Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2016 | Apr. 19, 2016 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q1 | |
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 | 496,042,305 | |
Pacific Gas And Electric Company [Member] | ||
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q1 | |
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 | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Operating Revenues | ||
Electric | $ 3,131 | $ 3,013 |
Natural gas | 843 | 886 |
Total operating revenues | 3,974 | 3,899 |
Operating Expenses | ||
Cost of electricity | 950 | 1,000 |
Cost of natural gas | 222 | 274 |
Operating and maintenance | 2,010 | 1,923 |
Depreciation, amortization, and decommissioning | 697 | 631 |
Total operating expenses | 3,879 | 3,828 |
Operating Income | 95 | 71 |
Interest income | 4 | 1 |
Interest expense | (203) | (189) |
Other income, net | 27 | 58 |
Income Before Income Taxes | (77) | (59) |
Income tax benefit | (187) | (93) |
Net Income | 110 | 34 |
Preferred stock dividend requirement of subsidiary | 3 | 3 |
Income Available for Common Shareholders | $ 107 | $ 31 |
Weighted Average Common Shares Outstanding, Basic | 493 | 477 |
Weighted Average Common Shares Outstanding, Diluted | 495 | 481 |
Net Earnings Per Common Share, Basic | $ 0.22 | $ 0.06 |
Net Earnings Per Common Share, Diluted | 0.22 | 0.06 |
Dividends Declared Per Common Share | $ 0.46 | $ 0.46 |
Pacific Gas And Electric Company [Member] | ||
Operating Revenues | ||
Electric | $ 3,132 | $ 3,014 |
Natural gas | 843 | 886 |
Total operating revenues | 3,975 | 3,900 |
Operating Expenses | ||
Cost of electricity | 950 | 1,000 |
Cost of natural gas | 222 | 274 |
Operating and maintenance | 2,011 | 1,923 |
Depreciation, amortization, and decommissioning | 696 | 631 |
Total operating expenses | 3,879 | 3,828 |
Operating Income | 96 | 72 |
Interest income | 4 | 1 |
Interest expense | (201) | (187) |
Other income, net | 24 | 26 |
Income Before Income Taxes | (77) | (88) |
Income tax benefit | (185) | (92) |
Net Income | 108 | 4 |
Preferred stock dividend requirement | 3 | 3 |
Income Available for Common Shareholders | $ 105 | $ 1 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Net income | $ 110 | $ 34 |
Other Comprehensive Income | ||
Pension and other postretirement benefit plans obligations (net of taxes of $0 and $0, at respective dates) | 0 | 0 |
Net change in investments (net of taxes of $0 and $12, at respective dates) | 0 | (17) |
Total other comprehensive income (loss) | 0 | (17) |
Comprehensive Income | 110 | 17 |
Preferred stock dividend requirement of subsidiary | 3 | 3 |
Comprehensive Income Attributable to Common Shareholders | 107 | 14 |
Pacific Gas And Electric Company [Member] | ||
Net income | 108 | 4 |
Other Comprehensive Income | ||
Pension and other postretirement benefit plans obligations (net of taxes of $0 and $0, at respective dates) | 0 | 0 |
Total other comprehensive income (loss) | 0 | 0 |
Comprehensive Income | $ 108 | $ 4 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 |
Net change in investments tax | 0 | 12 |
Pacific Gas And Electric Company [Member] | ||
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and cash equivalents | $ 142 | $ 123 |
Restricted cash | 234 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $55 and $54 at respective dates) | 1,010 | 1,106 |
Accrued unbilled revenue | 685 | 855 |
Regulatory balancing accounts | 1,721 | 1,760 |
Other | 328 | 286 |
Regulatory assets | 504 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 109 | 126 |
Materials and supplies | 344 | 313 |
Income taxes receivable | 230 | 155 |
Other | 327 | 338 |
Total current assets | 5,634 | 5,813 |
Property, Plant, and Equipment | ||
Electric | 49,974 | 48,532 |
Gas | 16,982 | 16,749 |
Construction work in progress | 2,148 | 2,059 |
Other | 2 | 2 |
Total property, plant, and equipment | 69,106 | 67,342 |
Accumulated depreciation | (21,062) | (20,619) |
Net property, plant, and equipment | 48,044 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,130 | 7,029 |
Nuclear decommissioning trusts | 2,516 | 2,470 |
Income taxes receivable | 153 | 135 |
Other | 1,173 | 1,064 |
Total other noncurrent assets | 10,972 | 10,698 |
TOTAL ASSETS | 64,650 | 63,234 |
Current Liabilities | ||
Short-term borrowings | 693 | 1,019 |
Long-term debt, classified as current | 160 | 160 |
Accounts payable | ||
Trade creditors | 1,062 | 1,414 |
Regulatory balancing accounts | 704 | 715 |
Other | 598 | 398 |
Disputed claims and customer refunds | 457 | 454 |
Interest payable | 145 | 206 |
Other | 2,155 | 1,997 |
Total current liabilities | 5,974 | 6,363 |
Noncurrent Liabilities | ||
Long-term debt | 16,522 | 15,925 |
Regulatory liabilities | 6,486 | 6,321 |
Pension and other postretirement benefits | 2,629 | 2,622 |
Asset retirement obligations | 4,480 | 3,643 |
Deferred income taxes | 9,323 | 9,206 |
Other | 2,372 | 2,326 |
Total noncurrent liabilities | $ 41,812 | $ 40,043 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Common stock | $ 11,440 | $ 11,282 |
Reinvested earnings | 5,179 | 5,301 |
Accumulated other comprehensive income (loss) | (7) | (7) |
Total shareholders' equity | 16,612 | 16,576 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 16,864 | 16,828 |
TOTAL LIABILITIES AND EQUITY | 64,650 | 63,234 |
Pacific Gas And Electric Company [Member] | ||
Current Assets | ||
Cash and cash equivalents | 44 | 59 |
Restricted cash | 234 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $55 and $54 at respective dates) | 1,010 | 1,106 |
Accrued unbilled revenue | 685 | 855 |
Regulatory balancing accounts | 1,721 | 1,760 |
Other | 353 | 284 |
Regulatory assets | 504 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 109 | 126 |
Materials and supplies | 344 | 313 |
Income taxes receivable | 204 | 130 |
Other | 327 | 338 |
Total current assets | 5,535 | 5,722 |
Property, Plant, and Equipment | ||
Electric | 49,974 | 48,532 |
Gas | 16,982 | 16,749 |
Construction work in progress | 2,148 | 2,059 |
Total property, plant, and equipment | 69,104 | 67,340 |
Accumulated depreciation | (21,060) | (20,617) |
Net property, plant, and equipment | 48,044 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,130 | 7,029 |
Nuclear decommissioning trusts | 2,516 | 2,470 |
Income taxes receivable | 153 | 135 |
Other | 1,061 | 958 |
Total other noncurrent assets | 10,860 | 10,592 |
TOTAL ASSETS | 64,439 | 63,037 |
Current Liabilities | ||
Short-term borrowings | 693 | 1,019 |
Long-term debt, classified as current | 160 | 160 |
Accounts payable | ||
Trade creditors | 1,062 | 1,414 |
Regulatory balancing accounts | 704 | 715 |
Other | 646 | 418 |
Disputed claims and customer refunds | 457 | 454 |
Interest payable | 144 | 203 |
Other | 1,906 | 1,750 |
Total current liabilities | 5,772 | 6,133 |
Noncurrent Liabilities | ||
Long-term debt | 16,174 | 15,577 |
Regulatory liabilities | 6,486 | 6,321 |
Pension and other postretirement benefits | 2,540 | 2,534 |
Asset retirement obligations | 4,480 | 3,643 |
Deferred income taxes | 9,605 | 9,487 |
Other | 2,331 | 2,282 |
Total noncurrent liabilities | $ 41,616 | $ 39,844 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Preferred stock | $ 258 | $ 258 |
Common stock | 1,322 | 1,322 |
Additional paid-in capital | 7,280 | 7,215 |
Reinvested earnings | 8,188 | 8,262 |
Accumulated other comprehensive income (loss) | 3 | 3 |
Total shareholders' equity | 17,051 | 17,060 |
TOTAL LIABILITIES AND EQUITY | $ 64,439 | $ 63,037 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Allowance for doubtful accounts | $ 55 | $ 54 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 495,606,702 | 492,025,443 |
Pacific Gas And Electric Company [Member] | ||
Allowance for doubtful accounts | $ 55 | $ 54 |
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 | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Cash Flows from Operating Activities | ||
Net income | $ 110 | $ 34 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 697 | 631 |
Allowance for equity funds used during construction | (27) | (28) |
Deferred income taxes and tax credits, net | 117 | 113 |
Disallowed capital expenditures | 87 | 53 |
Other | 73 | 52 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | 210 | 236 |
Inventories | (14) | 58 |
Accounts payable | (65) | (46) |
Income taxes receivable/payable | (75) | 3 |
Other current assets and liabilities | 146 | (114) |
Regulatory assets, liabilities, and balancing accounts, net | (87) | 195 |
Other noncurrent assets and liabilities | (117) | (107) |
Net cash provided by operating activities | 1,055 | 1,080 |
Cash Flows from Investing Activities | ||
Capital expenditures | (1,229) | (1,191) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 439 | 417 |
Purchases of nuclear decommissioning trust investments | (463) | (505) |
Other | 4 | 7 |
Net cash used in investing activities | (1,249) | (1,272) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $1 in 2016 | (577) | 223 |
Short-term debt financing | 250 | 0 |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2016 | 594 | 0 |
Common stock issued | 146 | 151 |
Common stock dividends paid | (219) | (211) |
Other | 20 | 23 |
Net cash provided by financing activities | 214 | 186 |
Net change in cash and cash equivalents | 20 | (6) |
Cash and cash equivalents at January 1 | 123 | 151 |
Cash and cash equivalents at March 31 | 142 | 145 |
Supplemental Cash Flow Information [Abstract] | ||
Interest, net of amounts capitalized | (242) | (216) |
Supplemental disclosures of noncash investing and financing activities | ||
Common stock dividends declared but not yet paid | 226 | 218 |
Capital expenditures financed through accounts payable | 373 | 217 |
Noncash common stock issuances | 6 | 5 |
Pacific Gas And Electric Company [Member] | ||
Cash Flows from Operating Activities | ||
Net income | 108 | 4 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 696 | 631 |
Allowance for equity funds used during construction | (27) | (28) |
Deferred income taxes and tax credits, net | 118 | 112 |
Disallowed capital expenditures | 87 | 53 |
Other | 68 | 45 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | 183 | 215 |
Inventories | (14) | 58 |
Accounts payable | (37) | 26 |
Income taxes receivable/payable | (74) | 2 |
Other current assets and liabilities | 151 | (123) |
Regulatory assets, liabilities, and balancing accounts, net | (87) | 195 |
Other noncurrent assets and liabilities | (109) | (89) |
Net cash provided by operating activities | 1,063 | 1,101 |
Cash Flows from Investing Activities | ||
Capital expenditures | (1,229) | (1,191) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 439 | 417 |
