Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 24, 2016 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Trading Symbol | PCG | |
Entity Registrant Name | PG&E CORP | |
Entity Central Index Key | 1,004,980 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 505,666,694 | |
Pacific Gas And Electric Company [Member] | ||
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Trading Symbol | PCG | |
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | |
Entity Central Index Key | 75,488 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 264,374,809 |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Operating Revenues | ||||
Electric | $ 3,994 | $ 3,868 | $ 10,590 | $ 10,344 |
Natural gas | 816 | 682 | 2,363 | 2,322 |
Total operating revenues | 4,810 | 4,550 | 12,953 | 12,666 |
Operating Expenses | ||||
Cost of electricity | 1,613 | 1,681 | 3,719 | 3,958 |
Cost of natural gas | 80 | 50 | 377 | 442 |
Operating and maintenance | 1,783 | 1,621 | 5,631 | 5,028 |
Depreciation, amortization, and decommissioning | 694 | 653 | 2,090 | 1,935 |
Total operating expenses | 4,170 | 4,005 | 11,817 | 11,363 |
Operating Income | 640 | 545 | 1,136 | 1,303 |
Interest income | 8 | 2 | 17 | 6 |
Interest expense | (211) | (194) | (621) | (575) |
Other income, net | 24 | 24 | 74 | 100 |
Income Before Income Taxes | 461 | 377 | 606 | 834 |
Income tax provision (benefit) | 70 | 67 | (105) | 84 |
Net Income | 391 | 310 | 711 | 750 |
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 |
Income Available for Common Shareholders | $ 388 | $ 307 | $ 701 | $ 740 |
Weighted Average Common Shares Outstanding, Basic | 501 | 486 | 497 | 481 |
Weighted Average Common Shares Outstanding, Diluted | 503 | 489 | 500 | 484 |
Net Earnings Per Common Share, Basic | $ 0.77 | $ 0.63 | $ 1.41 | $ 1.54 |
Net Earnings Per Common Share, Diluted | 0.77 | 0.63 | 1.40 | 1.53 |
Dividends Declared Per Common Share | $ 0.49 | $ 0.46 | $ 1.44 | $ 1.37 |
Pacific Gas And Electric Company [Member] | ||||
Operating Revenues | ||||
Electric | $ 3,993 | $ 3,868 | $ 10,590 | $ 10,344 |
Natural gas | 816 | 682 | 2,363 | 2,322 |
Total operating revenues | 4,809 | 4,550 | 12,953 | 12,666 |
Operating Expenses | ||||
Cost of electricity | 1,613 | 1,681 | 3,719 | 3,958 |
Cost of natural gas | 80 | 50 | 377 | 442 |
Operating and maintenance | 1,782 | 1,622 | 5,630 | 5,028 |
Depreciation, amortization, and decommissioning | 694 | 653 | 2,090 | 1,935 |
Total operating expenses | 4,169 | 4,006 | 11,816 | 11,363 |
Operating Income | 640 | 544 | 1,137 | 1,303 |
Interest income | 8 | 2 | 16 | 6 |
Interest expense | (209) | (191) | (614) | (567) |
Other income, net | 23 | 22 | 68 | 68 |
Income Before Income Taxes | 462 | 377 | 607 | 810 |
Income tax provision (benefit) | 73 | 72 | (99) | 95 |
Net Income | 389 | 305 | 706 | 715 |
Preferred stock dividend requirement | 3 | 3 | 10 | 10 |
Income Available for Common Shareholders | $ 386 | $ 302 | $ 696 | $ 705 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Net income | $ 391 | $ 310 | $ 711 | $ 750 |
Other Comprehensive Income | ||||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 0 | 0 | 0 | 0 |
Net change in investments (net of taxes of $0, $0, $0, and $12, at respective dates) | 0 | 0 | 0 | (17) |
Total other comprehensive income (loss) | 0 | 0 | 0 | (17) |
Comprehensive Income | 391 | 310 | 711 | 733 |
Preferred stock dividend requirement of subsidiary | 3 | 3 | 10 | 10 |
Comprehensive Income Attributable to Common Shareholders | 388 | 307 | 701 | 723 |
Pacific Gas And Electric Company [Member] | ||||
Net income | 389 | 305 | 706 | 715 |
Other Comprehensive Income | ||||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 0 | 0 | 1 | 0 |
Total other comprehensive income (loss) | 0 | 0 | 1 | 0 |
Comprehensive Income | $ 389 | $ 305 | $ 707 | $ 715 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Net change in investments tax | 0 | 0 | 0 | 12 |
Pacific Gas And Electric Company [Member] | ||||
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and cash equivalents | $ 71 | $ 123 |
Restricted cash | 168 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $53 and $54 at respective dates) | 1,233 | 1,106 |
Accrued unbilled revenue | 956 | 855 |
Regulatory balancing accounts | 1,475 | 1,760 |
Other | 475 | 286 |
Regulatory assets | 370 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 134 | 126 |
Materials and supplies | 343 | 313 |
Income taxes receivable | 218 | 155 |
Other | 306 | 338 |
Total current assets | 5,749 | 5,813 |
Property, Plant, and Equipment | ||
Electric | 51,532 | 48,532 |
Gas | 17,384 | 16,749 |
Construction work in progress | 2,117 | 2,059 |
Other | 2 | 2 |
Total property, plant, and equipment | 71,035 | 67,342 |
Accumulated depreciation | (21,605) | (20,619) |
Net property, plant, and equipment | 49,430 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,534 | 7,029 |
Nuclear decommissioning trusts | 2,597 | 2,470 |
Income taxes receivable | 70 | 135 |
Other | 1,185 | 1,064 |
Total other noncurrent assets | 11,386 | 10,698 |
TOTAL ASSETS | 66,565 | 63,234 |
Current Liabilities | ||
Short-term borrowings | 1,145 | 1,019 |
Long-term debt, classified as current | 160 | 160 |
Accounts payable | ||
Trade creditors | 1,370 | 1,414 |
Regulatory balancing accounts | 764 | 715 |
Other | 496 | 398 |
Disputed claims and customer refunds | 233 | 454 |
Interest payable | 144 | 206 |
Other | 1,958 | 1,997 |
Total current liabilities | 6,270 | 6,363 |
Noncurrent Liabilities | ||
Long-term debt | 16,528 | 15,925 |
Regulatory liabilities | 6,613 | 6,321 |
Pension and other postretirement benefits | 2,632 | 2,622 |
Asset retirement obligations | 4,672 | 3,643 |
Deferred income taxes | 9,850 | 9,206 |
Other | 2,394 | 2,326 |
Total noncurrent liabilities | 42,689 | 40,043 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Common stock | 12,083 | 11,282 |
Reinvested earnings | 5,278 | 5,301 |
Accumulated other comprehensive income (loss) | (7) | (7) |
Total shareholders' equity | 17,354 | 16,576 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 17,606 | 16,828 |
TOTAL LIABILITIES AND EQUITY | 66,565 | 63,234 |
Pacific Gas And Electric Company [Member] | ||
Current Assets | ||
Cash and cash equivalents | 68 | 59 |
Restricted cash | 168 | 234 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $53 and $54 at respective dates) | 1,233 | 1,106 |
Accrued unbilled revenue | 956 | 855 |
Regulatory balancing accounts | 1,475 | 1,760 |
Other | 473 | 284 |
Regulatory assets | 370 | 517 |
Inventories | ||
Gas stored underground and fuel oil | 134 | 126 |
Materials and supplies | 343 | 313 |
Income taxes receivable | 194 | 130 |
Other | 306 | 338 |
Total current assets | 5,720 | 5,722 |
Property, Plant, and Equipment | ||
Electric | 51,532 | 48,532 |
Gas | 17,384 | 16,749 |
Construction work in progress | 2,117 | 2,059 |
Total property, plant, and equipment | 71,033 | 67,340 |
Accumulated depreciation | (21,603) | (20,617) |
Net property, plant, and equipment | 49,430 | 46,723 |
Other Noncurrent Assets | ||
Regulatory assets | 7,534 | 7,029 |
Nuclear decommissioning trusts | 2,597 | 2,470 |
Income taxes receivable | 70 | 135 |
Other | 1,066 | 958 |
Total other noncurrent assets | 11,267 | 10,592 |
TOTAL ASSETS | 66,417 | 63,037 |
Current Liabilities | ||
Short-term borrowings | 981 | 1,019 |
Long-term debt, classified as current | 160 | 160 |
Accounts payable | ||
Trade creditors | 1,370 | 1,414 |
Regulatory balancing accounts | 764 | 715 |
Other | 765 | 418 |
Disputed claims and customer refunds | 233 | 454 |
Interest payable | 144 | 203 |
Other | 1,681 | 1,750 |
Total current liabilities | 6,098 | 6,133 |
Noncurrent Liabilities | ||
Long-term debt | 16,179 | 15,577 |
Regulatory liabilities | 6,613 | 6,321 |
Pension and other postretirement benefits | 2,540 | 2,534 |
Asset retirement obligations | 4,672 | 3,643 |
Deferred income taxes | 10,135 | 9,487 |
Other | 2,350 | 2,282 |
Total noncurrent liabilities | 42,489 | 39,844 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Preferred stock | 258 | 258 |
Common stock | 1,322 | 1,322 |
Additional paid-in capital | 7,955 | 7,215 |
Reinvested earnings | 8,291 | 8,262 |
Accumulated other comprehensive income (loss) | 4 | 3 |
Total shareholders' equity | 17,830 | 17,060 |
TOTAL LIABILITIES AND EQUITY | $ 66,417 | $ 63,037 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Allowance for doubtful accounts | $ 53 | $ 54 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 505,183,752 | 492,025,443 |
Pacific Gas And Electric Company [Member] | ||
Allowance for doubtful accounts | $ 53 | $ 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 | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Cash Flows from Operating Activities | ||
Net income | $ 711 | $ 750 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 2,090 | 1,935 |
Allowance for equity funds used during construction | (84) | (80) |
Deferred income taxes and tax credits, net | 644 | 260 |
Disallowed capital expenditures | 517 | 270 |
Other | 293 | 247 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | (546) | (322) |
Inventories | (38) | 5 |
Accounts payable | 189 | 95 |
Income taxes receivable/payable | (63) | 42 |
Other current assets and liabilities | 254 | (87) |
Regulatory assets, liabilities, and balancing accounts, net | (634) | 78 |
Other noncurrent assets and liabilities | (85) | (251) |
Net cash provided by operating activities | 3,248 | 2,942 |
Cash Flows from Investing Activities | ||
Capital expenditures | (4,128) | (3,662) |
Decrease in restricted cash | 66 | 11 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,019 | 1,023 |
Purchases of nuclear decommissioning trust investments | (1,050) | (1,124) |
Other | 10 | 18 |
Net cash used in investing activities | (4,083) | (3,734) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $5 and $2 at respective dates | (128) | 545 |
Short-term debt financing | 250 | 0 |
Short-term debt matured | 0 | (300) |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 and $14 at respective dates | 594 | 486 |
Common stock issued | 727 | 689 |
Common stock dividends paid | (678) | (638) |
Other | 18 | 13 |
Net cash provided by financing activities | 783 | 795 |
Net change in cash and cash equivalents | (52) | 3 |
Cash and cash equivalents at January 1 | 123 | 151 |
Cash and cash equivalents at September 30 | 71 | 154 |
Supplemental disclosures of cash flow information | ||
Interest, net of amounts capitalized | (611) | (569) |
Income taxes, net | 154 | 0 |
Supplemental disclosures of noncash investing and financing activities | ||
Common stock dividends declared but not yet paid | 248 | 223 |
Capital expenditures financed through accounts payable | 325 | 245 |
Noncash common stock issuances | 15 | 15 |
Pacific Gas And Electric Company [Member] | ||
Cash Flows from Operating Activities | ||
Net income | 706 | 715 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 2,090 | 1,935 |
Allowance for equity funds used during construction | (84) | (80) |
Deferred income taxes and tax credits, net | 648 | 245 |
