0, respectively) (1) (10) (11) - (21) Change in investments (net of taxes of $0, $0, and $20, respectively) - - (30) (30) Net current period other comprehensive loss - - (24) (24) Ending balance $ (7) $ 15 $ 18 $ 26 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation. |
New And Significant Accountin19
New And Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Components Of Net Periodic Benefit Cost | Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 123 $ 92 $ 14 $ 12 Interest cost 168 175 18 19 Expected return on plan assets (219) (202) (28) (25) Amortization of prior service cost 4 5 4 6 Amortization of net actuarial loss 1 1 1 1 Net periodic benefit cost 77 71 9 13 Regulatory account transfer (1) 8 13 - - Total $ 85 $ 84 $ 9 $ 13 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2015 2014 2015 2014 Service cost for benefits earned $ 360 $ 287 $ 41 $ 34 Interest cost 505 521 54 57 Expected return on plan assets (655) (605) (84) (77) Amortization of prior service cost 11 15 14 17 Amortization of net actuarial loss 7 2 3 2 Net periodic benefit cost 228 220 28 33 Regulatory account transfer (1) 26 31 - - Total $ 254 $ 251 $ 28 $ 33 (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 September 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) 3 2 5 Amortization of net actuarial loss (net of taxes of $0 and $0, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (4) (3) (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 September 30, 2014 Beginning balance $ (7) $ 15 $ 36 $ 44 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $3, respectively) - - (4) (4) Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $3, and $0, respectively) (1) 3 3 - 6 Regulatory account transfer (net of taxes of $3, $4, and $0, respectively) (1) (3) (3) - (6) Change in investments (net of taxes of $0, $0, and $10, respectively) - - (14) (14) Net current period other comprehensive loss - - (18) (18) Ending balance $ (7) $ 15 $ 18 $ 26 (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) Nine Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $6, and $0, respectively) (1) 7 8 - 15 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 4 2 - 6 Regulatory account transfer (net of taxes of $7, $7, and $0, respectively) (1) (11) (10) - (21) 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) Nine Months Ended September 30, 2014 Beginning balance $ (7) $ 15 $ 42 $ 50 Other comprehensive income before reclassifications: Change in investments (net of taxes of $0, $0, and $4, respectively) - - 6 6 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $6, $7, and $0, respectively) (1) 9 10 - 19 Amortization of net actuarial loss (net of taxes of $1, $1, and $0, respectively) (1) 1 1 - 2 Regulatory account transfer (net of taxes of $7, $8, and $0, respectively) (1) (10) (11) - (21) Change in investments (net of taxes of $0, $0, and $20, respectively) - - (30) (30) Net current period other comprehensive loss - - (24) (24) Ending balance $ (7) $ 15 $ 18 $ 26 (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) | 9 Months Ended |
Sep. 30, 2015 | |
Long-Term Regulatory Assets | Balance at September 30, December 31, (in millions) 2015 2014 Pension benefits $ 2,304 $ 2,347 Deferred income taxes 2,771 2,390 Environmental compliance costs 705 717 Utility retained generation 423 456 Price risk management 143 127 Unamortized loss, net of gain, on reacquired debt 98 113 Electromechanical meters 18 70 Other 122 102 Total long-term regulatory assets $ 6,584 $ 6,322 |
Long-Term Regulatory Liabilities | Balance at September 30, December 31, (in millions) 2015 2014 Cost of removal obligations $ 4,509 $ 4,211 Recoveries in excess of asset retirement obligations 610 754 Public purpose programs 701 701 Other 474 624 Total long-term regulatory liabilities $ 6,294 $ 6,290 |
Regulatory Balancing Accounts Receivable | Receivable Balance at September 30, December 31, (in millions) 2015 2014 Electric distribution $ 265 $ 344 Utility generation 24 261 Gas distribution 718 566 Energy procurement 390 608 Public purpose programs 136 109 Other 324 378 Total regulatory balancing accounts receivable $ 1,857 $ 2,266 |
Regulatory Balancing Accounts Payable | Payable Balance at September 30, December 31, (in millions) 2015 2014 Energy procurement $ 181 $ 188 Public purpose programs 173 154 Other 449 748 Total regulatory balancing accounts payable $ 803 $ 1,090 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Disclosure Debt [Abstract] | |