Purchases of nuclear decommissioning trust investments | (463) | (505) |
Other | 3 | 7 |
Net cash used in investing activities | (1,250) | (1,272) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $1 in 2016 | (577) | 223 |
Short-term debt financing | 250 | 0 |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2016 | 594 | 0 |
Preferred stock dividends paid | (3) | (3) |
Common stock dividends paid | (179) | (179) |
Equity contribution from PG&E Corporation | 65 | 100 |
Other | 22 | 25 |
Net cash provided by financing activities | 172 | 166 |
Net change in cash and cash equivalents | (15) | (5) |
Cash and cash equivalents at January 1 | 59 | 55 |
Cash and cash equivalents at March 31 | 44 | 50 |
Supplemental Cash Flow Information [Abstract] | ||
Interest, net of amounts capitalized | (237) | (211) |
Supplemental disclosures of noncash investing and financing activities | ||
Capital expenditures financed through accounts payable | $ 373 | $ 217 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Discount on net issuances of commercial paper | $ 1 | $ 0 |
Premium, discount, and issuance costs on proceeds from long-term debt | 6 | 0 |
Pacific Gas And Electric Company [Member] | ||
Discount on net issuances of commercial paper | 1 | 0 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 6 | $ 0 |
Organization And Basis Of Prese
Organization And Basis Of Presentation | 3 Months Ended |
Mar. 31, 2016 | |
Organization And Basis Of Presentation | NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This 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, as the companies assess financial performance and allocate resources on a consolidated basis. 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, 2015 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2015 Form 10-K. This quarterly report should be read in conjunction with the 2015 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 | 3 Months Ended |
Mar. 31, 2016 | |
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 2015 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 March 31, 2016 , 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 March 31, 2016 , it did not consolidate any of them. Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings. On March 1, 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC. The estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $ 1.4 billion, for a total estimated cost of $ 4.8 billion, due to increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $ 3.3 billion at March 31, 2016, which includes an $ 818 million adjustment to reflect the increased cost estimates described above, and $2.5 billion at December 31, 2015. These estimates are based on the 2016 decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets. Pension and Other 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 months ended March 31, 2016 and 2015 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 113 $ 119 $ 13 $ 13 Interest cost 179 168 19 18 Expected return on plan assets (207) (218) (27) (28) Amortization of prior service cost 2 4 4 5 Amortization of net actuarial loss 6 3 1 1 Net periodic benefit cost 93 76 10 9 Regulatory account transfer (1) (8) 9 - - Total $ 85 $ 85 $ 10 $ 9 (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 March 31, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 1 2 3 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (3) (8) Net current period other comprehensive loss - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended March 31, 2015 Beginning balance $ (21) 15 17 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 2 3 - 5 Amortization of net actuarial loss (net of taxes of $1, $0, and $0, respectively) (1) 2 - - 2 Regulatory account transfer (net of taxes of $3, $2, and $0, respectively) (1) (4) (3) - (7) 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.) 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. Recently Adopted Accounting Guidance Fair Value Measurement In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , which 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. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this standard did not impact their Condensed Consolidated Financial Statements. All prior periods presented in these Condensed Consolidated financial statements reflect the retrospective adoption of this guidance (See Note 8 below.) 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. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements. 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 the existing guidance relating to the presentation of debt issuance costs. The amendments in this ASU 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 adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements. PG&E Corporation and the Utility reclassified $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported. All prior periods presented in these Condensed Consolidated financial statements reflect the retrospective adoption of this guidance. Accounting Standards Issued But Not Yet Adopted Share-based Payment Accounting In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2017. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures. Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 with retrospective application. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which amends the existing guidance relating to the recognition and measurement of financial instruments. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures. Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends the existing revenue recognition guidance . In August 2015, the FASB deferred the effective date of this amendment for public companies by one year to January 1, 2018, with early adoption permitted as of the original effective date of January 1, 2017. (See ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date .) 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 | 3 Months Ended |
Mar. 31, 2016 | |
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 March 31, December 31, (in millions) 2016 2015 Pension benefits $ 2,414 $ 2,414 Deferred income taxes 3,265 3,054 Utility retained generation 399 411 Environmental Compliance Costs 683 748 Price risk management 134 138 Unamortized loss, net of gain, on reacquired debt 90 94 Other 145 170 Total long-term regulatory assets $ 7,130 $ 7,029 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K. Regulatory Liabilities Long-term regulatory liabilities are composed of the following: Balance at March 31, December 31, (in millions) 2016 2015 Cost of removal obligations $ 4,717 $ 4,605 Recoveries in excess of asset retirement obligations 645 631 Public purpose programs 620 600 Other 504 485 Total long-term regulatory liabilities $ 6,486 $ 6,321 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K. Regulatory Balancing Accounts The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at March 31, December 31, (in millions) 2016 2015 Electric distribution $ 515 $ 380 Utility generation 225 122 Gas distribution 280 493 Energy procurement 87 262 Public purpose programs 149 155 Other 465 348 Total regulatory balancing accounts receivable $ 1,721 $ 1,760 Payable Balance at March 31, December 31, (in millions) 2016 2015 Energy procurement $ 184 $ 112 Public purpose programs 212 244 Other 308 359 Total regulatory balancing accounts payable $ 704 $ 715 The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency and low income energy efficiency. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2016 | |
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 March 31, 2016 : 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) 33 443 2,524 Total revolving credit facilities $ 3,300 $ 33 $ 443 $ 2,824 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. Other Short-term Borrowings In March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Senior Notes Issuances In March 2016, the Utility issued $600 million principal amount of 2.95% Senior Notes due March 1, 2026. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Variable Rate Interest At March 31, 2016 , the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.37% to 0.45%. At March 31, 2016, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.34% to 0.38%. Pollution control bonds Series 2009 C and D will mature on December 1, 2016. |
Equity
Equity | 3 Months Ended |
Mar. 31, 2016 | |
Equity | NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2016 were as follows: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2015 $ 16,828 $ 17,060 Comprehensive income 110 108 Equity contributions - 65 Common stock issued 152 - Share-based compensation 6 - Common stock dividends declared (229) (179) Preferred stock dividend requirement - (3) Preferred stock dividend requirement of subsidiary (3) - Balance at March 31, 2016 $ 16,864 $ 17,051 During the three months ended March 31, 2016, PG&E Corporation sold 1.3 million shares under the February 2015 equity distribution agreement for cash proceeds of $ 74 million, net of commissions paid of $ 1 million. As of March 31, 2016, the remaining gross sales available under this agreement were $ 350 million. 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 three months ended March 31, 2016 , 2.3 million shares were issued for cash proceeds of $ 72 million under these plans. |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2016 | |
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 March 31, (in millions, except per share amounts) 2016 2015 Income available for common shareholders $ 107 $ 31 Weighted average common shares outstanding, basic 493 477 Add incremental shares from assumed conversions: Employee share-based compensation 2 4 Weighted average common shares outstanding, diluted 495 481 Total earnings per common share, diluted $ 0.22 $ 0.06 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive. |
Derivatives
Derivatives | 3 Months Ended |
Mar. 31, 2016 | |