Disallowed capital expenditures | 517 | 270 |
Other | 234 | 200 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | (546) | (321) |
Inventories | (38) | 5 |
Accounts payable | 194 | 148 |
Income taxes receivable/payable | (64) | 14 |
Other current assets and liabilities | 258 | (45) |
Regulatory assets, liabilities, and balancing accounts, net | (634) | 78 |
Other noncurrent assets and liabilities | (75) | (232) |
Net cash provided by operating activities | 3,206 | 2,932 |
Cash Flows from Investing Activities | ||
Capital expenditures | (4,128) | (3,662) |
Decrease in restricted cash | 66 | 11 |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 1,019 | 1,023 |
Purchases of nuclear decommissioning trust investments | (1,050) | (1,124) |
Other | 10 | 18 |
Net cash used in investing activities | (4,083) | (3,734) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $5 and $2 at respective dates | (293) | 545 |
Short-term debt financing | 250 | 0 |
Short-term debt matured | 0 | (300) |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 and $14 at respective dates | 594 | 486 |
Preferred stock dividends paid | (10) | (10) |
Common stock dividends paid | (423) | (537) |
Equity contribution from PG&E Corporation | 740 | 605 |
Other | 28 | 20 |
Net cash provided by financing activities | 886 | 809 |
Net change in cash and cash equivalents | 9 | 7 |
Cash and cash equivalents at January 1 | 59 | 55 |
Cash and cash equivalents at September 30 | 68 | 62 |
Supplemental disclosures of cash flow information | ||
Interest, net of amounts capitalized | (602) | (561) |
Income taxes, net | 151 | 0 |
Supplemental disclosures of noncash investing and financing activities | ||
Common stock dividends declared but not yet paid | 244 | 0 |
Capital expenditures financed through accounts payable | $ 325 | $ 245 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2015 | |
Discount on net issuances of commercial paper | $ 5 | $ 2 |
Premium, discount, and issuance costs on proceeds from long-term debt | 6 | 14 |
Pacific Gas And Electric Company [Member] | ||
Discount on net issuances of commercial paper | 5 | 2 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 6 | $ 14 |
Organization And Basis Of Prese
Organization And Basis Of Presentation | 9 Months Ended |
Sep. 30, 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 serving no rthern 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, cons truction, 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 t he 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 intercom pany 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 financia l 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 t he 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 l iabilities. 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 po stretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred. |
New And Significant Accounting
New And Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2016 | |
New And Significant Accounting Policies | NOTE 2: SIGNIFICANT ACCOUNTING POLICIES The significant accounting pol icies 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 equi ty 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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2016 , the Utility 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 w as not the primary beneficiary of any of these VIEs at September 30, 2016 , it did not consolidate any of t hem. 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. In the first quarter of 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC, which reflects an increase of approximately $1.4 billion in the estimated undiscounted cost to decommission the Utility’s nuclear power plants. The change in total est imated cost resulted in an $818 million adjustment to the ARO recognized on the Condensed Consolidated Balance Sheets. The adjustment relates to spent fuel storage, staffing, and out-of-state waste disposal costs. Actual decommissioning costs may vary fr om 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 custome rs 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 th ese updated cost estimates. On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon n uclear p ower p lant at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2), subject to cer tain approvals, resulting in an additional $ 115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets in the second quarter of 2016. The estimated total nuclear decommissioning cost of $ 4.8 billion 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 $ 3.5 billion at September 30, 2016 and $2.5 billion at December 31, 2015 . 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 U tility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2016 and 2015 were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 113 $ 123 $ 13 $ 14 Interest cost 179 168 19 18 Expected return on plan assets (207) (219) (26) (28) Amortization of prior service cost 2 4 3 4 Amortization of net actuarial loss 6 1 1 1 Net periodic benefit cost 93 77 10 9 Regulatory account transfer (1) (8) 8 - - 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. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 339 $ 360 $ 39 $ 41 Interest cost 537 505 57 54 Expected return on plan assets (621) (655) (80) (84) Amortization of prior service cost 6 11 11 14 Amortization of net actuarial loss 18 7 3 3 Net periodic benefit cost 279 228 30 28 Regulatory account transfer (1) (25) 26 - - Total $ 254 $ 254 $ 30 $ 28 (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 (Loss) The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below: Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) 2 1 3 Amortization of net actuarial loss (net of taxes of $3 and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (2) (7) Net current period other comprehensive gain (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 Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ (6) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 3 2 5 Amortization of net actuarial loss (net of taxes of $0, and $0, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (4) (3) (7) Net current period other comprehensive gain (loss) - - - Ending balance $ (21) $ 15 $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) 4 6 10 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 11 2 13 Regulatory account transfer (net of taxes of $9 and $6, respectively) (15) (8) (23) Net current period other comprehensive gain (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) Nine Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $6, and $0, respectively) (1) 7 8 - 15 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 4 2 - 6 Regulatory account transfer (net of taxes of $7, $7, and $0, respectively) (1) (11) (10) - (21) Change in investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive gain (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 Corp oration 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 t he 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 th is 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 Pr esentation 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 th e Utility will early adopt this guidance in the fourth quarter of 2016 and do not expect this ASU to have a material impact on their Condensed Consolidated Financial Statements and related disclosures. Recognition of Lease Assets and Liabilities In Febr uary 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 wi ll 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 Condensed Consolidated Financial Statements and re lated 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 evalua ting the impact the guidance will have on their Condensed 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 Condensed Consolidated Financial Statements and related disclosures. |
Regulatory Assets, Liabilities,
Regulatory Assets, Liabilities, And Balancing Accounts | 9 Months Ended |
Sep. 30, 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 September 30, December 31, (in millions) 2016 2015 Pension benefits $ 2,416 $ 2,414 Deferred income taxes 3,649 3,054 Utility retained generation 376 411 Environmental compliance costs 760 748 Price risk management 96 138 Unamortized loss, net of gain, on reacquired debt 81 94 Other 156 170 Total long-term regulatory assets $ 7,534 $ 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 September 30, December 31, (in millions) 2016 2015 Cost of removal obligations $ 4,939 $ 4,605 Recoveries in excess of asset retirement obligations 656 631 Public purpose programs 539 600 Other 479 485 Total long-term regulatory liabilities $ 6,613 $ 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 acc ount 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, respe ctively, 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 custome r revenues are collected. Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at September 30, December 31, (in millions) 2016 2015 Electric distribution $ 43 $ 380 Utility generation - 122 Gas distribution 583 493 Energy procurement 174 262 Public purpose programs 122 155 Other 553 348 Total regulatory balancing accounts receivable $ 1,475 $ 1,760 Payable Balance at September 30, December 31, (in millions) 2016 2015 Utility generation $ 47 $ - Energy procurement 109 112 Public purpose programs 289 244 Other 319 359 Total regulatory balancing accounts payable $ 764 $ 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-rela ted 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 | 9 Months Ended |
Sep. 30, 2016 | |
Debt | NOTE 4: DEBT Revolving Cred it Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2016 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2021 $ 300 (1) $ - $ 165 $ 135 Utility April 2021 3,000 (2) 31 731 2,238 Total revolving credit facilities $ 3,300 $ 31 $ 896 $ 2,373 (1) Includes a $50 million lender commitment to the letter of credit sublimit 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 sublimit and a $75 million commitment for swingline loans. In June 2016, PG&E Corpo ration and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2020 to April 27, 2021. 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 September 30, 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 0.8 9% to 0.92%. At September 30, 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 0.77% to 0.85%. Pollution control bonds Series 2009 C and D will mature on December 1, 2016. |
Equity
Equity | 9 Months Ended |
Sep. 30, 2016 | |