Schedule of Line of Credit Facilities | Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2020 $ 300 (1) $ - $ - $ 300 Utility April 2020 3,000 (2) 34 881 2,085 Total revolving credit facilities $ 3,300 $ 34 $ 881 $ 2,385 (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) | 9 Months Ended |
Sep. 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 733 715 Equity contributions - 605 Common stock issued 704 - Share-based compensation 58 8 Common stock dividends declared (665) (537) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2015 $ 16,820 $ 17,010 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 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 Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2015 2014 2015 2014 Income available for common shareholders $ 307 $ 811 $ 740 $ 1,305 Weighted average common shares outstanding, basic 486 472 481 466 Add incremental shares from assumed conversions: Employee share-based compensation 3 2 3 2 Weighted average common share outstanding, diluted 489 474 484 468 Total earnings per common share, diluted $ 0.63 $ 1.71 $ 1.53 $ 2.79 |
Derivatives (Tables)
Derivatives (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Volumes Of Outstanding Derivative Contracts | Contract Volume at September 30, December 31, Underlying Product Instruments 2015 2014 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 276,847,153 308,130,101 Options 134,380,439 164,418,002 Electricity (Megawatt-hours) Forwards and Swaps 4,884,523 5,346,787 Congestion Revenue Rights (3) 186,018,832 224,124,341 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. (2) Million British Thermal Units. (3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | At September 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 $ 63 $ (2) $ 11 $ 72 Other noncurrent assets – other 130 (2) - 128 Current liabilities – other (84) 2 34 (48) Noncurrent liabilities – other (145) 2 24 (119) Net commodity risk $ (36) $ - $ 69 $ 33 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 Nine Months Ended September 30, September 30, (in millions) 2015 2014 2015 2014 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (45) $ (6) $ (69) $ 79 Realized gain (loss) - cost of electricity (2) 1 (22) 4 (48) Realized loss - cost of natural gas (2) (3) (4) (8) (7) Net commodity risk $ (47) $ (32) $ (73) $ 24 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered | Balance at September 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) | 9 Months Ended |
Sep. 30, 2015 | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | Fair Value Measurements At September 30, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 92 $ - $ - $ - $ 92 Nuclear decommissioning trusts Money market investments 21 - - - 21 Global equity securities 1,445 12 - - 1,457 Fixed-income securities 710 523 - - 1,233 Total nuclear decommissioning trusts (2) 2,176 535 - - 2,711 Price risk management instruments (Note 7) Electricity - 4 185 7 196 Gas - 4 - - 4 Total price risk management instruments - 8 185 7 200 Rabbi trusts Fixed-income securities - 45 - - 45 Life insurance contracts - 71 - - 71 Total rabbi trusts - 116 - - 116 Long-term disability trust Money market investments 7 - - - 7 Global equity securities - 18 - - 18 Fixed-income securities - 106 - - 106 Total long-term disability trust 7 124 - - 131 Total assets $ 2,275 $ 783 $ 185 $ 7 $ 3,250 Liabilities: Price risk management instruments (Note 7) Electricity $ 60 $ 3 $ 164 $ (62) $ 165 Gas - 2 - - 2 Total liabilities $ 60 $ 5 $ 164 $ (62) $ 167 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 294 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2014 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Money market investments $ 94 $ - $ - $ - $ 94 Nuclear decommissioning trusts Money market investments 17 - - - 17 Global equity securities 1,585 13 - - 1,598 Fixed-income securities 741 389 - - 1,130 Total nuclear decommissioning trusts (2) 2,343 402 - - 2,745 Price risk management instruments (Note 9 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 September 30, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 185 $ 51 Market approach CRR auction prices $ (15.97) - 8.17 Power purchase agreements $ - $ 113 Discounted cash flow Forward prices $ 17.64 - 38.80 (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 purchase agreements $ - $ 100 Discounted cash flow Forward prices $ 16.04 - 56.21 (1) Represents price per megawatt-hour |