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 physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Derivatives are recorded at fair value and 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. 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 March 31, December 31, Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 341,884,852 333,091,813 Options 92,426,200 111,550,004 Electricity (Megawatt-hours) Forwards and Swaps 3,580,205 3,663,512 Congestion Revenue Rights (3) 198,499,963 216,383,389 (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 March 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (5) $ 12 $ 98 Other noncurrent assets – other 173 (5) - 168 Current liabilities – other (105) 5 46 (54) Noncurrent liabilities – other (139) 5 16 (118) Net commodity risk $ 20 $ - $ 74 $ 94 At December 31, 2015 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 97 (4) 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Net commodity risk $ 27 $ - $ 90 $ 117 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended March 31, (in millions) 2016 2015 Net unrealized gain (loss) - regulatory assets and liabilities (1) $ (7) $ (52) Realized loss - cost of electricity (2) (29) (7) Realized loss - cost of natural gas (2) (1) (1) Total commodity risk $ (37) $ (60) (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 March 31, 2016 , 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 March 31, December 31, (in millions) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (9) $ (2) Collateral posting in the normal course of business related to these derivatives 7 - Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (2) (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 | 3 Months Ended |
Mar. 31, 2016 | |
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 are held by PG&E Corporation and not the Utility. Fair Value Measurements At March 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 97 $ - $ - $ - $ 97 Nuclear decommissioning trusts Short-term investments 25 - - - 25 Global equity securities 1,619 - - - 1,619 Fixed-income securities 682 508 - - 1,190 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,326 508 - - 2,847 Price risk management instruments (Note 7) Electricity 1 12 246 3 262 Gas 2 3 - (1) 4 Total price risk management instruments 3 15 246 2 266 Rabbi trusts Fixed-income securities - 58 - - 58 Life insurance contracts - 72 - - 72 Total rabbi trusts - 130 - - 130 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 147 Total long-term disability trust 8 - - - 155 Total assets $ 2,434 $ 653 $ 246 $ 2 $ 3,495 Liabilities: Price risk management instruments (Note 7) Electricity $ 67 $ 5 $ 171 $ (72) $ 171 Gas - 1 - - 1 Total liabilities $ 67 $ 6 $ 171 $ (72) $ 172 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 331 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Short-term investments 36 - - - 36 Global equity securities 1,520 - - - 1,520 Fixed-income securities 694 521 - - 1,215 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,250 521 - - 2,784 Price risk management instruments (Note 9 in the 2015 Form 10-K) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Short-term investments 7 - - - 7 Assets measured at NAV - - - - 158 Total long-term disability trust 7 - - - 165 Total assets $ 2,321 $ 658 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9 in the 2015 Form 10-K) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 Total liabilities $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between 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 three months ended March 31, 2016 and 2015 . Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income 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. Assets Measured at NAV Using Practical Expedient On January 1, 2016, PG&E Corporation and the Utility adopted FASB ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) and applied it retrospectively for the periods presented in their Condensed Consolidated Financial Statements . (See Note 2 above.) In accordance with this guidance, investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of US government securities and asset-backed securities. Price Risk Management Instruments Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to the Chief Risk and Audit Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance 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 March 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 246 $ 59 Market approach CRR auction prices $ (23.81) - 8.76 Power purchase agreements $ - $ 112 Discounted cash flow Forward prices $ 17.64 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power purchase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 (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 months ended March 31, 2016 and 2015 : Price Risk Management Instruments (in millions) 2016 2015 Asset (liability) balance as of January 1 $ 89 $ 69 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (14) (27) Asset (liability) balance as of March 31 $ 75 $ 42 (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, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at March 31, 2016 and December 31, 2015 , 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 March 31, 2016 and December 31, 2015 . 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 March 31, 2016 At December 31, 2015 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 356 $ 350 $ 354 Utility 15,412 17,823 14,918 16,422 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 March 31, 2016 Nuclear decommissioning trusts Short-term investments $ 25 $ - $ - $ 25 Global equity securities 603 1,038 (9) 1,632 Fixed-income securities 1,113 81 (4) 1,190 Total (1) $ 1,741 $ 1,119 $ (13) $ 2,847 As of December 31, 2015 Nuclear decommissioning trusts Short-term investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 (1) Represents amounts before deducting $ 331 million and $314 million at March 31, 2016 and December 31, 2015 , respectively, primarily related to deferred taxes on appreciation of investment value. The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) March 31, 2016 Less than 1 year $ 26 1–5 years 409 5–10 years 251 More than 10 years 504 Total maturities of fixed-income securities $ 1,190 The following table provides a summary of activity for the investments: Three Months Ended March 31, 2016 March 31, 2015 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 439 417 Gross realized gains on sales of securities held as available-for-sale 5 35 Gross realized losses on sales of securities held as available-for-sale (2) (3) |
Commitments And Contingencies
Commitments And Contingencies | 3 Months Ended |
Mar. 31, 2016 | |
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 Order Instituting an Investigation into Compliance with Ex Parte Communication Rules During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have been made or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a Commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting. On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in the CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices. On April 18, 2016, the Cities of San Bruno and San Carlos, ORA, the SED, TURN, and the Utility filed a joint Meet and Confer Process Report in advance of the prehearing conference that was held on April 20, 2016. The report included the proposed scope of the proceeding, including the number of communications at issue, a procedure for moving undisputed facts into the evidentiary record, a diligence process for providing additional factual information, and a procedural schedule. Subject to the CPUC’s approval, the parties have agreed that the scope of this proceeding may include a total of 159 communications (the 46 communications already included in the OII and 113 additional communications). The parties also recommended briefing on whether an additional 21 communications should be included in the proceeding. The Utility is expecting a ruling on these proposals in the second quarter of 2016. The CPUC will determine whether the communications included within the scope of the proceeding were in violation of its rules and whether to impose penalties or other remedies. The CPUC can impose fines up to $50,000 for each violation, per day. The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as how many days each violation continued; the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve 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 discretion in determining penalties. PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but they are unable to reasonably estimate the amount or range of future charges that could be incurred, because it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, and whether the CPUC will consider additional communications in the OII, including those identified in a motion filed on December 1, 2015, by the City of San Bruno in the 2015 GT&S rate case . It is also uncertain whether the CPUC will take additional action in any of the proceedings in which the Utility has self-reported communications that may have violated the CPUC’s ex parte rules. Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with the federal and state investigators. It is 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. 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. On February 26, 2016, the Utility, the SED, TURN, and the City of Carmel, California (“Carmel”) filed their opening briefs. In its brief, the SED cited alleged record-keeping violations related to various natural gas distribution incidents, the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. The SED recommended that the CPUC impose a fine on the Utility of approximately $112 million for these alleged violations. The SED also recommended that the CPUC require the Utility to undertake various remedial actions with respect to its gas distribution system records and facilities and that the Utility be prohibited from recovering remedial-related costs from customers. Carmel recommended that the CPUC impose penalties on the Utility of up to approximately $652 million, including approximately $137 million for the natural gas explosion that occurred in Carmel on March 3, 2014 (for which the Utility has previously paid a CPUC-imposed fine of $10.85 million). Carmel also recommended various remedial measures. TURN recommended that the Utility be required to undertake remedial actions, fund annual SED audits of the Utility’s record-keeping practices for a period of ten years, and promptly correct any deficiencies identified in those audits. On April 1, 2016, the Utility filed its reply brief in which the Utility indicated that it did not agree that any penalty was appropriate, but if the CPUC determined that a penalty should be imposed, such penalty should not exceed $33.6 million. The Utility recommended that such penalty, if imposed, should be invested in the safety of the Utility’s gas distribution system, for example for implementation of certain remedial measures. The Utility expects that the presiding officer’s decision will be issued within 60 days of the April 1, 2016 filing. Unless any party files an appeal of the presiding officer’s decision or a CPUC Commissioner requests a CPUC review of the presiding officer’s decision within 30 days, the decision will become final. The CPUC has the authority to extend the deadlines indicated above. PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the form of fines or other remedies, including possible future unrecoverable costs to implement operational remedies. Remedies would be recorded in the period the expense is incurred and fines would be recorded when considered probable and their amount or range can be reasonably estimated. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s discretion in imposing fines and other remedies. 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 had been completed and that remediation work, including removal of the encroachments, was 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 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. In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations of natural gas safety regulations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can consider the discretionary factors discussed above (see “ Order Instituting an Investigation into Compliance with Ex Parte Communication Rules” above) in determining the number of violations and whether to impose daily fines for continuing violations. The SED is required, however, to impose the maximum statutory penalty of $50,000 for each separate violation. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters 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 superseded the original indictment that was returned on April 1, 2014. The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13 remaining counts. Although the trial previously had been scheduled to begin on April 26, 2016, the court vacated the trial date and no new trial date has been set. The court stated that it will set a new trial date in due course. The maximum statutory fine for each felony count is $500,000, for total potential fines of $6.5 million. The government is also seeking fines under the Alternative Fines Act. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” On December 8, 2015, the court issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act. The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of gross gains prior to deciding whether to dismiss those allegations. Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million. On February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges. The 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. 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. 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 The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of March 31, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, of which $665 million was written off in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2016. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected. Penalty Decision’s Disallowance of Natural Gas Capital Spend On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings pending against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”). (In January 2016, the CPUC closed the investigative proceedings.) The total penalty includes (1) a $300 million fine, (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. For the three months ended March 31, 2016, the Utility recorded additional charges in operating and maintenance expenses in the Condensed Consolidated Statements of Income of $87 million, as a result of the Penalty Decision. The cumulative charges at March 31, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table: Three Months Cumulative Future Ended Charges Charges March 31, March 31, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit - 400 - 400 Charge for disallowed capital (1) 87 494 195 689 Disallowed revenue for pipeline safety expenses (2) - - 161 161 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 87 $ 1,194 $ 356 $ 1,600 (1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will identify in a final decision to be issued in the Utility’s 2015 GT&S rate case. The Penalty Decision requires that at least $689 million of the $850 million cost disallowance be allocated to capital expenditures. The Utility estimates that approximately $494 million of cumulative capital spending is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision. (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 and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred. Other Legal and Regulatory Contingencies PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. Investigation of the Butte Fire On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the “Butte fire,” the wildfire that ignited and spread in Amador and Calaveras Counties in Northern California in September 2015. Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and its vegetation management contractors to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility. In connection with the Butte fire, approximately 32 complaints have been filed to date against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving approximately 1,300 individual plaintiffs and their insurance companies. In response to plaintiffs’ and the Utility’s requests, the California Judicial Council has authorized the coordination of all cases in the Superior Court of California, Sacramento County. Plaintiffs have begun to present to the Utility claims seeking early resolution of preference cases (individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The number of complaints may increase in the future. An initial case management conference was held on April 22, 2016 and the next case management conference is currently scheduled for May 24, 2016. In connection with this matter, the Utility may be liable for property damages without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent. Based on the evidence described in the Cal Fire report that the Gray Pine tree contacted an electric line of the Utility, the Utility believes that it is probable that it will incur a loss of $350 million for property damages in connection with this matter, which corresponds to the lower end of the range of its reasonably estimated losses. This amount is based on estimates about the number, size, and type of structures damaged or destroyed, and assumptions about the contents of such structures and other property damage. The Utility currently is unable to reasonably estimate the upper end of the range. At March 31, 2016, the Condensed Consolidated Balance Sheets include $350 million in other current liabilities for the estimated property damages. The Utility also believes that it is reasonably possible that it will incur a loss in excess of this amount, for additional costs related to fire suppression, personal injury damages, and other damages. The Utility believes that $90 million is a reasonable estimate of fire suppression costs. The Utility currently is unable to reasonably estimate other costs. The Utility has insurance coverage for third party 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, results of operations, or cash flows could be materially affected. As a result of the Cal Fire report, additional investigations and proceedings may be opened, the outcome of which PG&E Corporation and the Utility are unable to predict. Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards On September 17, 2015, the CPUC granted TURN’s and ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California IOUs for the 2006-2008 energy efficiency program cycle. Under the incentive ratemaking mechanism applicable to the 2006-2008 program cycle, the Utility could have earned incentive revenues up to a maximum of $180 million, depending on the extent to which the Utility achieved the energy savings targets. Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened proceeding, the CPUC will evaluate whether the incentive amounts awarded to the IOUs were just and reasonable, and whether any refunds are due. On March 18, 2016, TURN and ORA submitted a joint proposal to require a refund of incentive awards that TURN and ORA argue were not calculated in accordance with the ratemaking mechanism rules and procedures the CPUC had previously adopted. TURN and ORA contended that the CPUC should order the Utility to refund $104 million, the entire incentive earnings award, plus interest, to customers as either (1) a revenue credit to customers’ distribution and gas transportation accounts or (2) as a line item to the customers’ first monthly bill following the issuance of a CPUC decision. Additionally, on March 18, 2016, the IOUs submitted their proposals requesting that the CPUC reaffirm its prior decisions. The IOUs asserted that, given the many unresolved disputes about the data in the Energy Division’s 2010 Evaluation Report, the CPUC appropriately used different data to calculate the awards. The IOUs noted that under the incentive ratemaking mechanism, any refunds of prior incentive earnings should be deducted from future incentive earnings claims. On April 8, 2016, the IOUs, TURN and ORA filed comments on the proposals, in which the parties reiterated their requests. The Utility currently expects that evidentiary hearings, if ordered by the CPUC, would be held in July 2016. It is uncertain how the CPUC will resolve this matter and when the CPUC will issue a decision. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts previously awarded or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations. If the Utility were required to make a refund as TURN and ORA propose, PG&E Corporation’s and the Utility’s financial results would be affected by the amount of any refund-related charges. Residential Rate Reform Rate Change On February 17, 2016, the Utility filed a proposed rate change for rates to be billed to customers effective March 1, 2016. On February 29, 2016, the CPUC rejected the Utility’s proposed rate change, stating that the rate design failed to comply with the requirements adopted in the Decision on Residential Rate Reform issued on July 3, 2015, that set a specific rate change “glidepath” for the Utility. The Utility began billing customers based on its proposed rates on March 1, 2016. On March 9, 2016, the assigned ALJ issued a ruling directing the Utility to show cause why the CPUC should not order sanctions and other remedies in response to the Utility charging rates not authorized by the CPUC. On March 14, 2016, the assigned ALJ issued an additional ruling that (1) acknowledged that utilities might not be able to follow the exact “glidepath” set forth in the decision because it had been based on forecast data and (2) indicated a new process to be followed before the CPUC if the new rates do not exactly match the “glidepath.” On March 24, 2016, the Utility temporarily reverted back to billing customers based on rates generally similar to those in place prior to March 1, 2016. Also, on March 24, 2016, the Utility filed an additional advice letter proposing a new, three-tiered rate structure. The proposed new rate structure is subject to the CPUC approval. On April 20, 2016, the Energy Division of the CPUC issued a draft resolution that approves the Utility’s proposed solution, but does not address the ruling to show cause. The Utility believes it is reasonably possible it may be subject to penalties or shareholder reparations for charging rates not authorized by the CPUC between March 1, 2016 and March 24, 2016. The Utility is unable to determine the form or amount of penalties or reasonably estimate the amount or range of future charges that could be incurred. 