Equity | NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2016 were as follows: PG&E Co rporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2015 $ 16,828 $ 17,060 Comprehensive income 711 707 Equity contributions - 740 Common stock issued 742 - Share-based compensation 59 - Common stock dividends declared (724) (667) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2016 $ 17,606 $ 17,830 During the three and nine months ended September 30, 2016, PG&E Corporation sold 0.4 million and 2.6 m illion shares of its common stock under the February 2015 equity distribution agreement for cash proceeds of $ 26 million and $ 149 million, respectively, net of commissions paid of $ 0.2 million and $ 1.3 million, respectively. As of September 30, 2016, the remaining gross sales available under this agreement were $ 275 million. In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309 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-bas ed compensation plans. During the nine months ended September 30, 2016 , 5.7 million shares were issued for cash proceeds of $ 269 million under these plans. |
Earnings Per Share
Earnings Per Share | 9 Months Ended |
Sep. 30, 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 weight ed 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 Corp oration’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2016 2015 2016 2015 Income available for common shareholders $ 388 $ 307 $ 701 $ 740 Weighted average common shares outstanding, basic 501 486 497 481 Add incremental shares from assumed conversions: Employee share-based compensation 2 3 3 3 Weighted average common shares outstanding, diluted 503 489 500 484 Total earnings per common share, diluted $ 0.77 $ 0.63 $ 1.40 $ 1.53 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive. |
Derivatives
Derivatives | 9 Months Ended |
Sep. 30, 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 remain s 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 t o 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. Eligi ble derivatives are accounted for under the accrual method of accounting. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at September 30, December 31, Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 376,296,893 333,091,813 Options 118,017,176 111,550,004 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,128,038 3,663,512 Congestion Revenue Rights (3) 172,756,395 216,383,389 (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 September 30, 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 $ 100 $ (8) $ 14 $ 106 Other noncurrent assets – other 128 (8) - 120 Current liabilities – other (67) 8 10 (49) Noncurrent liabilities – other (104) 8 7 (89) Net commodity risk $ 57 $ - $ 31 $ 88 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 Nine Months Ended September 30, September 30, (in millions) 2016 2015 2016 2015 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (29) $ (45) $ 30 $ (69) Realized gain (loss) - cost of electricity (2) (7) 1 (48) 4 Realized loss - cost of natural gas (2) (9) (3) (15) (8) Net commodity risk $ (45) $ (47) $ (33) $ (73) (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact o f cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. Cash inflows and outflows associated with derivatives are included in operati ng cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At September 30, 2016 , the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility woul d 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 trigger ed was as follows: Balance at September 30, December 31, (in millions) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (8) $ (2) Related derivatives in an asset position 4 - Collateral posting in the normal course of business related to these derivatives 2 - 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 | 9 Months Ended |
Sep. 30, 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 in puts 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 ma rket 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 Corp oration 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 September 30, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ - $ - $ - $ - $ - Nuclear decommissioning trusts Short-term investments 1 - - - 1 Global equity securities 1,678 - - - 1,678 Fixed-income securities 720 530 - - 1,250 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,399 530 - - 2,943 Price risk management instruments (Note 7) Electricity 10 16 192 (2) 216 Gas - 10 - - 10 Total price risk management instruments 10 26 192 (2) 226 Rabbi trusts Fixed-income securities - 59 - - 59 Life insurance contracts - 77 - - 77 Total rabbi trusts - 136 - - 136 Long-term disability trust Short-term investments 4 - - - 4 Assets measured at NAV - - - - 138 Total long-term disability trust 4 - - - 142 Total assets $ 2,413 $ 692 $ 192 $ (2) $ 3,447 Liabilities: Price risk management instruments (Note 7) Electricity $ 25 $ 8 $ 136 $ (33) $ 136 Gas - 2 - - 2 Total liabilities $ 25 $ 10 $ 136 $ (33) $ 138 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $346 million, primarily related to deferred taxes on appreciatio n 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 liabi lities 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 nine months ended September 30, 2016 and 2015 . Trust Assets Assets Measu red 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 fi xed-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 classifie d 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 ev aluated 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): Di sclosures 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 wi th 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 w ell as fixed-income securities that are composed primarily of U.S. 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 corrobo rated 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 unobser vable 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 wh ich 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 September 30, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 192 $ 43 Market approach CRR auction prices $ (23.81) - 8.76 Power purchase agreements $ - $ 93 Discounted cash flow Forward prices $ 18.07 - 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 Po wer 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 and nine months ended September 30, 2016 and 2015 : Price Risk M anagement Instruments (in millions) 2016 2015 Asset (liability) balance as of July 1 $ 66 $ 48 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (10) (27) Asset (liability) balance as of September 30 $ 56 $ 21 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. 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) (33) (48) Asset (liability) balance as of September 30 $ 56 $ 21 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. 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 September 30, 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 note s and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at September 30, 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 September 30, 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 15,417 18,440 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 September 30, 2016 Nuclear decommissioning trusts Short-term investments $ 1 $ - $ - $ 1 Global equity securities 579 1,116 (3) 1,692 Fixed-income securities 1,164 89 (3) 1,250 Total (1) $ 1,744 $ 1,205 $ (6) $ 2,943 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 $346 million and $314 million at September 30, 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) September 30, 2016 Less than 1 year $ 33 1–5 years 443 5–10 years 271 More than 10 years 503 Total maturities of fixed-income securities $ 1,250 The following table provides a summary of activity for the investments: Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 257 $ 244 $ 1,019 $ 1,023 Gross realized gains on securities held as available-for-sale 6 3 15 50 Gross realized losses on securities held as available-for-sale (14) (12) (17) (25) |
Commitments And Contingencies
Commitments And Contingencies | 9 Months Ended |
Sep. 30, 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. A provision for a loss contingency is recorded when it is both probable that a loss has been incu rred 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 estim ate 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 quarte rly 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 Corporatio n’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. 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 may be materially 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 occurred 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 proce edings. 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 CPUC investigations related to the Utility’s natural ga s transmission pipeline operations and practices. On July 12, 2016, the assigned commissioner and ALJ issued a ruling that adopted recommendations included in a process report jointly submitted by the Cities of San Bruno and San Carlos, ORA, the SED, TUR N (together, the “other parties”), and the Utility in April 2016. The approved framework for resolving the proceeding included a total of 159 communications (the 46 communications already included in the OII and 113 additional communications) in the scope of the proceeding, a procedure for moving undisputed facts into the evidentiary record and a diligence process for providing additional factual information. The Utility and the other parties disagreed on the inclusion of an additional 21 communications i n the scope and filed briefs on the issue. The ruling confirmed that these additional 21 communications were not included within the scope of the OII and do not, in themselves, appear to be ex parte violations, but granted the other parties’ request to se ek additional information regarding these communications. In a status report jointly submitted to the CPUC on October 14, 2016, the parties proposed an update to the framework for resolving the proceeding. The revised framework includes a total of 165 communications (159 communications previously included in the proceeding, reduced by two communications the other parties agreed not to pursue, plus 8 additional communications out of 21 communications previously in disagreement). The parties also propose d to begin settlement discussions on November 30, 2016, followed by a joint status report proposed for January 13, 2017. In the event a settlement cannot be reached, the parties proposed to submit their opening briefs on January 27, 2017, and reply briefs on February 17, 2017. On October 31, 2016, the CPUC issued a proposed decision adopting the schedule proposed by the parties in the October 14, 2016 status report. The proposed decision extends the statutory deadline for this proceeding to May 17, 2017 in order to allow the parties to complete settlement discussions or file briefs, and for the ALJ to prepare and file a proposed decision. The Utility expects that the other parties may argue that the number of violations exceeds the 165 communications r eferenced in the October 14, 2016 joint status report either because a single communication may have violated more than one rule or because they believe some of the material provided during discovery constitutes impermissible ex parte communications. The Utility expects to contest many of these assertions. If the matter does not settle, the CPUC will determine which communications included within the scope of the proceeding were in violation of its rules. The CPUC will also determine whether to impose pe nalties or other remedies, as a result of a potential settlement or otherwise. The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if the CPUC determines that the violation was continuing. 