Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2017 | Jul. 21, 2017 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | PCG | |
Entity Registrant Name | PG&E CORP | |
Entity Central Index Key | 1,004,980 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 512,821,658 | |
Pacific Gas And Electric Company [Member] | ||
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | PCG | |
Entity Registrant Name | PACIFIC GAS & ELECTRIC CO | |
Entity Central Index Key | 75,488 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 264,374,809 |
Condensed Consolidated Statemen
Condensed Consolidated Statements Of Income - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Operating Revenues | ||||
Electric | $ 3,323 | $ 3,465 | $ 6,388 | $ 6,596 |
Natural gas | 927 | 704 | 2,130 | 1,547 |
Total operating revenues | 4,250 | 4,169 | 8,518 | 8,143 |
Operating Expenses | ||||
Cost of electricity | 1,123 | 1,156 | 1,970 | 2,106 |
Cost of natural gas | 121 | 75 | 446 | 297 |
Operating and maintenance | 1,546 | 1,838 | 3,050 | 3,848 |
Depreciation, amortization, and decommissioning | 712 | 699 | 1,424 | 1,396 |
Total operating expenses | 3,502 | 3,768 | 6,890 | 7,647 |
Operating Income | 748 | 401 | 1,628 | 496 |
Interest income | 8 | 5 | 13 | 9 |
Interest expense | (225) | (207) | (443) | (410) |
Other income, net | 13 | 23 | 34 | 50 |
Income Before Income Taxes | 544 | 222 | 1,232 | 145 |
Income tax provision (benefit) | 134 | 12 | 243 | (175) |
Net Income | 410 | 210 | 989 | 320 |
Preferred stock dividend requirement of subsidiary | 4 | 4 | 7 | 7 |
Income Available for Common Shareholders | $ 406 | $ 206 | $ 982 | $ 313 |
Weighted Average Common Shares Outstanding, Basic | 511 | 497 | 510 | 495 |
Weighted Average Common Shares Outstanding, Diluted | 513 | 498 | 512 | 497 |
Net Earnings Per Common Share, Basic | $ 0.79 | $ 0.41 | $ 1.93 | $ 0.63 |
Net Earnings Per Common Share, Diluted | 0.79 | 0.41 | 1.92 | 0.63 |
Dividends Declared Per Common Share | $ 0.53 | $ 0.49 | $ 1.02 | $ 0.95 |
Pacific Gas And Electric Company [Member] | ||||
Operating Revenues | ||||
Electric | $ 3,324 | $ 3,465 | $ 6,391 | $ 6,597 |
Natural gas | 926 | 704 | 2,130 | 1,547 |
Total operating revenues | 4,250 | 4,169 | 8,521 | 8,144 |
Operating Expenses | ||||
Cost of electricity | 1,123 | 1,156 | 1,970 | 2,106 |
Cost of natural gas | 121 | 75 | 446 | 297 |
Operating and maintenance | 1,545 | 1,837 | 3,049 | 3,848 |
Depreciation, amortization, and decommissioning | 712 | 700 | 1,424 | 1,396 |
Total operating expenses | 3,501 | 3,768 | 6,889 | 7,647 |
Operating Income | 749 | 401 | 1,632 | 497 |
Interest income | 7 | 4 | 12 | 8 |
Interest expense | (222) | (204) | (438) | (405) |
Other income, net | 11 | 21 | 28 | 45 |
Income Before Income Taxes | 545 | 222 | 1,234 | 145 |
Income tax provision (benefit) | 136 | 13 | 256 | (172) |
Net Income | 409 | 209 | 978 | 317 |
Preferred stock dividend requirement | 4 | 4 | 7 | 7 |
Income Available for Common Shareholders | $ 405 | $ 205 | $ 971 | $ 310 |
Condensed Consolidated Stateme3
Condensed Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Net income | $ 410 | $ 210 | $ 989 | $ 320 |
Other Comprehensive Income | ||||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 1 | 0 | 1 | 0 |
Total other comprehensive income (loss) | 1 | 0 | 1 | 0 |
Comprehensive Income | 411 | 210 | 990 | 320 |
Preferred stock dividend requirement of subsidiary | 4 | 4 | 7 | 7 |
Comprehensive Income Attributable to Common Shareholders | 407 | 206 | 983 | 313 |
Pacific Gas And Electric Company [Member] | ||||
Net income | 409 | 209 | 978 | 317 |
Other Comprehensive Income | ||||
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates) | 0 | 1 | 1 | 1 |
Total other comprehensive income (loss) | 0 | 1 | 1 | 1 |
Comprehensive Income | $ 409 | $ 210 | $ 979 | $ 318 |
Condensed Consolidated Stateme4
Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Pacific Gas And Electric Company [Member] | ||||
Pension and other postretirement benefit plans obligations tax | $ 0 | $ 0 | $ 0 | $ 0 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 178 | $ 177 |
Restricted cash | 7 | 7 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $60 and $58 at respective dates) | 1,208 | 1,252 |
Accrued unbilled revenue | 988 | 1,098 |
Regulatory balancing accounts | 1,565 | 1,500 |
Other | 760 | 801 |
Regulatory assets | 522 | 423 |
Inventories | ||