Level 3 Reconciliation | Price Risk Management Instruments (in millions) 2015 2014 Asset (liability) balance as of July 1 $ 48 $ (11) Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (27) (9) Asset (liability) balance as of September 30 $ 21 $ (20) (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) (48) 10 Asset (liability) balance as of September 30 $ 21 $ (20) (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 September 30, 2015 At December 31, 2014 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 354 $ 350 $ 352 Utility 14,273 15,858 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 September 30, 2015 Nuclear decommissioning trusts Money market investments $ 21 $ - $ - $ 21 Global equity securities 510 963 (16) 1,457 Fixed-income securities 1,168 70 (5) 1,233 Total (1) $ 1,699 $ 1,033 $ (21) $ 2,711 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 $ 294 million and $324 million at September 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) September 30, 2015 Less than 1 year $ 21 1–5 years 465 5–10 years 290 More than 10 years 457 Total maturities of debt securities $ 1,233 |
Schedule Of Activity For Debt And Equity Securities | Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 244 $ 182 $ 1,023 $ 1,059 Gross realized gains on securities held as available-for-sale 3 30 50 114 Gross realized losses on securities held as available-for-sale (12) - (25) (3) |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Impact Of The Penalty Decision | Nine Months Cumulative Future Ended Charges Charges Total September 30, September 30, and (in millions) 2015 2015 Costs Amount Fine payable to the state (1) $ 100 $ 300 $ - $ 300 Customer bill credit 400 400 - 400 Charge for disallowed capital (2) 270 270 419 689 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 $ 770 $ 990 $ 610 $ 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 $142 million and $270 million of capital spending (which include less than $1 million for remedy related capital costs)in the three months and nine months ended September 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 revenues will be reduced for these unrecovered expenses. (4) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additional remedy-related costs of approximately $ 61 million. |
Schedule Of Environmental Remediation Liability | Balance at September 30, December 31, (in millions) 2015 2014 Topock natural gas compressor station (1) $ 296 $ 291 Hinkley natural gas compressor station (1) 136 158 Former manufactured gas plant sites owned by the Utility or third parties 267 257 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 94 98 Total environmental remediation liability $ 946 $ 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 | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |||
Organization And Basis Of Presentation [Line Items] | ||||||
Total Penalties Issued by CPUC | $ 770 | |||||
Fine payable to the state | 100 | [1] | $ 200 | |||
Bill Credit to Natural Gas Customers | 400 | |||||
Charge for disallowed capital | $ 141 | 270 | $ 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 | 689 | |||||
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 | $ 270 | $ 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 estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additional remedy-related costs of approximately $61 million. The Utility could incur remedy-related costs that are higher than current estimates. |
New And Significant Accountin28
New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost for benefits earned | $ 123 | $ 92 | $ 360 | $ 287 | |
Interest cost | 168 | 175 | 505 | 521 | |
Expected return on plan assets | (219) | (202) | (655) | (605) | |
Amortization of prior service cost | 4 | 5 | 11 | 15 | |
Amortization of net actuarial loss | 1 | 1 | 7 | 2 | |
Net periodic benefit cost | 77 | 71 | 228 | 220 | |
Less: transfer to regulatory account | [1] | 8 | 13 | 26 | 31 |
Total | 85 | 84 | 254 | 251 | |
Other Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost for benefits earned | 14 | 12 | 41 | 34 | |
Interest cost | 18 | 19 | 54 | 57 | |
Expected return on plan assets | (28) | (25) | (84) | (77) | |
Amortization of prior service cost | 4 | 6 | 14 | 17 | |
Amortization of net actuarial loss | 1 | 1 | 3 | 2 | |
Net periodic benefit cost | 9 | 13 | 28 | 33 | |
Less: transfer to regulatory account | [1] | 0 | 0 | 0 | 0 |