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; an d 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 historic ally exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties on the Utility in the OII but are una ble 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. Finally, the U.S. Attorney’s Office in San Francisco a nd 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 these investigations. 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 p ractices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also required the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Ut ilities 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 violati ons are found. In particular, the order cited 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 occu rred in Carmel, California on March 3, 2014. On August 18, 2016, the CPUC unanimously approved a modified presiding officer’s decision (the “MOD POD”) issued on August 17, 2016 in this investigation. In accordance with the MOD POD, the amount of the f ine increased from $24.3 million to $25.6 million, to include a $50,000 fine omitted from the June 1, 2016 presiding officer’s decision (the “POD”) and $1.3 million resulting from the per-day fine increase for the missing leak repair records for the De Anz a division. With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million. The remaining $25.6 million was paid in September 2016. In accordance wi th the MOD POD, the decision denies the appeals previously filed by the SED and Carmel from the POD, and closes this proceeding but allows the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties. On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision. Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including those related to the missing De Anza records violations) and certain other findings, and requests tha t the CPUC adopt its recommendations. On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPU C. The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations. On October 24, 2016, the Utility held a meet and confer with parties to develop remedial measures necessary to address the issues i dentified in the CPUC decision with the objective of establishing a compliance plan that includes all feasible and cost-effective measures necessary to improve the Utility’s natural gas distribution system record-keeping. Under the current schedule, the p arties are expected to submit a compliance plan to the CPUC on or before December 16, 2016. 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 a s 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 perio d 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. T he 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 Utili ty 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 au dits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can impose fines up to $50,000 for each violation, per day, and 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. On September 29, 2016, the CPUC issued a final decision adopting im provements and refinements to its gas and electric safety citation programs. Specifically, the final decision refines the criteria for the SED to use in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs. The decision also m erges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate. The decision closes the proceeding. 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 enforcemen t action and the number of factors that can be considered in determining the amount of fines. In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas dist ribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel. The Utility did not provide timely notification of such non-compliance to the CPUC. The SED is investigating the Uti lity’s self-report. The SED could impose fines on the Utility of up to $50,000 per inspection, and also for failure to timely file a self-report in connection with such inspections. The SED has the authority to issue more than one citation for a series of related incidents, and the CPUC can issue an OII and possible additional fines even after the SED has issued a citation. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines that could be i mposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding as a result of the SED’s investigation. Federal Matters Federal Criminal Trial On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pi peline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility illegally obstructed the NTSB investigation into the cause of the San Bruno accident. On Ju ly 26, 2016, the court granted the government’s motion to dismiss Count 13 alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of c ounts from 13 to 12. On August 2, 2016, the remaining Alternative Fines Act sentencing allegations in the case were dismissed. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” (The remaining allegations related to $281 million of gross gains that the government alleged the Utility derived. As previously disclosed, in December 2015, the court dismissed the government’s allegations regarding the amount of losses.) On August 9, 2016, the jury returned its verdict. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations o f pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict. The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument. The Utility is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017. The maximum statutory fine for each felony count is $500,000, for total potential maximum statutory fines of $3 million. At September 30, 2016, the Utility’s Condense d Consolidated Balance Sheets include a $3 million accrual in connection with the jury verdict. The Utility also could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed, such as a requireme nt that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by an independent third-party monitor. If appointed, the Utility expects a monitor would serve for a period of time and report periodically to the court or a department or agency of the government. Other Federal Matters In July 2014, the Utility was informed that the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Of fice in San Francisco also continues to investigate matters relating to the criminal trial discussed above. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contai ned an osprey nest and egg in Inverness, California, on March 18, 2016. It is uncertain whether any charges will be brought against the Utility as a result of these investigations. Other Litigation Matters Butte Fire Litigation In September 2015, a wi ldfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, t he fire burned 70,868 acres, resulted in two fatalities, and destroyed 549 homes, 368 outbuildings and four commercial properties. Cal Fire’s report concluded that the wildfire was caused when a Gray Pine tree contacted the Utility’s electric line which i gnited 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 rele ase 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. On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its vegetation manage ment contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacrament o County. As of September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and oth er costs, principally based on inverse condemnation and negligence theories of liability. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling preference cases (presented by individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The Utility also has begun scheduling mediation of other cases. Case management conferences were held on July 14, 2 016 and September 1, 2016. The next case management conference is scheduled for December 1, 2016 . In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees 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. The Utility believes it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility. 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 (including estimated damages t o structures and their contents, and to trees) in connection with this matter, which corresponds to the lower end of the range of its reasonably estimable losses. This amount is based on assumptions about the number, size, and type of structures damaged o r destroyed, the contents of such structures, the extent of damage to such structures and contents, and other property damage. The estimate does not include fire suppression costs, personal injury damages and other damages that the Utility could be liable for if it were found to have been negligent . The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of the $350 million accrued through September 30, 2016. The Utility believes that $90 mi llion is a reasonable estimate of fire suppression costs (this amount is not included in the $350 million accrued through September 30, 2016). The Utility currently is unable to reasonably estimate the upper end of the range because it is still at an earl y stage of the evaluation of claims, the mediation and settlement process, and discovery. The process for estimating costs associated with claims relating to the Butte fire, including for estimated property damages, requires management to exercise signi ficant judgment based on a number of assumptions and subjective factors. As more information becomes known, including discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regardi ng the financial impact of the Butte fire may change, including management’s ability to reasonably estimate a range of loss. The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the B utte fire. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. In the second quarter of 2016, the Utility recorded $260 million for probable insur ance recoveries in connection with recovery of losses related to the Butte fire, included in Other accounts receivable in the Condensed Consolidated Balance Sheets. The Utility plans to seek recovery of all insured losses, and while the Utility believes t hat a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to Butte fire will ultimately be recovered through its insurance, it is unable to predict the amount and timing of such insurance recoveries. If t he Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals during such reporting periods. Other Contingencies PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts relate d to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $84 million at September 30, 2016 and $63 million at December 31, 2015. These amounts are included in Other current liabilities in the Condensed Consolidated Balanc e 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. Disallowance of Plant Costs PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operat ing and maintenance expenses in the Condensed Consolidated Statements of Income. Disallowances as a result of the CPUC’s June 23, 2016 final phase one decision in the Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipe line Safety Enhancement Plan are discussed below. 