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 $55 million at March 31, 2016 and $63 million at December 31, 2015. 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 March 31, December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 302 $ 300 Hinkley natural gas compressor station (1) 140 140 Former manufactured gas plant sites owned by the Utility or third parties 283 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 136 164 Fossil fuel-fired generation facilities and sites 103 94 Total environmental remediation liability $ 964 $ 969 (1) See “Natural Gas Compressor Station Sites” below. At March 31, 2016 , the Utility expected to recover $ 680 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 subject to the regulatory authority of the Regional Board. On November 4, 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets. The Utility’s environmental remediation liability at March 31, 2016 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to be performed to implement the final remediation plan and the Utility’s required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in Dec |
New And Significant Accountin18
New And Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2016 | |
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 March 31, 2016 , 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 March 31, 2016 , it did not consolidate any of them. |
Asset Retirement Obligations | Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceedings. On March 1, 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC. The estimated undiscounted cost to decommission the Utility’s nuclear power plants increased by approximately $ 1.4 billion, for a total estimated cost of $ 4.8 billion, due to increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $ 3.3 billion at March 31, 2016, which includes an $ 818 million adjustment to reflect the increased cost estimates described above, and $2.5 billion at December 31, 2015. These estimates are based on the 2016 decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets. |
Pension And Other 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 months ended March 31, 2016 and 2015 were as follows: Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 113 $ 119 $ 13 $ 13 Interest cost 179 168 19 18 Expected return on plan assets (207) (218) (27) (28) Amortization of prior service cost 2 4 4 5 Amortization of net actuarial loss 6 3 1 1 Net periodic benefit cost 93 76 10 9 Regulatory account transfer (1) (8) 9 - - Total $ 85 $ 85 $ 10 $ 9 (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 March 31, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 1 2 3 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (3) (8) Net current period other comprehensive loss - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended March 31, 2015 Beginning balance $ (21) 15 17 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 2 3 - 5 Amortization of net actuarial loss (net of taxes of $1, $0, and $0, respectively) (1) 2 - - 2 Regulatory account transfer (net of taxes of $3, $2, and $0, respectively) (1) (4) (3) - (7) 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.) 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) | 3 Months Ended |
Mar. 31, 2016 | |
Components Of Net Periodic Benefit Cost | Pension Benefits Other Benefits Three Months Ended March 31, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 113 $ 119 $ 13 $ 13 Interest cost 179 168 19 18 Expected return on plan assets (207) (218) (27) (28) Amortization of prior service cost 2 4 4 5 Amortization of net actuarial loss 6 3 1 1 Net periodic benefit cost 93 76 10 9 Regulatory account transfer (1) (8) 9 - - Total $ 85 $ 85 $ 10 $ 9 (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 March 31, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 1 2 3 Amortization of net actuarial loss (net of taxes of $2 and $0, respectively) 4 1 5 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (3) (8) Net current period other comprehensive loss - - - Ending balance $ (23) $ 16 $ (7) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Other Benefits Benefits Investments Total (in millions, net of income tax) Three Months Ended March 31, 2015 Beginning balance $ (21) 15 17 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $2, $2, and $0, respectively) (1) 2 3 - 5 Amortization of net actuarial loss (net of taxes of $1, $0, and $0, respectively) (1) 2 - - 2 Regulatory account transfer (net of taxes of $3, $2, and $0, respectively) (1) (4) (3) - (7) 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.) |
Regulatory Assets, Liabilitie20
Regulatory Assets, Liabilities, And Balancing Accounts (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Long-Term Regulatory Assets | Balance at March 31, December 31, (in millions) 2016 2015 Pension benefits $ 2,414 $ 2,414 Deferred income taxes 3,265 3,054 Utility retained generation 399 411 Environmental Compliance Costs 683 748 Price risk management 134 138 Unamortized loss, net of gain, on reacquired debt 90 94 Other 145 170 Total long-term regulatory assets $ 7,130 $ 7,029 |
Long-Term Regulatory Liabilities | Balance at March 31, December 31, (in millions) 2016 2015 Cost of removal obligations $ 4,717 $ 4,605 Recoveries in excess of asset retirement obligations 645 631 Public purpose programs 620 600 Other 504 485 Total long-term regulatory liabilities $ 6,486 $ 6,321 |
Regulatory Balancing Accounts Receivable | Receivable Balance at March 31, December 31, (in millions) 2016 2015 Electric distribution $ 515 $ 380 Utility generation 225 122 Gas distribution 280 493 Energy procurement 87 262 Public purpose programs 149 155 Other 465 348 Total regulatory balancing accounts receivable $ 1,721 $ 1,760 |
Regulatory Balancing Accounts Payable | Payable Balance at March 31, December 31, (in millions) 2016 2015 Energy procurement $ 184 $ 112 Public purpose programs 212 244 Other 308 359 Total regulatory balancing accounts payable $ 704 $ 715 |
Debt (Tables)
Debt (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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) 33 443 2,524 Total revolving credit facilities $ 3,300 $ 33 $ 443 $ 2,824 (1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. (2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. |
Equity (Tables)
Equity (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Changes In Equity | PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2015 $ 16,828 $ 17,060 Comprehensive income 110 108 Equity contributions - 65 Common stock issued 152 - Share-based compensation 6 - Common stock dividends declared (229) (179) Preferred stock dividend requirement - (3) Preferred stock dividend requirement of subsidiary (3) - Balance at March 31, 2016 $ 16,864 $ 17,051 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted | Three Months Ended March 31, (in millions, except per share amounts) 2016 2015 Income available for common shareholders $ 107 $ 31 Weighted average common shares outstanding, basic 493 477 Add incremental shares from assumed conversions: Employee share-based compensation 2 4 Weighted average common shares outstanding, diluted 495 481 Total earnings per common share, diluted $ 0.22 $ 0.06 |
Derivatives (Tables)
Derivatives (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Volumes Of Outstanding Derivative Contracts | Contract Volume at March 31, December 31, Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards and Swaps 341,884,852 333,091,813 Options 92,426,200 111,550,004 Electricity (Megawatt-hours) Forwards and Swaps 3,580,205 3,663,512 Congestion Revenue Rights (3) 198,499,963 216,383,389 (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 March 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (5) $ 12 $ 98 Other noncurrent assets – other 173 (5) - 168 Current liabilities – other (105) 5 46 (54) Noncurrent liabilities – other (139) 5 16 (118) Net commodity risk $ 20 $ - $ 74 $ 94 At December 31, 2015 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 97 (4) 25 $ 118 Other noncurrent assets – other 172 (2) - 170 Current liabilities – other (102) 4 44 (54) Noncurrent liabilities – other (140) 2 21 (117) Net commodity risk $ 27 $ - $ 90 $ 117 |
Gains And Losses On Derivative Instruments | Commodity Risk Three Months Ended March 31, (in millions) 2016 2015 Net unrealized gain (loss) - regulatory assets and liabilities (1) $ (7) $ (52) Realized loss - cost of electricity (2) (29) (7) Realized loss - cost of natural gas (2) (1) (1) Total commodity risk $ (37) $ (60) (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 March 31, December 31, (in millions) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (9) $ (2) Collateral posting in the normal course of business related to these derivatives 7 - Net position of derivative contracts/additional collateral posting requirements (1) $ (2) $ (2) (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) | 3 Months Ended |