Gas stored underground and fuel oil | 132 | 117 |
Materials and supplies | 369 | 346 |
Income taxes receivable | 93 | 160 |
Other | 249 | 283 |
Total current assets | 6,071 | 6,164 |
Property, Plant, and Equipment | ||
Electric | 53,692 | 52,556 |
Gas | 18,555 | 17,853 |
Construction work in progress | 2,311 | 2,184 |
Other | 2 | 2 |
Total property, plant, and equipment | 74,560 | 72,595 |
Accumulated depreciation | (22,924) | (22,014) |
Net property, plant, and equipment | 51,636 | 50,581 |
Other Noncurrent Assets | ||
Regulatory assets | 8,311 | 7,951 |
Nuclear decommissioning trusts | 2,733 | 2,606 |
Income taxes receivable | 70 | 70 |
Other | 1,234 | 1,226 |
Total other noncurrent assets | 12,348 | 11,853 |
TOTAL ASSETS | 70,055 | 68,598 |
Current Liabilities | ||
Short-term borrowings | 1,180 | 1,516 |
Long-term debt, classified as current | 700 | 700 |
Accounts payable | ||
Trade creditors | 1,389 | 1,495 |
Regulatory balancing accounts | 871 | 645 |
Other | 423 | 433 |
Disputed claims and customer refunds | 238 | 236 |
Interest payable | 220 | 216 |
Other | 1,927 | 2,323 |
Total current liabilities | 6,948 | 7,564 |
Noncurrent Liabilities | ||
Long-term debt | 16,616 | 16,220 |
Regulatory liabilities | 7,125 | 6,805 |
Pension and other postretirement benefits | 2,687 | 2,641 |
Asset retirement obligations | 4,675 | 4,684 |
Deferred income taxes | 10,753 | 10,213 |
Other | 2,360 | 2,279 |
Total noncurrent liabilities | 44,216 | 42,842 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Common stock | 12,442 | 12,198 |
Reinvested earnings | 6,205 | 5,751 |
Accumulated other comprehensive income (loss) | (8) | (9) |
Total shareholders' equity | 18,639 | 17,940 |
Noncontrolling Interest - Preferred Stock of Subsidiary | 252 | 252 |
Total equity | 18,891 | 18,192 |
TOTAL LIABILITIES AND EQUITY | 70,055 | 68,598 |
Pacific Gas And Electric Company [Member] | ||
Current Assets | ||
Cash and cash equivalents | 57 | 71 |
Restricted cash | 7 | 7 |
Accounts receivable | ||
Customers (net of allowance for doubtful accounts of $60 and $58 at respective dates) | 1,208 | 1,252 |
Accrued unbilled revenue | 988 | 1,098 |
Regulatory balancing accounts | 1,565 | 1,500 |
Other | 758 | 801 |
Regulatory assets | 522 | 423 |
Inventories | ||
Gas stored underground and fuel oil | 132 | 117 |
Materials and supplies | 369 | 346 |
Income taxes receivable | 84 | 159 |
Other | 248 | 282 |
Total current assets | 5,938 | 6,056 |
Property, Plant, and Equipment | ||
Electric | 53,692 | 52,556 |
Gas | 18,555 | 17,853 |
Construction work in progress | 2,311 | 2,184 |
Total property, plant, and equipment | 74,558 | 72,593 |
Accumulated depreciation | (22,922) | (22,012) |
Net property, plant, and equipment | 51,636 | 50,581 |
Other Noncurrent Assets | ||
Regulatory assets | 8,311 | 7,951 |
Nuclear decommissioning trusts | 2,733 | 2,606 |
Income taxes receivable | 70 | 70 |
Other | 1,111 | 1,110 |
Total other noncurrent assets | 12,225 | 11,737 |
TOTAL ASSETS | 69,799 | 68,374 |
Current Liabilities | ||
Short-term borrowings | 1,180 | 1,516 |
Long-term debt, classified as current | 700 | 700 |
Accounts payable | ||
Trade creditors | 1,389 | 1,494 |
Regulatory balancing accounts | 871 | 645 |
Other | 468 | 453 |
Disputed claims and customer refunds | 238 | 236 |
Interest payable | 218 | 214 |
Other | 1,664 | 2,072 |
Total current liabilities | 6,728 | 7,330 |
Noncurrent Liabilities | ||
Long-term debt | 16,267 | 15,872 |
Regulatory liabilities | 7,125 | 6,805 |
Pension and other postretirement benefits | 2,592 | 2,548 |
Asset retirement obligations | 4,675 | 4,684 |
Deferred income taxes | 11,063 | 10,510 |
Other | 2,306 | 2,230 |
Total noncurrent liabilities | 44,028 | 42,649 |
Commitments and Contingencies (Note 9) | ||
Shareholders' Equity | ||
Preferred stock | 258 | 258 |
Common stock | 1,322 | 1,322 |
Additional paid-in capital | 8,240 | 8,050 |
Reinvested earnings | 9,220 | 8,763 |
Accumulated other comprehensive income (loss) | 3 | 2 |
Total shareholders' equity | 19,043 | 18,395 |
TOTAL LIABILITIES AND EQUITY | $ 69,799 | $ 68,374 |
Condensed Consolidated Balance6
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Millions, $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Allowance for doubtful accounts | $ 60 | $ 58 |
Common stock, par value | $ 0 | $ 0 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 512,220,726 | 506,891,874 |
Pacific Gas And Electric Company [Member] | ||