2015 GT&S Rate Case Disallowance of Capital Expenditures On June 23, 2016, the CPUC approved a final decision in phase one of the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts. As a result, i n the second quarter of 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million to the net plant balance for 2011 through 2014 capi tal expenditures in excess of adopted amounts and $56 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s a bility to manage its capital spending and on the outcome of the third party audit of 2011 through 2014 capital spending. Penalty Decision’s Disallowance of Natural Gas Capital Expenditures 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 Ut ility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures. The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty. The Utility expects a final CPUC decision to be voted in December 2016. For the three and nine months ended September 30, 2016, the Utility recorded charges for disallowed capital spendin g of $51 million and $286 million, respectively, as a result of the Penalty Decision. The cumulative charges at September 30, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table: Nine Months Cumulative Future Ended Charges Charges September 30, September 30, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit paid - 400 - 400 Charge for disallowed capital (1) 286 692 - 692 Disallowed revenue for pipeline safety expenses (2) 8 8 150 158 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 294 $ 1,400 $ 150 $ 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 finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issu ed a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures. (2) Future GT&S revenues will be reduced for these unrecovered expenses. (3) In the Penalty Decision, the CPUC estimated that the Utility w ould incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs would be expensed a s incurred. 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 September 30, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, of which $665 million was expensed 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 futu re periods to the extent PSEP-related capital costs are higher than currently expected. Environmental Remediation Contingencies The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidat ed Balance Sheets and is composed of the following: Balance at September 30, December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 300 $ 300 Hinkley natural gas compressor station (1) 140 140 Former manufactured gas plant sites owned by the Utility or third parties 305 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 143 164 Fossil fuel-fired generation facilities and sites 104 94 Total environmental remediation liability $ 992 $ 969 (1) See “Natural Gas Compressor Station Sites” below. The Utility’s environmental remediation liability at September 30, 2016 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to implement final remediation plans and the Utility’s required time frame for r emediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financ |
New And Significant Accountin18
New And Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Variable Interest Entities | Variable Interest Entities A VIE is an entity that does not have sufficient equi ty 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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2016 , the Utility 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 w as not the primary beneficiary of any of these VIEs at September 30, 2016 , it did not consolidate any of t hem. |
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. In the first quarter of 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC, which reflects an increase of approximately $1.4 billion in the estimated undiscounted cost to decommission the Utility’s nuclear power plants. The change in total est imated cost resulted in an $818 million adjustment to the ARO recognized on the Condensed Consolidated Balance Sheets. The adjustment relates to spent fuel storage, staffing, and out-of-state waste disposal costs. Actual decommissioning costs may vary fr om 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 custome rs 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 th ese updated cost estimates. On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon n uclear p ower p lant at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2), subject to cer tain approvals, resulting in an additional $ 115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets in the second quarter of 2016. The estimated total nuclear decommissioning cost of $ 4.8 billion 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 $ 3.5 billion at September 30, 2016 and $2.5 billion at December 31, 2015 . Changes in these estimates could materially affect the amount of the recorded ARO for these assets. |
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 t he 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 th is 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 Pr esentation 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. |
New And Significant Accountin19
New And Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Components Of Net Periodic Benefit Cost | Pension Benefits Other Benefits Three Months Ended September 30, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 113 $ 123 $ 13 $ 14 Interest cost 179 168 19 18 Expected return on plan assets (207) (219) (26) (28) Amortization of prior service cost 2 4 3 4 Amortization of net actuarial loss 6 1 1 1 Net periodic benefit cost 93 77 10 9 Regulatory account transfer (1) (8) 8 - - 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. Pension Benefits Other Benefits Nine Months Ended September 30, (in millions) 2016 2015 2016 2015 Service cost for benefits earned $ 339 $ 360 $ 39 $ 41 Interest cost 537 505 57 54 Expected return on plan assets (621) (655) (80) (84) Amortization of prior service cost 6 11 11 14 Amortization of net actuarial loss 18 7 3 3 Net periodic benefit cost 279 228 30 28 Regulatory account transfer (1) (25) 26 - - Total $ 254 $ 254 $ 30 $ 28 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. |
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income | Pension Other Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $0 and $2, respectively) 2 1 3 Amortization of net actuarial loss (net of taxes of $3 and $0, respectively) 3 1 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (2) (7) Net current period other comprehensive gain (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 Benefits Benefits Total (in millions, net of income tax) Three Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ (6) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $2, respectively) 3 2 5 Amortization of net actuarial loss (net of taxes of $0, and $0, respectively) 1 1 2 Regulatory account transfer (net of taxes of $3 and $3, respectively) (4) (3) (7) Net current period other comprehensive gain (loss) - - - Ending balance $ (21) $ 15 $ (6) (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.) Pension Other Benefits Benefits Total (in millions, net of income tax) Nine Months Ended September 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $5, respectively) 4 6 10 Amortization of net actuarial loss (net of taxes of $7 and $1, respectively) 11 2 13 Regulatory account transfer (net of taxes of $9 and $6, respectively) (15) (8) (23) Net current period other comprehensive gain (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) Nine Months Ended September 30, 2015 Beginning balance $ (21) $ 15 $ 17 $ 11 Amounts reclassified from other comprehensive income: Amortization of prior service cost (net of taxes of $4, $6, and $0, respectively) (1) 7 8 - 15 Amortization of net actuarial loss (net of taxes of $3, $1, and $0, respectively) (1) 4 2 - 6 Regulatory account transfer (net of taxes of $7, $7, and $0, respectively) (1) (11) (10) - (21) Change in investments (net of taxes of $0, $0, and $12, respectively) - - (17) (17) Net current period other comprehensive gain (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) | 9 Months Ended |
Sep. 30, 2016 | |
Long-Term Regulatory Assets | Balance at September 30, December 31, (in millions) 2016 2015 Pension benefits $ 2,416 $ 2,414 Deferred income taxes 3,649 3,054 Utility retained generation 376 411 Environmental compliance costs 760 748 Price risk management 96 138 Unamortized loss, net of gain, on reacquired debt 81 94 Other 156 170 Total long-term regulatory assets $ 7,534 $ 7,029 |
Long-Term Regulatory Liabilities | Balance at September 30, December 31, (in millions) 2016 2015 Cost of removal obligations $ 4,939 $ 4,605 Recoveries in excess of asset retirement obligations 656 631 Public purpose programs 539 600 Other 479 485 Total long-term regulatory liabilities $ 6,613 $ 6,321 |
Regulatory Balancing Accounts Receivable | Receivable Balance at September 30, December 31, (in millions) 2016 2015 Electric distribution $ 43 $ 380 Utility generation - 122 Gas distribution 583 493 Energy procurement 174 262 Public purpose programs 122 155 Other 553 348 Total regulatory balancing accounts receivable $ 1,475 $ 1,760 |
Regulatory Balancing Accounts Payable | Payable Balance at September 30, December 31, (in millions) 2016 2015 Utility generation $ 47 $ - Energy procurement 109 112 Public purpose programs 289 244 Other 319 359 Total regulatory balancing accounts payable $ 764 $ 715 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 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 2021 $ 300 (1) $ - $ 165 $ 135 Utility April 2021 3,000 (2) 31 731 2,238 Total revolving credit facilities $ 3,300 $ 31 $ 896 $ 2,373 (1) Includes a $50 million lender commitment to the letter of credit sublimit 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 sublimit and a $75 million commitment for swingline loans. |
Equity (Tables)
Equity (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Changes In Equity | PG&E Co rporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2015 $ 16,828 $ 17,060 Comprehensive income 711 707 Equity contributions - 740 Common stock issued 742 - Share-based compensation 59 - Common stock dividends declared (724) (667) Preferred stock dividend requirement - (10) Preferred stock dividend requirement of subsidiary (10) - Balance at September 30, 2016 $ 17,606 $ 17,830 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted | Three Months Ended Nine Months Ended September 30, September 30, (in millions, except per share amounts) 2016 2015 2016 2015 Income available for common shareholders $ 388 $ 307 $ 701 $ 740 Weighted average common shares outstanding, basic 501 486 497 481 Add incremental shares from assumed conversions: Employee share-based compensation 2 3 3 3 Weighted average common shares outstanding, diluted 503 489 500 484 Total earnings per common share, diluted $ 0.77 $ 0.63 $ 1.40 $ 1.53 |