Mar. 31, 2016 | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | Fair Value Measurements At March 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 97 $ - $ - $ - $ 97 Nuclear decommissioning trusts Short-term investments 25 - - - 25 Global equity securities 1,619 - - - 1,619 Fixed-income securities 682 508 - - 1,190 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,326 508 - - 2,847 Price risk management instruments (Note 7) Electricity 1 12 246 3 262 Gas 2 3 - (1) 4 Total price risk management instruments 3 15 246 2 266 Rabbi trusts Fixed-income securities - 58 - - 58 Life insurance contracts - 72 - - 72 Total rabbi trusts - 130 - - 130 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 147 Total long-term disability trust 8 - - - 155 Total assets $ 2,434 $ 653 $ 246 $ 2 $ 3,495 Liabilities: Price risk management instruments (Note 7) Electricity $ 67 $ 5 $ 171 $ (72) $ 171 Gas - 1 - - 1 Total liabilities $ 67 $ 6 $ 171 $ (72) $ 172 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 331 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2015 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 64 $ - $ - $ - $ 64 Nuclear decommissioning trusts Short-term investments 36 - - - 36 Global equity securities 1,520 - - - 1,520 Fixed-income securities 694 521 - - 1,215 Assets measured at NAV - - - - 13 Total nuclear decommissioning trusts (2) 2,250 521 - - 2,784 Price risk management instruments (Note 9 in the 2015 Form 10-K) Electricity - 9 259 18 286 Gas - 1 - 1 2 Total price risk management instruments - 10 259 19 288 Rabbi trusts Fixed-income securities - 57 - - 57 Life insurance contracts - 70 - - 70 Total rabbi trusts - 127 - - 127 Long-term disability trust Short-term investments 7 - - - 7 Assets measured at NAV - - - - 158 Total long-term disability trust 7 - - - 165 Total assets $ 2,321 $ 658 $ 259 $ 19 $ 3,428 Liabilities: Price risk management instruments (Note 9 in the 2015 Form 10-K) Electricity $ 69 $ 1 $ 170 $ (70) $ 170 Gas - 2 - (1) 1 Total liabilities $ 69 $ 3 $ 170 $ (71) $ 171 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. |
Level 3 Measurements And Sensitivity Analysis | Fair Value at (in millions) At March 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 246 $ 59 Market approach CRR auction prices $ (23.81) - 8.76 Power purchase agreements $ - $ 112 Discounted cash flow Forward prices $ 17.64 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2015 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 259 $ 63 Market approach CRR auction prices $ (161.36) - 8.76 Power purchase agreements $ - $ 107 Discounted cash flow Forward prices $ 15.08 - 37.27 (1) Represents price per megawatt-hour |
Level 3 Reconciliation | Price Risk Management Instruments (in millions) 2016 2015 Asset (liability) balance as of January 1 $ 89 $ 69 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (14) (27) Asset (liability) balance as of March 31 $ 75 $ 42 (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 March 31, 2016 At December 31, 2015 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 350 $ 356 $ 350 $ 354 Utility 15,412 17,823 14,918 16,422 |
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 March 31, 2016 Nuclear decommissioning trusts Short-term investments $ 25 $ - $ - $ 25 Global equity securities 603 1,038 (9) 1,632 Fixed-income securities 1,113 81 (4) 1,190 Total (1) $ 1,741 $ 1,119 $ (13) $ 2,847 As of December 31, 2015 Nuclear decommissioning trusts Short-term investments $ 36 $ - $ - $ 36 Global equity securities 508 1,034 (9) 1,533 Fixed-income securities 1,165 58 (8) 1,215 Total (1) $ 1,709 $ 1,092 $ (17) $ 2,784 (1) Represents amounts before deducting $ 331 million and $314 million at March 31, 2016 and December 31, 2015 , respectively, primarily related to deferred taxes on appreciation of investment value. |
Schedule Of Maturities On Debt Instruments | As of (in millions) March 31, 2016 Less than 1 year $ 26 1–5 years 409 5–10 years 251 More than 10 years 504 Total maturities of fixed-income securities $ 1,190 |
Schedule Of Activity For Debt And Equity Securities | Three Months Ended March 31, 2016 March 31, 2015 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 439 417 Gross realized gains on sales of securities held as available-for-sale 5 35 Gross realized losses on sales of securities held as available-for-sale (2) (3) |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Impact Of The Penalty Decision | Three Months Cumulative Future Ended Charges Charges March 31, March 31, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit - 400 - 400 Charge for disallowed capital (1) 87 494 195 689 Disallowed revenue for pipeline safety expenses (2) - - 161 161 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 87 $ 1,194 $ 356 $ 1,600 (1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will identify in a final decision to be issued in the Utility’s 2015 GT&S rate case. The Penalty Decision requires that at least $689 million of the $850 million cost disallowance be allocated to capital expenditures. The Utility estimates that approximately $494 million of cumulative capital spending is probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision. (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 and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred. |
Schedule Of Environmental Remediation Liability | Balance at March 31, December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 302 $ 300 Hinkley natural gas compressor station (1) 140 140 Former manufactured gas plant sites owned by the Utility or third parties 283 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 136 164 Fossil fuel-fired generation facilities and sites 103 94 Total environmental remediation liability $ 964 $ 969 (1) See “Natural Gas Compressor Station Sites” below. |
New And Significant Accountin27
New And Significant Accounting Policies (Narrative) (Details) - Asset Retirement Obligation Costs [Member] - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total nuclear decommissioning asset retirement obligation | $ 3,300 | $ 2,500 |
Adjustment to nuclear decommissioning cost estimates | 818 | |
Adjustment to undiscounted nuclear decommissioning cost estimates | 1,400 | |
Total undiscounted nuclear decommissioning cost estimates | $ 4,800 |
New And Significant Accountin28
New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | $ 113 | $ 119 | |
Interest cost | 179 | 168 | |
Expected return on plan assets | (207) | (218) | |
Amortization of prior service cost | 2 | 4 | |
Amortization of net actuarial loss | 6 | 3 | |
Net periodic benefit cost | 93 | 76 | |
Less: transfer to regulatory account | [1] | (8) | 9 |
Total | 85 | 85 | |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service cost for benefits earned | 13 | 13 | |
Interest cost | 19 | 18 | |
Expected return on plan assets | (27) | (28) | |
Amortization of prior service cost | 4 | 5 | |
Amortization of net actuarial loss | 1 | 1 | |
Net periodic benefit cost | 10 | 9 | |
Less: transfer to regulatory account | [1] | 0 | 0 |
Total | $ 10 | $ 9 | |
[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 | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Beginning balance | $ (7) | $ 11 | |
Change in investments | 0 | (17) | |
Net current period other comprehensive income (loss) | 0 | (17) | |
Ending balance | (7) | (6) | |
Net change in investments tax | 0 | 12 | |
Net actuarial loss tax | 0 | 0 | |
Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Amortization of prior service cost | [1] | 3 | 5 |
Amortization of net actuarial loss | [1] | 5 | 2 |
Regulatory account transfer | [1] | (8) | (7) |
Change in investments | (17) | ||
Pension Benefits [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Beginning balance | (23) | (21) | |
Amortization of prior service cost | 2 | 4 | |
Amortization of net actuarial loss | 6 | 3 | |
Net current period other comprehensive income (loss) | 0 | 0 | |
Ending balance | (23) | (21) | |
Pension Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Amortization of prior service cost | [1] | 1 | 2 |
Amortization of net actuarial loss | [1] | 4 | 2 |
Regulatory account transfer | [1] | (5) | (4) |
Change in investments | 0 | ||
Amortization of prior service cost tax | 1 | 2 | |
Net actuarial loss tax | 2 | 1 | |
Regulatory account transfer tax | 3 | 3 | |
Other Benefits [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Beginning balance | 16 | 15 | |
Amortization of prior service cost | 4 | 5 | |
Amortization of net actuarial loss | 1 | 1 | |
Net current period other comprehensive income (loss) | 0 | 0 | |
Ending balance | 16 | 15 | |
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 |
Amortization of net actuarial loss | [1] | 1 | 0 |
Regulatory account transfer | [1] | (3) | (3) |
Change in investments | 0 | ||
Amortization of prior service cost tax | 2 | 2 | |
Regulatory account transfer tax | 2 | 2 | |
Other Investments [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Beginning balance | 17 | ||
Net current period other comprehensive income (loss) | (17) | ||
Ending balance | 0 | ||
Other Investments [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | |||
Accumulated Other Comprehensive Income Loss [Line Items] | |||
Amortization of prior service cost | [1] | 0 | |
Amortization of net actuarial loss | [1] | 0 | |
Regulatory account transfer | [1] | 0 | |
Change in investments | (17) | ||
Change in investments tax | $ 0 | $ 12 | |
[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 | Mar. 31, 2016 | Dec. 31, 2015 |
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 7,130 | $ 7,029 |
Pension Benefits [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,414 | 2,414 |
Deferred Income Taxes [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 3,265 | 3,054 |
Utility Retained Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 399 | 411 |
Environmental Compliance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 683 | 748 |
Price Risk Management [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 134 | 138 |
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 90 | 94 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 145 | $ 170 |
Regulatory Assets, Liabilitie31
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 6,486 | $ 6,321 |
Cost Of Removal Obligations [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 4,717 | 4,605 |
Recoveries In Excess Of AROs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 645 | 631 |
Public Purpose Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 620 | 600 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 504 | $ 485 |
Regulatory Assets, Liabilitie32
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 1,721 | $ 1,760 |
Regulatory Balancing Accounts Receivable [Member] | Electric distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 515 | 380 |
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 225 | 122 |
Regulatory Balancing Accounts Receivable [Member] | Gas distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 280 | 493 |
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 87 | 262 |
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 149 | 155 |
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 465 | 348 |
Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 704 | 715 |
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 184 | 112 |
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 212 | 244 |
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 308 | $ 359 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) $ in Millions | Mar. 31, 2016USD ($) |
Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | |
Debt [Line Items] | |
Debt instrument, face amount | $ 614 |
Pollution Control Bonds Series 2009 A-D [Member] | |
Debt [Line Items] | |
Debt instrument, face amount | $ 309 |
Minimum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.37% |
Minimum [Member] | Pollution Control Bonds Series 2009 A-D [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.34% |
Maximum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.45% |
Maximum [Member] | Pollution Control Bonds Series 2009 A-D [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.38% |
Utility [Member] | |
Debt [Line Items] | |
Floating rate unsecured term loan, due 2017 | $ 250 |
Utility [Member] | Senior Notes, 3.50%, Due 2025 [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 2.95% |
Senior Notes | $ 600 |
Debt (Schedule Of Line Of Credi
Debt (Schedule Of Line Of Credit) (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2016USD ($) | ||
Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2020 | |
Letters of Credit Sublimit | $ 500 | |
Swingline Loans Sublimit | 75 | |
Utility [Member] | ||
Debt [Line Items] | ||
Facility limit | 3,000 | [1] |
Letters Of Credit Outstanding Amount | 33 | |
Commercial Paper | 443 | |
Facility Availability | $ 2,524 | |
P G E Corporation [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2020 | |
Facility limit | $ 300 | [2] |
Letters Of Credit Outstanding Amount | 0 | |
Commercial Paper | 0 | |
Facility Availability | 300 | |
Letters of Credit Sublimit | 50 | |
Swingline Loans Sublimit | $ 100 | |
Swingline Loan Repay Term | 7 days | |
Credit Facilities [Member] | ||
Debt [Line Items] | ||
Facility limit | $ 3,300 | |
Letters Of Credit Outstanding Amount | 33 | |
Commercial Paper | 443 | |
Facility Availability | $ 2,824 | |
[1] | Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans. | |
[2] | Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days. |
Equity (Narrative) (Detail)
Equity (Narrative) (Detail) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | |
Common Stock Value | $ 11,440 | $ 11,282 |
Pacific Gas And Electric Company [Member] | ||
Common Stock Value | $ 1,322 | $ 1,322 |
Equity Contract [Member] | ||
Equity Distribution Agreement, shares issued | 1,300,000 | |
Remaining equity distribution agreement amount | $ 350 | |
Fees and commissions | 1 | |
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 | 2,300,000 | |
Stock Issued During Period Value Stock Options Exercised | $ 72 |
Equity (Changes In Equity) (Det
Equity (Changes In Equity) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Balance at December 31, 2014 | $ 16,576 | |
Balance at December 31, 2014 | 16,828 | |
Comprehensive Income Net Of Tax | 110 | $ 17 |
Common stock issued | 152 | |
Share-based compensation | 6 | |
Common stock dividends declared | (229) | |
Preferred stock dividend requirement of subsidiary | (3) | (3) |
Balance at September 30, 2015 | 16,864 | |
Balance at September 30, 2015 | 16,612 | |
Pacific Gas And Electric Company [Member] | ||
Balance at December 31, 2014 | 17,060 | |
Comprehensive Income Net Of Tax | 108 | 4 |
Common stock issued | 0 | |
Share-based compensation | 0 | |
Common stock dividends declared | (179) | |
Preferred stock dividend requirement | (3) | (3) |
Equity contributions | 65 | $ 100 |
Balance at September 30, 2015 | $ 17,051 |
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 | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Income available for common shareholders | $ 107 | $ 31 |
Weighted average common shares outstanding, basic | 493 | 477 |
Employee share-based compensation | 2 | 4 |
Weighted average common shares outstanding, diluted | 495 | 481 |
Total earnings per common share, diluted | $ 0.22 | $ 0.06 |
Derivatives (Volumes Of Outstan
Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details) | Mar. 31, 2016 | Dec. 31, 2015 | |
Forwards And Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 341,884,852 | 333,091,813 |
Forwards And Swaps [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | 3,580,205 | 3,663,512 | |
Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 92,426,200 | 111,550,004 |
Congestion Revenue Rights [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [3] | 198,499,963 | 216,383,389 |
[1] | Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios. | ||
[2] | Million British Thermal Units. | ||
[3] | CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations. |
Derivatives (Outstanding Deriva
Derivatives (Outstanding Derivative Balances) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Other Current Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 91 | $ 97 |
Cash Collateral | 12 | 25 |
Total Derivative Balance | 98 | 118 |
Netting | (5) | (4) |
Other Noncurrent Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 173 | 172 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 168 | 170 |
Netting | (5) | (2) |
Other Current Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (105) | (102) |
Cash Collateral | 46 | 44 |
Total Derivative Balance | (54) | (54) |
Netting | 5 | 4 |
Other Noncurrent Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (139) | (140) |
Cash Collateral | 16 | 21 |
Total Derivative Balance | (118) | (117) |
Netting | 5 | 2 |
Gross Derivative Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 20 | 27 |
Netting [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 0 | 0 |
Cash Collateral [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Cash Collateral | 74 | 90 |
Total Derivatve Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Derivative Balance | $ 94 | $ 117 |
Derivatives (Gains And Losses O
Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Unrealized gain (loss) - regulatory assets and liabilities | [1] | $ (7) | $ (52) |
Realized gain (loss) - cost of electricity | [2] | (29) | (7) |
Realized loss - cost of natural gas | [2] | (1) | (1) |
Net commodity risk | $ (37) | $ (60) | |
[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 | Mar. 31, 2016 | Dec. 31, 2015 | |
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized | $ (9) | $ (2) | |
Collateral posting in the normal course of business related to these derivatives | 7 | 0 | |
Net position of derivative contracts/additional collateral posting requirements | [1] | $ (2) | $ (2) |
[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 | Mar. 31, 2016 | Dec. 31, 2015 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | $ 97 | $ 64 | |||
Total assets | 3,495 | 3,428 | |||
Electricity | 171 | 170 | |||
Natural Gas | 1 | 1 | |||
Total liabilities | 172 | 171 | |||
Amount primarily related to deferred taxes on appreciation of investment value | 331 | 314 | |||
Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 25 | 36 | |||
Total assets | 2,847 | [1] | 2,784 | [2] | |
Fixed-income securities | 1,190 | 1,215 | |||
Global equity securities | 1,619 | 1,520 | |||
Financial Instruments Measured At NAV | 13 | 13 | |||
Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 266 | 288 | |||
Electricity | 262 | 286 | |||
Natural Gas | 4 | 2 | |||
Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 130 | 127 | |||
Fixed-income securities | 58 | 57 | |||
Life insurance contracts | 72 | 70 | |||
Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 8 | 7 | |||
Total assets | 155 | 165 | |||
Financial Instruments Measured At NAV | 147 | 158 | |||
Fair Value Measurements, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 97 | 64 | |||
Total assets | 2,434 | 2,321 | |||
Total liabilities | 67 | 69 | |||
Fair Value Measurements, Level 1 [Member] | Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 25 | 36 | |||
Total assets | 2,326 | [1] | 2,250 | [2] | |
Fixed-income securities | 682 | 694 | |||
Global equity securities | 1,619 | 1,520 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Fair Value Measurements, Level 1 [Member] | Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 3 | 0 | |||
Electricity | 1 | 0 | |||
Natural Gas | 2 | 0 | |||
Electricity | 67 | 69 | |||
Natural Gas | 0 | 0 | |||
Fair Value Measurements, Level 1 [Member] | Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 0 | 0 | |||
Fixed-income securities | 0 | 0 | |||
Life insurance contracts | 0 | 0 | |||
Fair Value Measurements, Level 1 [Member] | Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 8 | 7 | |||
Total assets | 8 | 7 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Fair Value Measurements, Level 2 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 653 | 658 | |||
Total liabilities | 6 | 3 | |||
Fair Value Measurements, Level 2 [Member] | Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 508 | [1] | 521 | [2] | |
Fixed-income securities | 508 | 521 | |||
Global equity securities | 0 | 0 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Fair Value Measurements, Level 2 [Member] | Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 15 | 10 | |||
Electricity | 12 | 9 | |||
Natural Gas | 3 | 1 | |||
Electricity | 5 | 1 | |||
Natural Gas | 1 | 2 | |||
Fair Value Measurements, Level 2 [Member] | Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 130 | 127 | |||
Fixed-income securities | 58 | 57 | |||
Life insurance contracts | 72 | 70 | |||
Fair Value Measurements, Level 2 [Member] | Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | 0 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Fair Value Measurements, Level 3 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 246 | 259 | |||
Total liabilities | 171 | 170 | |||
Fair Value Measurements, Level 3 [Member] | Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | [1] | 0 | [2] | |
Fixed-income securities | 0 | 0 | |||
Global equity securities | 0 | 0 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Fair Value Measurements, Level 3 [Member] | Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 246 | 259 | |||
Electricity | 246 | 259 | |||
Natural Gas | 0 | 0 | |||
Electricity | 171 | 170 | |||
Natural Gas | 0 | 0 | |||
Fair Value Measurements, Level 3 [Member] | Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 0 | 0 | |||
Fixed-income securities | 0 | 0 | |||
Life insurance contracts | 0 | 0 | |||
Fair Value Measurements, Level 3 [Member] | Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 0 | |||
Total assets | 0 | 0 | |||
Financial Instruments Measured At NAV | 0 | 0 | |||
Netting [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | [3] | 0 | 0 | ||
Total assets | [3] | 2 | 19 | ||
Total liabilities | [3] | (72) | (71) | ||
Netting [Member] | Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | [3] | 0 | 0 | ||
Total assets | [3] | 0 | [1] | 0 | [2] |