Allowance for doubtful accounts | $ 60 | $ 58 |
Common stock, par value | $ 5 | $ 5 |
Common stock, shares authorized | 800,000,000 | 800,000,000 |
Common stock, shares outstanding | 264,374,809 | 264,374,809 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Cash Flows from Operating Activities | ||
Net income | $ 989 | $ 320 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 1,424 | 1,396 |
Allowance for equity funds used during construction | (34) | (54) |
Deferred income taxes and tax credits, net | 516 | 350 |
Disallowed capital expenditures | 47 | 425 |
Other | 121 | 179 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | 111 | (75) |
Inventories | (38) | (30) |
Accounts payable | 19 | 179 |
Income taxes receivable/payable | 67 | (79) |
Other current assets and liabilities | (92) | (7) |
Regulatory assets, liabilities, and balancing accounts, net | (353) | (769) |
Other noncurrent assets and liabilities | 41 | (106) |
Butte-related insurance receivable | 54 | (263) |
Butte-related third-party claims | (116) | 349 |
Net cash provided by operating activities | 2,756 | 1,815 |
Cash Flows from Investing Activities | ||
Capital expenditures | (2,474) | (2,651) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 794 | 721 |
Purchases of nuclear decommissioning trust investments | (817) | (762) |
Other | 8 | 6 |
Net cash used in investing activities | (2,489) | (2,686) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $3 at respective dates | (339) | 257 |
Short-term debt financing | 250 | 250 |
Short-term debt matured | (250) | 0 |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates | 734 | 594 |
Long-term debt matured or repurchased | (345) | 0 |
Common stock issued | 247 | 289 |
Common stock dividends paid | (488) | (440) |
Other | (75) | (13) |
Net cash provided by financing activities | (266) | 937 |
Net change in cash and cash equivalents | 1 | 66 |
Cash and cash equivalents at January 1 | 177 | 123 |
Cash and cash equivalents at June 30 | 178 | 189 |
Supplemental disclosures of cash flow information | ||
Interest, net of amounts capitalized | (395) | (357) |
Income taxes, net | 68 | 54 |
Supplemental disclosures of noncash investing and financing activities | ||
Common stock dividends declared but not yet paid | 271 | 244 |
Capital expenditures financed through accounts payable | 268 | 309 |
Noncash common stock issuances | 10 | 10 |
Pacific Gas And Electric Company [Member] | ||
Cash Flows from Operating Activities | ||
Net income | 978 | 317 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation, amortization, and decommissioning | 1,424 | 1,396 |
Allowance for equity funds used during construction | (34) | (54) |
Deferred income taxes and tax credits, net | 534 | 352 |
Disallowed capital expenditures | 47 | 425 |
Other | 127 | 144 |
Effect of changes in operating assets and liabilities: | ||
Accounts receivable | 113 | (76) |
Inventories | (38) | (30) |
Accounts payable | 45 | 190 |
Income taxes receivable/payable | 75 | (78) |
Other current assets and liabilities | (72) | (5) |
Regulatory assets, liabilities, and balancing accounts, net | (353) | (769) |
Other noncurrent assets and liabilities | 40 | (95) |
Butte-related insurance receivable | 54 | (263) |
Butte-related third-party claims | (116) | 349 |
Net cash provided by operating activities | 2,824 | 1,803 |
Cash Flows from Investing Activities | ||
Capital expenditures | (2,474) | (2,651) |
Proceeds from sales and maturities of nuclear decommissioning trust investments | 794 | 721 |
Purchases of nuclear decommissioning trust investments | (817) | (762) |
Other | 8 | 6 |
Net cash used in investing activities | (2,489) | (2,686) |
Cash Flows from Financing Activities | ||
Net issuances (repayments) of commercial paper, net of discount of $3 at respective dates | (339) | 257 |
Short-term debt financing | 250 | 250 |
Short-term debt matured | (250) | 0 |
Proceeds from issuance of long-term debt, net of discount and issuance costs of $11 and $6 at respective dates | 734 | 594 |
Long-term debt matured or repurchased | (345) | 0 |
Preferred stock dividends paid | (7) | (7) |
Common stock dividends paid | (514) | (423) |
Equity contribution from PG&E Corporation | 190 | 280 |
Other | (68) | (7) |
Net cash provided by financing activities | (349) | 944 |
Net change in cash and cash equivalents | (14) | 61 |
Cash and cash equivalents at January 1 | 71 | 59 |