Derivatives (Tables)
Derivatives (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Volumes Of Outstanding Derivative Contracts | Contract Volume at September 30, December 31, Underlying Product Instruments 2016 2015 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 376,296,893 333,091,813 Options 118,017,176 111,550,004 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,128,038 3,663,512 Congestion Revenue Rights (3) 172,756,395 216,383,389 (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 September 30, 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 $ 100 $ (8) $ 14 $ 106 Other noncurrent assets – other 128 (8) - 120 Current liabilities – other (67) 8 10 (49) Noncurrent liabilities – other (104) 8 7 (89) Net commodity risk $ 57 $ - $ 31 $ 88 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 Nine Months Ended September 30, September 30, (in millions) 2016 2015 2016 2015 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (29) $ (45) $ 30 $ (69) Realized gain (loss) - cost of electricity (2) (7) 1 (48) 4 Realized loss - cost of natural gas (2) (9) (3) (15) (8) Net commodity risk $ (45) $ (47) $ (33) $ (73) (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact o f cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered | Balance at September 30, December 31, (in millions) 2016 2015 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (8) $ (2) Related derivatives in an asset position 4 - Collateral posting in the normal course of business related to these derivatives 2 - 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) | 9 Months Ended |
Sep. 30, 2016 | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | Fair Value Measurements At September 30, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ - $ - $ - $ - $ - Nuclear decommissioning trusts Short-term investments 1 - - - 1 Global equity securities 1,678 - - - 1,678 Fixed-income securities 720 530 - - 1,250 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,399 530 - - 2,943 Price risk management instruments (Note 7) Electricity 10 16 192 (2) 216 Gas - 10 - - 10 Total price risk management instruments 10 26 192 (2) 226 Rabbi trusts Fixed-income securities - 59 - - 59 Life insurance contracts - 77 - - 77 Total rabbi trusts - 136 - - 136 Long-term disability trust Short-term investments 4 - - - 4 Assets measured at NAV - - - - 138 Total long-term disability trust 4 - - - 142 Total assets $ 2,413 $ 692 $ 192 $ (2) $ 3,447 Liabilities: Price risk management instruments (Note 7) Electricity $ 25 $ 8 $ 136 $ (33) $ 136 Gas - 2 - - 2 Total liabilities $ 25 $ 10 $ 136 $ (33) $ 138 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $346 million, primarily related to deferred taxes on appreciatio n 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 September 30, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 192 $ 43 Market approach CRR auction prices $ (23.81) - 8.76 Power purchase agreements $ - $ 93 Discounted cash flow Forward prices $ 18.07 - 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 Po wer 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 and nine months ended September 30, 2016 and 2015 : Price Risk M anagement Instruments (in millions) 2016 2015 Asset (liability) balance as of July 1 $ 66 $ 48 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (10) (27) Asset (liability) balance as of September 30 $ 56 $ 21 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. 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) (33) (48) Asset (liability) balance as of September 30 $ 56 $ 21 (1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. |
Carrying Amount And Fair Value Of Financial Instruments | At September 30, 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 15,417 18,440 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 September 30, 2016 Nuclear decommissioning trusts Short-term investments $ 1 $ - $ - $ 1 Global equity securities 579 1,116 (3) 1,692 Fixed-income securities 1,164 89 (3) 1,250 Total (1) $ 1,744 $ 1,205 $ (6) $ 2,943 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 $346 million and $314 million at September 30, 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) September 30, 2016 Less than 1 year $ 33 1–5 years 443 5–10 years 271 More than 10 years 503 Total maturities of fixed-income securities $ 1,250 |
Schedule Of Activity For Debt And Equity Securities | Three Months Ended Nine Months Ended September 30, September 30, 2016 2015 2016 2015 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 257 $ 244 $ 1,019 $ 1,023 Gross realized gains on securities held as available-for-sale 6 3 15 50 Gross realized losses on securities held as available-for-sale (14) (12) (17) (25) |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Impact Of The Penalty Decision | Nine Months Cumulative Future Ended Charges Charges September 30, September 30, and Total (in millions) 2016 2016 Costs Amount Fine paid to the state $ - $ 300 $ - $ 300 Customer bill credit paid - 400 - 400 Charge for disallowed capital (1) 286 692 - 692 Disallowed revenue for pipeline safety expenses (2) 8 8 150 158 CPUC estimated cost of other remedies (3) - - - 50 Total Penalty Decision fines and remedies $ 294 $ 1,400 $ 150 $ 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 finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issu ed a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures. (2) Future GT&S revenues will be reduced for these unrecovered expenses. (3) In the Penalty Decision, the CPUC estimated that the Utility w ould incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs would be expensed a s incurred. |
Schedule Of Environmental Remediation Liability | Balance at September 30, December 31, (in millions) 2016 2015 Topock natural gas compressor station (1) $ 300 $ 300 Hinkley natural gas compressor station (1) 140 140 Former manufactured gas plant sites owned by the Utility or third parties 305 271 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 143 164 Fossil fuel-fired generation facilities and sites 104 94 Total environmental remediation liability $ 992 $ 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 | 9 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total nuclear decommissioning asset retirement obligation | $ 3,500 | $ 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 | |
Increase in ARO | $ 115 |
New And Significant Accountin28
New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost for benefits earned | $ 113 | $ 123 | $ 339 | $ 360 | |
Interest cost | 179 | 168 | 537 | 505 | |
Expected return on plan assets | (207) | (219) | (621) | (655) | |
Amortization of prior service cost | 2 | 4 | 6 | 11 | |
Amortization of net actuarial loss | 6 | 1 | 18 | 7 | |
Net periodic benefit cost | 93 | 77 | 279 | 228 | |
Regulatory account transfer | [1] | (8) | 8 | (25) | 26 |
Total | 85 | 85 | 254 | 254 | |
Other Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost for benefits earned | 13 | 14 | 39 | 41 | |
Interest cost | 19 | 18 | 57 | 54 | |
Expected return on plan assets | (26) | (28) | (80) | (84) | |
Amortization of prior service cost | 3 | 4 | 11 | 14 | |
Amortization of net actuarial loss | 1 | 1 | 3 | 3 | |
Net periodic benefit cost | 10 | 9 | 30 | 28 | |
Regulatory account transfer | [1] | 0 | 0 | 0 | 0 |
Total | $ 10 | $ 9 | $ 30 | $ 28 | |
[1] | The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in futures rates. |
New And Significant Accountin29
New And Significant Accounting Policies (Reclassifications Out Of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | $ (7) | $ (6) | $ (7) | $ 11 | |
Change in investments | 0 | 0 | 0 | (17) | |
Net current period other comprehensive income (loss) | 0 | 0 | 0 | (17) | |
Ending balance | (7) | (6) | (7) | (6) | |
Net change in investments tax | 0 | 0 | 0 | 12 | |
Net actuarial loss tax | 0 | 0 | 0 | 0 | |
Amounts Reclassified From Other Comprehensive Income [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Amortization of prior service cost | [1] | 3 | 5 | 10 | 15 |
Amortization of net actuarial loss | [1] | 4 | 2 | 13 | 6 |
Regulatory account transfer | [1] | (7) | (7) | (23) | (21) |
Change in investments | (17) | ||||
Pension Benefits [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | (23) | (21) | (23) | (21) | |
Amortization of prior service cost | 2 | 4 | 6 | 11 | |
Amortization of net actuarial loss | 6 | 1 | 18 | 7 | |
Net current period other comprehensive income (loss) | 0 | 0 | 0 | 0 | |
Ending balance | (23) | (21) | (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] | 2 | 3 | 4 | 7 |
Amortization of net actuarial loss | [1] | 3 | 1 | 11 | 4 |
Regulatory account transfer | [1] | (5) | (4) | (15) | (11) |
Change in investments | 0 | ||||
Amortization of prior service cost tax | 0 | 1 | 2 | 4 | |
Net actuarial loss tax | 3 | 0 | 7 | 3 | |
Regulatory account transfer tax | 3 | 3 | 9 | 7 | |
Change in investments tax | 0 | 0 | |||
Other Benefits [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | 16 | 15 | 16 | 15 | |
Amortization of prior service cost | 3 | 4 | 11 | 14 | |
Amortization of net actuarial loss | 1 | 1 | 3 | 3 | |
Net current period other comprehensive income (loss) | 0 | 0 | 0 | 0 | |
Ending balance | 16 | 15 | 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] | 1 | 2 | 6 | 8 |
Amortization of net actuarial loss | [1] | 1 | 1 | 2 | 2 |
Regulatory account transfer | [1] | (2) | (3) | (8) | (10) |
Change in investments | 0 | ||||
Amortization of prior service cost tax | 2 | 2 | 5 | 6 | |
Net actuarial loss tax | 0 | 0 | 1 | 1 | |
Regulatory account transfer tax | $ 2 | 3 | 6 | 7 | |
Change in investments tax | 0 | 0 | |||
Other Investments [Member] | |||||
Accumulated Other Comprehensive Income Loss [Line Items] | |||||
Beginning balance | 17 | ||||
Net current period other comprehensive income (loss) | (17) | ||||
Ending balance | $ 0 | 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 | Sep. 30, 2016 | Dec. 31, 2015 |
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 7,534 | $ 7,029 |
Pension Benefits [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,416 | 2,414 |
Deferred Income Taxes [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 3,649 | 3,054 |
Utility Retained Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 376 | 411 |
Environmental Compliance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 760 | 748 |
Price Risk Management [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 96 | 138 |
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 81 | 94 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 156 | $ 170 |
Regulatory Assets, Liabilitie31
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 6,613 | $ 6,321 |
Cost Of Removal Obligations [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 4,939 | 4,605 |