Total | $ 9 | $ 13 | $ 28 | $ 33 | |
[1] | The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in futures rates. |
New And Significant Accountin29
New And Significant Accounting Policies (Reclassifications Out Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | $ (6) | $ 44 | $ 11 | $ 50 | |
Change in investments | 0 | (18) | (17) | (24) | |
Net current period other comprehensive income (loss) | 0 | (18) | (17) | (24) | |
Ending balance | (6) | 26 | (6) | 26 | |
Net change in investments tax | 0 | 13 | 12 | 16 | |
Net actuarial loss tax | 0 | 0 | 0 | 0 | |
Other Comprehensive Income Before Reclassifications [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Change in investments | (4) | 6 | |||
Amounts Reclassified From Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Amortization of prior service cost | [1] | 5 | 6 | 15 | 19 |
Amortization of net actuarial loss | [1] | 2 | 6 | 2 | |
Regulatory account transfer | [1] | (7) | (6) | (21) | (21) |
Change in investments | (14) | (17) | (30) | ||
Pension Benefits [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | (21) | (7) | (21) | (7) | |
Amortization of prior service cost | 4 | 5 | 11 | 15 | |
Amortization of net actuarial loss | 1 | 1 | 7 | 2 | |
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 | [1] | 3 | 3 | 7 | 9 |
Amortization of net actuarial loss | [1] | 1 | 4 | 1 | |
Regulatory account transfer | [1] | (4) | (3) | (11) | (10) |
Change in investments | 0 | 0 | 0 | ||
Amortization of prior service cost tax | 1 | 2 | 4 | 6 | |
Net actuarial loss tax | 0 | 0 | 3 | 1 | |
Regulatory account transfer tax | 3 | 3 | 7 | 7 | |
Other Benefits [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | 15 | 15 | 15 | 15 | |
Amortization of prior service cost | 4 | 6 | 14 | 17 | |
Amortization of net actuarial loss | 1 | 1 | 3 | 2 | |
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 | [1] | 2 | 3 | 8 | 10 |
Amortization of net actuarial loss | [1] | 1 | 2 | 1 | |
Regulatory account transfer | [1] | (3) | (3) | (10) | (11) |
Change in investments | 0 | 0 | 0 | ||
Amortization of prior service cost tax | 2 | 3 | 6 | 7 | |
Net actuarial loss tax | 0 | 0 | 1 | 1 | |
Regulatory account transfer tax | 3 | 4 | 7 | 8 | |
Other Investments [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | 36 | 17 | 42 | ||
Net current period other comprehensive income (loss) | (18) | (17) | (24) | ||
Ending balance | 0 | 18 | 0 | 18 | |
Other Investments [Member] | Other Comprehensive Income Before Reclassifications [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Change in investments | (4) | 6 | |||
Net change in investments tax | 0 | 3 | 0 | 4 | |
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Amortization of prior service cost | [1] | 0 | 0 | 0 | |
Amortization of net actuarial loss | [1] | 0 | 0 | ||
Regulatory account transfer | [1] | 0 | 0 | 0 | |
Change in investments | (14) | (17) | (30) | ||
Change in investments tax | $ 0 | $ 10 | $ 12 | $ 20 | |
[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, Liabilitie30
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 6,584 | $ 6,322 |
Pension Benefits [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,304 | 2,347 |
Deferred Income Taxes [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,771 | 2,390 |
Utility Retained Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 423 | 456 |
Environmental Compliance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 705 | 717 |
Price Risk Management [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 143 | 127 |
Electromechanical Meters [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 18 | 70 |
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 98 | 113 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 122 | $ 102 |
Regulatory Assets, Liabilitie31
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 6,294 | $ 6,290 |
Cost Of Removal Obligations [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 4,509 | 4,211 |
Recoveries In Excess Of AROs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 610 | 754 |
Public Purpose Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 701 | 701 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 474 | $ 624 |
Regulatory Assets, Liabilitie32
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 1,857 | $ 2,266 |
Regulatory Balancing Accounts Receivable [Member] | Electric distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 265 | 344 |