Fixed-income securities | [3] | 0 | 0 | ||
Global equity securities | [3] | 0 | 0 | ||
Financial Instruments Measured At NAV | [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] | 2 | 19 | ||
Electricity | [3] | 3 | 18 | ||
Natural Gas | [3] | (1) | 1 | ||
Electricity | [3] | (72) | (70) | ||
Natural Gas | [3] | 0 | (1) | ||
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] | |||||
Short-term investments | [3] | 0 | 0 | ||
Total assets | [3] | 0 | 0 | ||
Financial Instruments Measured At NAV | [3] | $ 0 | $ 0 | ||
[1] | Represents amount before deducting $331 million, primarily related to deferred taxes on appreciation of investment value. | ||||
[2] | Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. | ||||
[3] | Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. |
Fair Value Measurements (Level
Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 3,495 | $ 3,428 | |
Liabilities, Fair Value | $ 172 | 171 | |
Fair value measurement Valuation technique | Market approach | ||
Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 246 | 259 | |
Liabilities, Fair Value | $ 59 | $ 63 | |
Fair value measurement Valuation technique | 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 | $ 112 | $ 107 | |
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] | (23.81) | (161.36) |
Minimum [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 17.64 | 15.08 |
Maximum [Member] | Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 8.76 | 8.76 |
Maximum [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 38.8 | 37.27 |
[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 | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Beginning asset (liability) balance | $ 89 | $ 69 | |
Included in regulatory assets and liabilities or balancing accounts | [1] | (14) | (27) |
Ending asset (liability) balance | $ 75 | $ 42 | |
[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 | Mar. 31, 2016 | Dec. 31, 2015 |
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 | $ 17,823 | $ 16,422 |
Pacific Gas And Electric Company [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | 15,412 | 14,918 |
P G E Corporation [Member] | Fair Value Measurements, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | 356 | 354 |
P G E Corporation [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | $ 350 | $ 350 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | ||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | [1] | $ 1,741 | $ 1,709 |
Total Unrealized Gains | [1] | 1,119 | 1,092 |
Total Unrealized Losses | [1] | (13) | (17) |
Total Fair Value | [1] | 2,847 | 2,784 |
Amount primarily related to deferred taxes on appreciation of investment value | 331 | 314 | |
Money Market Investments [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 25 | 36 | |
Total Unrealized Gains | 0 | 0 | |
Total Unrealized Losses | 0 | 0 | |
Total Fair Value | 25 | 36 | |
Other Fixed-Income Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 1,113 | 1,165 | |
Total Unrealized Gains | 81 | 58 | |
Total Unrealized Losses | (4) | (8) | |
Total Fair Value | 1,190 | 1,215 | |
Global equity securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Amortized Cost | 603 | 508 | |
Total Unrealized Gains | 1,038 | 1,034 | |
Total Unrealized Losses | (9) | (9) | |
Total Fair Value | $ 1,632 | $ 1,533 | |
[1] | Represents amounts before deducting $331 million and $314 million at March 31, 2016 and December 31, 2015, 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 | Mar. 31, 2016USD ($) |
Less than 1 year | $ 26 |
1-5 years | 409 |
5-10 years | 251 |
More than 10 years | 504 |
Total maturities of fixed-income securities | $ 1,190 |
Fair Value Measurements (Sche48
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 439 | $ 417 |
Gross realized gains on sales of securities held as available-for-sale | 5 | 35 |
Gross realized losses on sales of securities held as available-for-sale | $ (2) | $ (3) |
Commitments And Contingencies49
Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Long-term Purchase Commitment [Line Items] | |
Total | $ 50,000 |
Commitments And Contingencies50
Commitments And Contingencies (Impact Of Penalty Decision) (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | ||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | $ 0 | ||
Customer bill credit | 0 | ||
Charge for disallowed capital | 87 | $ 53 | |
Total Penalty Decision Fines And Remedies | 87 | ||
CPUC estimated cost of other remedies | [1] | 0 | |
Disallowed Revenue For Pipeline Safety Expenses | [2] | 0 | |
Total Penalty Decision [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | 300 | ||
Customer bill credit | 400 | ||
Charge for disallowed capital | [3] | 689 | |
Total Penalty Decision Fines And Remedies | 1,600 | ||
CPUC estimated cost of other remedies | [1] | 50 | |
Disallowed Revenue For Pipeline Safety Expenses | [2] | 161 | |
Penalty Decision Cumulative Charges [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | 300 | ||
Customer bill credit | 400 | ||
Charge for disallowed capital | [3] | 494 | |
Total Penalty Decision Fines And Remedies | 1,194 | ||
CPUC estimated cost of other remedies | [1] | 0 | |
Disallowed Revenue For Pipeline Safety Expenses | [2] | 0 | |
Penalty Decision Future Charges and Costs [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | 0 | ||
Customer bill credit | 0 | ||
Charge for disallowed capital | [3] | 195 | |
Total Penalty Decision Fines And Remedies | 356 | ||
CPUC estimated cost of other remedies | [1] | 0 | |
Disallowed Revenue For Pipeline Safety Expenses | [2] | 161 | |
Pacific Gas And Electric Company [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Charge for disallowed capital | $ 87 | $ 53 | |
[1] | In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision and does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs are being expensed as incurred. | ||
[2] | These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses. | ||
[3] | The Penalty Decision disallows the Utility from recovering $850 million in costs 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 Penalty Decision requires that at least $689 million of the $850 million cost disallowance be allocated to capital expenditures. The Utility estimates that approximately $494 million of cumulative capital spending is 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 | |
Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Loss Contingencies [Line Items] | ||
Unrecognized Tax Benefits | $ 70,000 | |
CPUC Disallowed Future Spending | 850,000 | |
SED Maximum Statutory Penalty Per Violaiton | $ 50 | |
Butte Fire [Member] | ||
Loss Contingencies [Line Items] | ||
Number of plaintiffs | 1,300 | |
Loss Contingency Range Of Possible Loss Minimum | $ 350,000 | |
Number of complaints filed against utility | 32 | |
Fire Fighting Costs Recovery Requested By Cal Fire | $ 90,000 | |
Natural Gas Distribution Facilities Record Keeping OII [Member] | ||
Loss Contingencies [Line Items] | ||
SED recommended penalty | 112,000 | |
City of Carmel Recommended Penalty | 652,000 | |
Portion of Carmel Recommended Penalty Related to Carmel Explosion | 137,000 | |
Utility Recommended Maximum Penalty | $ 33,600 | |
Number of days until Presiding Officer Decision Expected from Filing Date | 60 days | |
Number Of Days From Presising Officer Decision Until Decision Is Final If No Appeals | 30 days | |
Criminal investigation [Member] | ||
Loss Contingencies [Line Items] | ||
Total maximum statutory penalties | $ 6,500 | |
CAISO And PX [Member] | ||
Loss Contingencies [Line Items] | ||
Disputed Claims Liability Balance | $ 454,000 | |
Other Receivables Disputed Claims | 228,000 | |
CAISO And PX [Member] | Joint Offer Of Settlement [Member] | ||
Loss Contingencies [Line Items] | ||
Settlement Refund | 256,000 | |
Ex Parte Communications [Member] | ||
Loss Contingencies [Line Items] | ||
California Public Utilities Commission Imposed Penalty Per Day Per Violation | $ 50 | |
Ex Parte Communication Count Already Included in OII | 46 | |
Additional Ex Parte Communication Count | 113 | |
Ex Parte Communication to be Considered in Briefing | 21 | |
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 | |
Pipeline Saftey Enhancement Plan [Member] | ||
Loss Contingencies [Line Items] | ||
Capitalized PSEP costs | 1,300,000 | |
Cummulative unrecoverable PSEP capital costs | 665,000 | |
CPUC Authorized For Recovery PSEP Capital Costs | 766,000 | |
Pacific Gas And Electric Company [Member] | Natural Gas Distribution Facilities Record Keeping OII [Member] | ||
Loss Contingencies [Line Items] | ||
CPUC Imposed Penalty | 10,850 | |
Pacific Gas And Electric Company [Member] | Criminal investigation [Member] | ||
Loss Contingencies [Line Items] | ||
Statutory penalty for each count of alleged violation | 500 | |
Gross Gain Derived From Alleged Violation | 281,000 | |
Maximum Alternative Fine Sought | $ 562,000 | |
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] | Criminal investigation [Member] | Dismissed Criminal Indictment Counts [Member] | ||
Loss Contingencies [Line Items] | ||
Number of felony counts | 15 | |
Pacific Gas And Electric Company [Member] | Criminal investigation [Member] | Remaining Criminal Indictment Counts [Member] | ||
Loss Contingencies [Line Items] | ||
Number of felony counts | 12 | |
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 | |
Utility [Member] | ||
Loss Contingencies [Line Items] | ||
Accrued legal liabilities | $ 55,000 | $ 63,000 |
Commitments And Contingencies52
Commitments And Contingencies (Nuclear Insurance) (Details) - Diablo Canyon [Member] $ in Thousands | 3 Months Ended |
Mar. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Maximum Aggregate Annual Retrospective Premium Obligation | $ 60,000 |
EMANI Policy Limit | 200,000 |
EMANI Possible Retrospective Assesment | $ 2,100 |
Commitments And Contingencies53
Commitments And Contingencies (Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 | |
Topock natural gas compressor station | [1] | $ 302 | $ 300 |
Hinkley natural gas compressor station | [1] | 140 | 140 |
Former manufactured gas plant sites owned by the Utility or third parties | 283 | 271 | |
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites | 136 | 164 | |
Fossil fuel-fired generation facilities and sites | 103 | 94 | |
Total environmental remediation liability | $ 964 | $ 969 | |
[1] | See "Natural Gas Compressor Station Sites" below. |
Commitments And Contingencies54
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions | Mar. 31, 2016USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 680 |
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute | $ 1,900 |