Recoveries In Excess Of AROs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 656 | 631 |
Public Purpose Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 539 | 600 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 479 | $ 485 |
Regulatory Assets, Liabilitie32
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Utility Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 47 | $ 0 |
Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 1,475 | 1,760 |
Regulatory Balancing Accounts Receivable [Member] | Electric distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 43 | 380 |
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 0 | 122 |
Regulatory Balancing Accounts Receivable [Member] | Gas distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 583 | 493 |
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 174 | 262 |
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 122 | 155 |
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 553 | 348 |
Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 764 | 715 |
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 109 | 112 |
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 289 | 244 |
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 319 | $ 359 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) $ in Millions | Sep. 30, 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 | 0.89% |
Minimum [Member] | Pollution Control Bonds Series 2009 A-D [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.77% |
Maximum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.92% |
Maximum [Member] | Pollution Control Bonds Series 2009 A-D [Member] | |
Debt [Line Items] | |
Debt instrument, interest rate | 0.85% |
Utility [Member] | |
Debt [Line Items] | |
Floating rate unsecured term loan, due 2017 | $ 250 |
Utility [Member] | Senior Notes, 2.95%, Due 2026 [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 | 9 Months Ended | |
Sep. 30, 2016USD ($) | ||
Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2021 | |
Letters of Credit Sublimit | $ 500 | |
Swingline Loans Sublimit | 75 | |
Utility [Member] | ||
Debt [Line Items] | ||
Facility limit | 3,000 | [1] |
Letters Of Credit Outstanding Amount | 31 | |
Commercial Paper | 731 | |
Facility Availability | $ 2,238 | |
P G E Corporation [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2021 | |
Facility limit | $ 300 | [2] |
Letters Of Credit Outstanding Amount | 0 | |
Commercial Paper | 165 | |
Facility Availability | 135 | |
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 | 31 | |
Commercial Paper | 896 | |
Facility Availability | $ 2,373 | |
[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 Thousands | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | |
Common Stock Value | $ 12,083,000 | $ 12,083,000 | $ 11,282,000 |
Pacific Gas And Electric Company [Member] | |||
Common Stock Value | $ 1,322,000 | $ 1,322,000 | $ 1,322,000 |
Equity Contract [Member] | |||
Equity Distribution Agreement, shares issued | 400,000 | 2,600,000 | |
Remaining equity distribution agreement amount | $ 275,000 | $ 275,000 | |
Fees and commissions | 200 | 1,300 | |
Stock Issued During Period Value Under Equity Distribution Agreement | $ 26,000 | $ 149,000 | |
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 | 5,700,000 | ||
Stock Issued During Period Value Stock Options Exercised | $ 269,000 | ||
Underwritten Public Offering [Member] | |||
Common Stock Shares Issued | 4,900,000 | 4,900,000 | |
Common Stock Value | $ 309,000 | $ 309,000 |
Equity (Changes In Equity) (Det
Equity (Changes In Equity) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Balance at December 31, 2015 | $ 16,576 | |||
Balance at December 31, 2015 | 16,828 | |||
Comprehensive Income Net Of Tax | $ 391 | $ 310 | 711 | $ 733 |
Common stock issued | 742 | |||
Share-based compensation | 59 | |||
Common stock dividends declared | (724) | |||
Preferred stock dividend requirement of subsidiary | (3) | (3) | (10) | (10) |
Balance at September 30, 2016 | 17,606 | 17,606 | ||
Balance at September 30, 2016 | 17,354 | 17,354 | ||
Pacific Gas And Electric Company [Member] | ||||
Balance at December 31, 2015 | 17,060 | |||
Comprehensive Income Net Of Tax | 389 | 305 | 707 | 715 |
Common stock issued | 0 | |||
Share-based compensation | 0 | |||
Common stock dividends declared | (667) | |||
Preferred stock dividend requirement | (3) | $ (3) | (10) | (10) |
Equity contributions | 740 | $ 605 | ||
Balance at September 30, 2016 | $ 17,830 | $ 17,830 |
Earnings Per Share (Reconciliat
Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income available for common shareholders | $ 388 | $ 307 | $ 701 | $ 740 |
Weighted average common shares outstanding, basic | 501 | 486 | 497 | 481 |
Employee share-based compensation | 2 | 3 | 3 | 3 |
Weighted average common shares outstanding, diluted | 503 | 489 | 500 | 484 |
Total earnings per common share, diluted | $ 0.77 | $ 0.63 | $ 1.40 | $ 1.53 |
Derivatives (Volumes Of Outstan
Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details) | Sep. 30, 2016 | Dec. 31, 2015 | |
Forwards And Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 376,296,893 | 333,091,813 |
Forwards And Swaps [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | 3,128,038 | 3,663,512 | |
Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 118,017,176 | 111,550,004 |
Congestion Revenue Rights [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [3] | 172,756,395 | 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 | Sep. 30, 2016 | Dec. 31, 2015 |
Other Current Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 100 | $ 97 |
Cash Collateral | 14 | 25 |
Total Derivative Balance | 106 | 118 |
Netting | (8) | (4) |
Other Noncurrent Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 128 | 172 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 120 | 170 |
Netting | (8) | (2) |
Other Current Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (67) | (102) |
Cash Collateral | 10 | 44 |
Total Derivative Balance | (49) | (54) |
Netting | 8 | 4 |
Other Noncurrent Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (104) | (140) |
Cash Collateral | 7 | 21 |
Total Derivative Balance | (89) | (117) |
Netting | 8 | 2 |
Gross Derivative Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 57 | 27 |
Netting [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 0 | 0 |
Cash Collateral [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Cash Collateral | 31 | 90 |
Total Derivatve Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Derivative Balance | $ 88 | $ 117 |
Derivatives (Gains And Losses O
Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Unrealized gain (loss) - regulatory assets and liabilities | [1] | $ (29) | $ (45) | $ 30 | $ (69) |
Realized gain (loss) - cost of electricity | [2] | (7) | 1 | (48) | 4 |
Realized loss - cost of natural gas | [2] | (9) | (3) | (15) | (8) |
Net commodity risk | $ (45) | $ (47) | $ (33) | $ (73) | |
[1] | Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. | ||||
[2] | These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Derivatives (Additional Cash Co
Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized | $ (8) | $ (2) | |
Related derivatives in an asset position | 4 | 0 | |
Collateral posting in the normal course of business related to these derivatives | 2 | 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 | Sep. 30, 2016 | Dec. 31, 2015 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | $ 0 | $ 64 | |||
Total assets | 3,447 | 3,428 | |||
Electricity | 136 | 170 | |||
Natural Gas | 2 | 1 | |||
Total liabilities | 138 | 171 | |||
Amount primarily related to deferred taxes on appreciation of investment value | 346 | [1] | 314 | [2] | |
Nuclear Decommissioning Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 1 | 36 | |||
Total assets | 2,943 | [1] | 2,784 | [2] | |
Fixed-income securities | 1,250 | 1,215 | |||
Global equity securities | 1,678 | 1,520 | |||
Financial Instruments Measured At NAV | 14 | 13 | |||
Price Risk Management Instrument [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 226 | 288 | |||
Electricity | 216 | 286 | |||
Natural Gas | 10 | 2 | |||
Rabbi Trusts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total assets | 136 | 127 | |||
Fixed-income securities | 59 | 57 | |||
Life insurance contracts | 77 | 70 | |||
Long-Term Disability Trust [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 4 | 7 | |||
Total assets | 142 | 165 | |||
Financial Instruments Measured At NAV | 138 | 158 | |||
Fair Value Measurements, Level 1 [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Short-term investments | 0 | 64 | |||
Total assets | 2,413 | 2,321 | |||
Total liabilities | 25 | 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 | 1 | 36 | |||
Total assets | 2,399 | [1] | 2,250 | [2] | |
Fixed-income securities | 720 | 694 | |||
Global equity securities | 1,678 | 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 | 10 | 0 | |||
Electricity | 10 | 0 | |||
Natural Gas | 0 | 0 | |||
Electricity | 25 | 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 | 4 | 7 | |||
Total assets | 4 | 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 | 692 | 658 | |||
Total liabilities | 10 | 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 | 530 | [1] | 521 | [2] | |
Fixed-income securities | 530 | 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 | 26 | 10 | |||
Electricity | 16 | 9 | |||
Natural Gas | 10 | 1 | |||
Electricity | 8 | 1 | |||
Natural Gas | 2 | 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 | 136 | 127 | |||
Fixed-income securities | 59 | 57 | |||
Life insurance contracts | 77 | 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 | 192 | 259 | |||
Total liabilities | 136 | 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 | 192 | 259 | |||
Electricity | 192 | 259 | |||
Natural Gas | 0 | 0 | |||
Electricity | 136 | 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] | (33) | (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] | (2) | 18 | ||
Natural Gas | [3] | 0 | 1 | ||
Electricity | [3] | (33) | (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 $346 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 | 9 Months Ended | 12 Months Ended | |
Sep. 30, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 3,447 | $ 3,428 | |
Liabilities, Fair Value | 138 | 171 | |
Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | 192 | 259 | |
Liabilities, Fair Value | $ 43 | $ 63 | |
Fair value measurement Valuation technique | Market approach | Market approach | |
Fair value measurement Unobservable Input | CRR auction prices | CRR auction prices | |
Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 0 | $ 0 | |
Liabilities, Fair Value | $ 93 | $ 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] | 18.07 | 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 | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||||
Beginning asset (liability) balance | $ 66 | $ 48 | $ 89 | $ 69 | |