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 24 | 261 |
Regulatory Balancing Accounts Receivable [Member] | Gas distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 718 | 566 |
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 390 | 608 |
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 136 | 109 |
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 324 | 378 |
Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 803 | 1,090 |
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 181 | 188 |
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 173 | 154 |
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 449 | $ 748 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | |
Debt [Line Items] | |||
Short-term debt matured | $ (300) | $ 0 | |
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | |||
Debt [Line Items] | |||
Debt instrument, interest rate | 0.01% | 0.01% | |
Debt instrument, face amount | $ 614 | $ 614 | |
Pollution Control Bonds Series 2009 A-D [Member] | |||
Debt [Line Items] | |||
Debt instrument, interest rate | 0.01% | 0.01% | |
Debt instrument, face amount | $ 309 | $ 309 | |
Utility [Member] | Senior Notes, 3.50%, Due 2025 [Member] | |||
Debt [Line Items] | |||
Debt instrument, interest rate | 3.50% | 3.50% | |
Senior Notes | $ 400 | $ 400 | |
Utility [Member] | Senior Notes, 4.30%, Due 2045 [Member] | |||
Debt [Line Items] | |||
Debt instrument, interest rate | 4.30% | 4.30% | |
Senior Notes | $ 100 | $ 100 | |
Utility [Member] | Floating Rate Senior Notes [Member] | |||
Debt [Line Items] | |||
Short-term debt matured | $ (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 | ||
Sep. 30, 2015 | Apr. 27, 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 | 34 | ||
Commercial Paper | 881 | ||
Facility Availability | $ 2,085 | ||
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 | 0 | ||
Facility Availability | 300 | ||
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 | 34 | ||
Commercial Paper | 881 | ||
Facility Availability | $ 2,385 | ||
[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 | ||
Sep. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | |
Fees and commissions | $ 1 | ||
Common Stock Value | $ 11,183 | $ 10,421 | |
Pacific Gas And Electric Company [Member] | |||
Common Stock Value | 1,322 | $ 1,322 | |
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 | 6,100,000 | ||
Stock Issued During Period Value Stock Options Exercised | $ 263 | ||
Underwritten Public Offering [Member] | |||
Common Stock Shares Issued | 6,800,000 | ||
Common Stock Value | $ 352 |
Equity (Changes In Equity) (Det
Equity (Changes In Equity) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Balance at December 31, 2014 | $ 15,748 | |||
Balance at December 31, 2014 | 16,000 | |||
Comprehensive Income Net Of Tax | $ 310 | $ 796 | 733 | $ 1,291 |
Common stock issued | 704 | |||
Share-based compensation | 58 | |||
Common stock dividends declared | (665) | |||
Preferred stock dividend requirement of subsidiary | (3) | (3) | (10) | (10) |
Balance at September 30, 2015 | 16,820 | 16,820 | ||
Balance at September 30, 2015 | 16,568 | 16,568 | ||
Pacific Gas And Electric Company [Member] | ||||
Balance at December 31, 2014 | 16,229 | |||
Comprehensive Income Net Of Tax | 305 | 793 | 715 | 1,271 |
Common stock issued | 0 | |||
Share-based compensation | 8 | |||
Common stock dividends declared | (537) | |||
Preferred stock dividend requirement | (3) | $ (3) | (10) | (10) |
Equity contributions | 605 | $ 705 | ||
Balance at September 30, 2015 | $ 17,010 | $ 17,010 |
Earnings Per Share (Reconciliat
Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Income available for common shareholders | $ 307 | $ 811 | $ 740 | $ 1,305 |
Weighted average common shares outstanding, basic | 486 | 472 | 481 | 466 |
Employee share-based compensation | 3 | 2 | 3 | 2 |
Weighted average common shares outstanding, diluted | 489 | 474 | 484 | 468 |
Total earnings per common share, diluted | $ 0.63 | $ 1.71 | $ 1.53 | $ 2.79 |
Derivatives (Volumes Of Outstan
Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details) | Sep. 30, 2015 | Dec. 31, 2014 | |
Forwards And Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 276,847,153 | 308,130,101 |
Forwards And Swaps [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | 4,884,523 | 5,346,787 | |
Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 134,380,439 | 164,418,002 |
Congestion Revenue Rights [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [3] | 186,018,832 | 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 costs due to transmission grid limitations. |
Derivatives (Outstanding Deriva
Derivatives (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Other Current Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 63 | $ 73 |
Cash Collateral | 11 | 19 |
Total Derivative Balance | 72 | 88 |
Netting | (2) | (4) |
Other Noncurrent Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 130 | 178 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 128 | 165 |
Netting | (2) | (13) |
Other Current Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (84) | (78) |
Cash Collateral | 34 | 26 |
Total Derivative Balance | (48) | (48) |
Netting | 2 | 4 |
Other Noncurrent Liabilities [Member | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (145) | (140) |
Cash Collateral | 24 | 9 |
Total Derivative Balance | (119) | (118) |
Netting | 2 | 13 |
Gross Derivative Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (36) | 33 |
Netting [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 0 | 0 |
Cash Collateral [Member | ||
Derivatives And Hedging Activities [Line Items] | ||
Cash Collateral | 69 | 54 |
Total Derivatve Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Derivative Balance | $ 33 | $ 87 |
Derivatives (Gains And Losses O
Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Unrealized gain (loss) - regulatory assets and liabilities | [1] | $ (45) | $ (6) | $ (69) | $ 79 |
Realized gain (loss) - cost of electricity | [2] | 1 | (22) | 4 | (48) |
Realized loss - cost of natural gas | [2] | (3) | (4) | (8) | (7) |
Net commodity risk | $ (47) | $ (32) | $ (73) | $ 24 | |
[1] | Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. | ||||
[2] | These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Derivatives (Additional Cash Co
Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) - USD ($) $ in Millions | Sep. 30, 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 | Sep. 30, 2015 | Dec. 31, 2014 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Money market investments | $ 92 | $ 94 | |||
Total assets | 3,250 | 3,399 | |||
Total liabilities | 167 | 166 | |||
Amount primarily related to deferred taxes on appreciation of investment value | 294 | 324 | |||
Other Investments | 33 | ||||
Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Money market investments | 21 | 17 | |||
Total assets | 2,711 | [1] | 2,745 | [2] | |
Fixed-income securities | 1,233 | 1,130 | |||
Global equity securities | 1,457 | 1,598 | |||
Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 200 | 253 | |||
Electricity | 196 | 251 | |||
Natural Gas | 4 | 2 | |||
Electricity | 165 | 163 | |||
Natural Gas | 2 | 3 | |||
Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 116 | 114 | |||
Fixed-income securities | 45 | 42 | |||
Life insurance contracts | 71 | 72 | |||
Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Money market investments | 7 | 7 | |||
Total assets | 131 | 160 | |||
Fixed-income securities | 106 | 128 | |||
Global equity securities | 18 | 25 | |||
Fair Value Measurements, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Money market investments | 92 | 94 | |||
Total assets | 2,275 | 2,478 | |||
Total liabilities | 60 | 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 | 21 | 17 | |||
Total assets | 2,176 | [1] | 2,343 | [2] | |
Fixed-income securities | 710 | 741 | |||
Global equity securities | 1,445 | 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 | 0 | 1 | |||
Electricity | 0 | 0 | |||
Natural Gas | 0 | 1 | |||
Electricity | 60 | 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 | 7 | 7 | |||
Total assets | 7 | 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 | 783 | 687 | |||
Total liabilities | 5 | 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 | 535 | [1] | 402 | [2] | |
Fixed-income securities | 523 | 389 | |||
Global equity securities | 12 | 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 | 8 | 18 | |||
Electricity | 4 | 17 | |||
Natural Gas | 4 | 1 | |||
Electricity | 3 | 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 | 116 | 114 | |||
Fixed-income securities | 45 | 42 | |||
Life insurance contracts | 71 | 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 | 124 | 153 | |||
Fixed-income securities | 106 | 128 | |||