Included in regulatory assets and liabilities or balancing accounts | [1] | (10) | (27) | (33) | (48) |
Ending asset (liability) balance | $ 56 | $ 21 | $ 56 | $ 21 | |
[1] | The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted. |
Fair Value Measurements (Carryi
Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) - USD ($) $ in Millions | Sep. 30, 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 | $ 18,440 | $ 16,422 |
Pacific Gas And Electric Company [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | 15,417 | 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 | 9 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Dec. 31, 2015 | ||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | [1] | $ 1,744 | $ 1,709 | ||
Total Unrealized Gains | [1] | 1,205 | 1,092 | ||
Total Unrealized Losses | [1] | (6) | (17) | ||
Total Fair Value | [1] | 2,943 | 2,784 | ||
Amount primarily related to deferred taxes on appreciation of investment value | 346 | [2] | 314 | [3] | |
Short-term investments [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 1 | 36 | |||
Total Unrealized Gains | 0 | 0 | |||
Total Unrealized Losses | 0 | 0 | |||
Total Fair Value | 1 | 36 | |||
Other Fixed-Income Securities [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 1,164 | 1,165 | |||
Total Unrealized Gains | 89 | 58 | |||
Total Unrealized Losses | (3) | (8) | |||
Total Fair Value | 1,250 | 1,215 | |||
Global equity securities [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 579 | 508 | |||
Total Unrealized Gains | 1,116 | 1,034 | |||
Total Unrealized Losses | (3) | (9) | |||
Total Fair Value | $ 1,692 | $ 1,533 | |||
[1] | Represents amounts before deducting $343 million and $314 million at June 30, 2016 and December 31, 2015, respectively, primarily related to deferred taxes on appreciation of investment value. | ||||
[2] | Represents amount before deducting $346 million, primarily related to deferred taxes on appreciation of investment value. | ||||
[3] | Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value. |
Fair Value Measurements (Sche47
Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) $ in Millions | Sep. 30, 2016USD ($) |
Less than 1 year | $ 33 |
1-5 years | 443 |
5-10 years | 271 |
More than 10 years | 503 |
Total maturities of fixed-income securities | $ 1,250 |
Fair Value Measurements (Sche48
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 257 | $ 244 | $ 1,019 | $ 1,023 |
Gross realized gains on sales of securities held as available-for-sale | 6 | 3 | 15 | 50 |
Gross realized losses on sales of securities held as available-for-sale | $ (14) | $ (12) | $ (17) | $ (25) |
Commitments And Contingencies49
Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions | Sep. 30, 2016USD ($) | Dec. 31, 2015USD ($) |
Long-term Purchase Commitment [Line Items] | ||
Long-term agreements range, years | 20 | |
Total | $ 406 | $ 50,000 |
Commitments And Contingencies50
Commitments And Contingencies (Impact Of Penalty Decision) (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | ||
Impact Of Penalty Decision [Line Items] | |||
Charge for disallowed capital | $ 517 | $ 270 | |
Penalty Decision [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Charge for disallowed capital | [1] | 286 | |
Total Penalty Decision Fines And Remedies | 294 | ||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 8 | |
Total Penalty Decision [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | 300 | ||
Customer bill credit paid | 400 | ||
Charge for disallowed capital | [1] | 692 | |
Total Penalty Decision Fines And Remedies | 1,600 | ||
CPUC estimated cost of other remedies | [3] | 50 | |
Disallowed Revenue For Pipeline Safety Expenses | [2] | 158 | |
Penalty Decision Cumulative Charges [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Fine paid to the state | 300 | ||
Customer bill credit paid | 400 | ||
Charge for disallowed capital | [1] | 692 | |
Total Penalty Decision Fines And Remedies | 1,400 | ||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 8 | |
Penalty Decision Future Charges and Costs [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Charge for disallowed capital | [1] | 0 | |
Total Penalty Decision Fines And Remedies | 150 | ||
Disallowed Revenue For Pipeline Safety Expenses | [2] | 150 | |
Pacific Gas And Electric Company [Member] | |||
Impact Of Penalty Decision [Line Items] | |||
Charge for disallowed capital | $ 517 | $ 270 | |
[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 finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issued a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures. | ||
[2] | 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. This table does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs would be expensed as incurred. |
Commitments And Contingencies51
Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($) | ||
Loss Contingencies [Line Items] | |||||
Unrecognized Tax Benefits | $ 70,000 | $ 70,000 | |||
CPUC Disallowed Spending | 850,000 | ||||
Release of Escrow to California Power Exchange | (66,000) | $ (11,000) | |||
CPUC Disallowed PSEP Spending Allocated To Capital In Phase 2 Proposed Decision | 689,000 | ||||
Charge for disallowed capital | $ 517,000 | 270,000 | |||
Butte Fire [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of plaintiffs | 1,800 | 1,800 | |||
Loss Contingency Range Of Possible Loss Minimum | $ 350,000 | $ 350,000 | |||
Number of complaints filed against utility | 50 | 50 | |||
Fire Fighting Costs Recovery Requested By Cal Fire | $ 90,000 | ||||
Expected recovery of costs through insurance | $ 260,000 | $ 260,000 | |||
Number Of Acres Burned | 70,868 | 70,868 | |||
Number Of Fatalities Caused By Fire | 2 | 2 | |||
Number Of Homes Burned By Fire | 549 | 549 | |||
Number Of Outbuildings Burned By Fire | 368 | 368 | |||
Number Of Commerical Properties Burned By Fire | 4 | 4 | |||
Number Of Households Represented In Court | 800 | 800 | |||
Number Of Master Complaints | 2 | 2 | |||
Natural Gas Distribution Facilities Record Keeping OII [Member] | |||||
Loss Contingencies [Line Items] | |||||
CPUC Imposed Fine | $ 36,500 | ||||
Penalty Assessed By CPUC In Presiding Officer Decision | 24,300 | ||||
New Penalty Assesed By CPUC In Modified Presiding Officer Decision | 25,600 | ||||
Fine Added To MOD POD | 50 | ||||
Fine Added To MOD POD Related To Missing Leak Repair Records For De Anza Division | 1,300 | ||||
Previously Paid Fine For Carmel Incident | 10,850 | ||||
SED Proposed Additional Fine | 7,000 | ||||
Potential Safety Citations [Member] | |||||
Loss Contingencies [Line Items] | |||||
SED Maximum Statutory Penalty Per Violaiton | 50 | ||||
SED Administrative Limit Per Citation | $ 8,000 | ||||
Number Of Noncompliant Atmospheric Corrosion Inspections | 550,000 | 550,000 | |||
Percent Of Noncompliant Atmospheric Corrosion Inspections | 35.00% | 35.00% | |||
Criminal investigation [Member] | |||||
Loss Contingencies [Line Items] | |||||
Statutory penalty for each count of alleged violation | $ 500 | ||||
Total maximum statutory penalties | 3,000 | ||||
Gross Gain Derived From Alleged Violation | $ 281,000 | ||||
Number Of Record-Keeping Counts Jury Acquitted Utility Of | 6 | 6 | |||
Guilty Felony Counts Of Violations Of Integrity Management Regulations | 5 | 5 | |||
Guilty Felony Count Of Obstructing Federal Agency Proceeding | 1 | 1 | |||
Dismissed Alleged Count Of Violation | 1 | 1 | |||
Criminal investigation [Member] | Alleged obstruction of NTSB's investigation [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of felony counts | 1 | 1 | |||
Criminal investigation [Member] | Remaining Criminal Indictment Counts [Member] | |||||
Loss Contingencies [Line Items] | |||||
Number of felony counts | 12 | 12 | |||
Minimum [Member] | Potential Safety Citations [Member] | |||||
Loss Contingencies [Line Items] | |||||
SED fines for self-reported violations | $ 50 | ||||
Maximum [Member] | Potential Safety Citations [Member] | |||||
Loss Contingencies [Line Items] | |||||
SED fines for self-reported violations | 16,800 | ||||
Penalty Decision Cumulative Charges [Member] | |||||
Loss Contingencies [Line Items] | |||||
Charge for disallowed capital | [1] | 692,000 | |||
Penalty Decision Future Charges and Costs [Member] | |||||
Loss Contingencies [Line Items] | |||||
Charge for disallowed capital | [1] | 0 | |||
Settlements parties [Member] | |||||
Loss Contingencies [Line Items] | |||||
Disputed Claims Liability Balance | $ 233,000 | 233,000 | $ 454,000 | ||
Other Receivables Disputed Claims | 161,000 | 161,000 | 228,000 | ||
Elimination Of CAISO Receivable | 165,000 | ||||
Release of Escrow to California Power Exchange | $ 66,000 | ||||
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 | 46 | |||
Additional Ex Parte Communication Count | 113 | 113 | |||
Ex Parte Communications Considered in Briefing | 21 | 21 | |||
Ex Parte Communications No Longer Included | 2 | 2 | |||
Additional Communications Added In Status Report | 8 | 8 | |||
Pipeline Saftey Enhancement Plan [Member] | |||||
Loss Contingencies [Line Items] | |||||
Capitalized PSEP costs | $ 1,300,000 | $ 1,300,000 | |||
Cummulative unrecoverable PSEP capital costs | 665,000 | ||||
CPUC Authorized For Recovery PSEP Capital Costs | 766,000 | ||||
2015 GT&S phase one decision [Member] | |||||
Loss Contingencies [Line Items] | |||||
Charge for disallowed capital | 134,000 | ||||
2015 GT&S phase one decision [Member] | Estimate Of Capital Expenditures Exceeding Authorized Amounts [Member] | |||||
Loss Contingencies [Line Items] | |||||
Charge for disallowed capital | 56,000 | ||||
Pacific Gas And Electric Company [Member] | |||||
Loss Contingencies [Line Items] | |||||
Release of Escrow to California Power Exchange | (66,000) | (11,000) | |||
Charge for disallowed capital | 517,000 | $ 270,000 | |||
Utility [Member] | |||||
Loss Contingencies [Line Items] | |||||
Accrued legal liabilities | $ 84,000 | $ 84,000 | $ 63,000 | ||
[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 finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issued a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures. |
Commitments And Contingencies52
Commitments And Contingencies (Nuclear Insurance) (Details) - Diablo Canyon [Member] $ in Thousands | 9 Months Ended |
Sep. 30, 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 | Sep. 30, 2016 | Dec. 31, 2015 | |
Topock natural gas compressor station | [1] | $ 300 | $ 300 |
Hinkley natural gas compressor station | [1] | 140 | 140 |
Former manufactured gas plant sites owned by the Utility or third parties | 305 | 271 | |
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites | 143 | 164 | |
Fossil fuel-fired generation facilities and sites | 104 | 94 | |
Total environmental remediation liability | $ 992 | $ 969 | |
[1] | See "Natural Gas Compressor Station Sites" below. |
Commitments And Contingencies54
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions | Sep. 30, 2016USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 704 |
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute | $ 2,000 |