Global equity securities | 18 | 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 | 185 | 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 | 185 | 232 | |||
Electricity | 185 | 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] | 7 | 2 | ||
Total liabilities | [3] | (62) | (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 | [3] | 0 | [1] | 0 | [2] |
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] | 7 | 2 | ||
Electricity | [3] | 7 | 2 | ||
Natural Gas | [3] | 0 | 0 | ||
Electricity | [3] | (62) | (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 $294 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) $ in Millions | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 3,250 | $ 3,399 | |
Liabilities, Fair Value | 167 | 166 | |
Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | 185 | 232 | |
Liabilities, Fair Value | $ (51) | $ (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 | $ (113) | $ (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] | (15.97) | (15.97) |
Minimum [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 17.64 | 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] | 38.8 | 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 | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||||
Beginning asset (liability) balance | $ 48 | $ (11) | $ 69 | $ (30) | |
Included in regulatory assets and liabilities or balancing accounts | [1] | (27) | (9) | (48) | 10 |
Ending asset (liability) balance | $ 21 | $ (20) | $ 21 | $ (20) | |
[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 | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value Measurements, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | $ 354 | $ 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 | 15,858 | 15,851 |
Pacific Gas And Electric Company [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | $ 14,273 | $ 13,778 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2015 | Dec. 31, 2014 | |||
Schedule of Available-for-sale Securities [Line Items] | ||||
Amortized Cost | $ 1,699 | [1] | $ 1,601 | |
Total Unrealized Gains | 1,033 | [1] | 1,190 | |
Total Unrealized Losses | (21) | [1] | (13) | |
Total Fair Value | 2,711 | [1] | 2,778 | |
Amount primarily related to deferred taxes on appreciation of investment value | 294 | 324 | ||
Money Market Investments [Member] | ||||
Schedule of Available-for-sale Securities [Line Items] | ||||
Amortized Cost | 21 | 17 | ||
Total Unrealized Gains | 0 | 0 | ||
Total Unrealized Losses | 0 | 0 | ||
Total Fair Value | 21 | 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 | 1,168 | 1,059 | ||
Total Unrealized Gains | 70 | 75 | ||
Total Unrealized Losses | (5) | (4) | ||
Total Fair Value | 1,233 | 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 | 510 | 520 | ||
Total Unrealized Gains | 963 | 1,087 | ||
Total Unrealized Losses | (16) | (9) | ||
Total Fair Value | $ 1,457 | $ 1,598 | ||
[1] | Represents amounts before deducting $294 million and $324 million at September 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 | Sep. 30, 2015USD ($) |
Less than 1 year | $ 21 |
1-5 years | 465 |
5-10 years | 290 |
More than 10 years | 457 |
Total maturities of debt securities | $ 1,233 |
Fair Value Measurements (Sche48
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 244 | $ 182 | $ 1,023 | $ 1,059 |
Gross realized gains on sales of securities held as available-for-sale | 3 | 30 | 50 | 114 |
Gross realized losses on sales of securities held as available-for-sale | $ (12) | $ 0 | $ (25) | $ (3) |
Commitments And Contingencies49
Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions | 9 Months Ended | |
Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) | |
Long-term Purchase Commitment [Line Items] | ||
Total | $ 780 | $ 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 | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |||
Impact Of Penalty Decision [Line Items] | ||||||
Fine payable to the state | $ 100 | [1] | $ 200 | |||
Customer bill credit | 400 | |||||
Disallowed capital expenditures | $ 141 | 270 | $ 0 | |||
Disallowed revenue for pipeline safety expenses | [2] | 0 | ||||
CPUC estimated cost of other remedies | [3] | 0 | ||||
Total Penalty Decision fines and remedies recorded | 770 | |||||
Total Penalty Decision [Member] | ||||||
Impact Of Penalty Decision [Line Items] | ||||||
Fine payable to the state | [1] | 300 | ||||
Customer bill credit | 400 | |||||
Disallowed capital expenditures | 689 | |||||
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] | 270 | ||||
Disallowed revenue for pipeline safety expenses | [2] | 0 | ||||
CPUC estimated cost of other remedies | [3] | 20 | ||||
Total Penalty Decision fines and remedies recorded | 990 | |||||
Penalty Decision Future Charges and Costs [Member] | ||||||
Impact Of Penalty Decision [Line Items] | ||||||
Fine payable to the state | [1] | 0 | ||||
Customer bill credit | 0 | |||||
Disallowed capital expenditures | [4] | 419 | ||||
Disallowed revenue for pipeline safety expenses | [2] | 161 | ||||
CPUC estimated cost of other remedies | [3] | 30 | ||||
Total Penalty Decision fines and remedies recorded | 610 | |||||
Remedy Related Capital Costs [Member] | ||||||
Impact Of Penalty Decision [Line Items] | ||||||
Disallowed capital expenditures | $ 1 | |||||
2017 GRC Request [Member] | ||||||
Impact Of Penalty Decision [Line Items] | ||||||
CPUC estimated cost of other remedies | 61 | |||||
Pacific Gas And Electric Company [Member] | ||||||
Impact Of Penalty Decision [Line Items] | ||||||
Disallowed capital expenditures | $ 270 | $ 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 estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additional remedy-related costs of approximately $61 million. The Utility could incur remedy-related costs that are higher than current estimates. | |||||
[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 $142 million and $270 million of capital spending (which include less than $1 million for remedy related capital costs) in the three months and nine months ended September 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 | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2014USD ($) | |||
Loss Contingencies [Line Items] | ||||||
Accrued legal liabilities | $ 61,000 | $ 55,000 | $ 61,000 | $ 55,000 | ||
Unrecognized Tax Benefits | 380,000 | 380,000 | ||||
Amount of capitalized PSEP costs included in Property, Plant, and Equipment | 657,000 | 657,000 | ||||
Payment To State General Fund | 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 | $ 770,000 | |||||
SED Maximum Statutory Penalty Per Violaiton | $ 50 | |||||
Butte Fire [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Number of Deaths | 2 | 2 | ||||
Number Of Structures Destroyed | 965 | 965 | ||||
Number Of Houses Destroyed | 571 | 571 | ||||
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 | 990,000 | |||||
Penalty Decision Future Charges and Costs [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 | $ 610,000 | |||||
Carmel Incident [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
CPUC Imposed Penalty | 10,850 | |||||
Violations Before January 1, 2012 [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
California Public Utilities Commission Imposed Penalty Per Day Per Violation | $ 20 | |||||
Violations After January 1, 2012 [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
California Public Utilities Commission Imposed Penalty Per Day Per Violation | 50 | |||||
Maximum Allowable Award [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Energy Efficiency Award For 2006-2008 Program Cycle | 180,000 | |||||
Actual Award [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Energy Efficiency Award For 2006-2008 Program Cycle | $ 104,000 | |||||
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 | 434,000 | ||||
Other Receivables Disputed Claims | 291,000 | $ 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 estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additional remedy-related costs of approximately $61 million. The Utility could incur remedy-related costs that are higher than current estimates. | |||||
[3] | These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses. |
Commitments And Contingencies52
Commitments And Contingencies (Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 | |
Topock natural gas compressor station | [1] | $ 296 | $ 291 |
Hinkley natural gas compressor station | [1] | 136 | 158 |
Former manufactured gas plant sites owned by the Utility or third parties | 267 | 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 | 94 | 98 | |
Total environmental remediation liability | $ 946 | $ 954 | |
[1] | See "Natural Gas Compressor Station Sites" below. |
Commitments And Contingencies53
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions | Sep. 30, 2015USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 678 |
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute | $ 1,800 |