Cash and cash equivalents at June 30 | 57 | 120 |
Supplemental disclosures of cash flow information | ||
Interest, net of amounts capitalized | (390) | (352) |
Income taxes, net | 76 | 54 |
Supplemental disclosures of noncash investing and financing activities | ||
Capital expenditures financed through accounts payable | $ 268 | $ 309 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements Of Cash Flows (Parenthetical) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Discount on net issuances of commercial paper | $ 3 | $ 3 |
Premium, discount, and issuance costs on proceeds from long-term debt | 11 | 6 |
Pacific Gas And Electric Company [Member] | ||
Discount on net issuances of commercial paper | 3 | 3 |
Premium, discount, and issuance costs on proceeds from long-term debt | $ 11 | $ 6 |
Organization And Basis Of Prese
Organization And Basis Of Presentation | 6 Months Ended |
Jun. 30, 2017 | |
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 northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment). The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2016 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2016 Form 10-K. This quarterly report should be read in conjunction with the 2016 Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. 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 | 6 Months Ended |
Jun. 30, 2017 | |
New And Significant Accounting Policies | NOTE 2: SIGNIFICANT ACCOUNTING POLICIES The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at June 30, 2017 , 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 was not the primary beneficiary of any of these VIEs at June 30, 2017 , it did not consolidate any of them. Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $ 3.4 billion at June 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets. Pension and Other Post-retirement Benefits PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below. The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2017 and 2016 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 118 $ 113 $ 15 $ 13 Interest cost 178 179 19 19 Expected return on plan assets (192) (207) (25) (27) Amortization of prior service cost (2) 2 4 4 Amortization of net actuarial loss 5 6 1 1 Net periodic benefit cost 107 93 14 10 Regulatory account transfer (1) (23) (8) - - Total $ 84 $ 85 $ 14 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 236 $ 226 $ 30 $ 26 Interest cost 357 358 38 38 Expected return on plan assets (385) (414) (49) (54) Amortization of prior service cost (4) 4 8 8 Amortization of net actuarial loss 11 12 2 2 Net periodic benefit cost 215 186 29 20 Regulatory account transfer (1) (46) (17) - - Total $ 169 $ 169 $ 29 $ 20 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (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 June 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 3 - 3 Regulatory account transfer (net of taxes of $1 and $2, respectively) (2) (2) (4) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (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 June 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) 1 3 4 Amortization of net actuarial loss (net of taxes of $2, and $1, respectively) 4 - 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (3) (8) 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) Six Months Ended June 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $3, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $5 and $1, respectively) 6 1 7 Regulatory account transfer (net of taxes of $3 and $4, respectively) (4) (5) (9) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (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) Six Months Ended June 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 $3, respectively) 2 5 7 Amortization of net actuarial loss (net of taxes of $4 and $1, respectively) 8 1 9 Regulatory account transfer (net of taxes of $6 and $4, respectively) (10) (6) (16) 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.) There was no material difference between PG&E Corporation and the Utility for the information disclosed above. Recently Adopted Accounting Guidance 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 statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34 million for the six months ended June 30, 2016. Accounting Standards Issued But Not Yet Adopted Presentation of Net Periodic Pension Cost In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715) , which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendment requires an employer to disaggregate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. Although PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it is not expected to have a material impact to financial results. Restricted Cash In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230) , which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. As of June 30, 2017, PG&E Corporation and the Utility held immaterial balances within restricted cash. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Statements of Cash Flows and related disclosures. Recognition of Lease Assets and Liabilities In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 and will be applied on a modified retrospective basis. PG&E Corporation and the Utility are still evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities , which amends the existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts. These investments are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and the Utility do not anticipate a material impact to the Condensed Consolidated Financial Statements and related disclosures as a result of this ASU. Revenue Recognition Standard In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers , which amends existing revenue recognition guidance, effective January 1, 2018 . The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility intend to use the modified retrospective method when adopting the new standard on January 1, 2018. PG&E Corporation and the Utility are currently reviewing all revenue streams and evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures. While the Utility expects that most of its revenue will be included in the scope of ASU 2014-09, it has not yet fully completed its evaluation. The majority of the Utility’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Utility generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales. The Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group. Additionally, the Utility expects more detailed revenue disclosures related to the nature, timing and uncertainty in revenues upon adoption of ASU 2014-09. |
Regulatory Assets, Liabilities,
Regulatory Assets, Liabilities, And Balancing Accounts | 6 Months Ended |
Jun. 30, 2017 | |
Regulatory Assets, Liabilities, And Balancing Accounts | NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS Regulatory Assets and Liabilities Long-term regulatory assets and liabilities are comprised of the following: Asset Balance at (in millions) June 30, 2017 December 31, 2016 Deferred income taxes $ 4,195 $ 3,859 Pension benefits 2,467 2,429 Environmental compliance costs 770 778 Utility retained generation 342 364 Price risk management 84 92 Unamortized loss, net of gain, on reacquired debt 69 76 Other 384 353 Total long-term regulatory assets $ 8,311 $ 7,951 Liability Balance at (in millions) June 30, 2017 December 31, 2016 Cost of removal obligations $ 5,342 $ 5,060 Recoveries in excess of AROs 661 626 Public purpose programs 554 567 Other 568 552 Total long-term regulatory liabilities $ 7,125 $ 6,805 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K. Regulatory Balancing Accounts Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) June 30, 2017 December 31, 2016 Electric distribution $ 285 $ 132 Electric transmission 212 244 Utility generation 117 48 Gas distribution and transmission 433 541 Energy procurement - 132 Public purpose programs 129 106 Other 389 297 Total regulatory balancing accounts receivable $ 1,565 $ 1,500 Payable Balance at (in millions) June 30, 2017 December 31, 2016 Electric transmission $ 171 $ 99 Gas distribution and transmission - 48 Energy procurement 86 13 Public purpose programs 376 264 Other 238 221 Total regulatory balancing accounts payable $ 871 $ 645 For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K. |
Debt
Debt | 6 Months Ended |
Jun. 30, 2017 | |
Debt | NOTE 4: DEBT Revolving Credit Facilities and Commercial Paper Program The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at June 30, 2017 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2022 $ 300 (1) $ - $ - $ 300 Utility April 2022 3,000 (2) 42 681 2,277 Total revolving credit facilities $ 3,300 $ 42 $ 681 $ 2,577 (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 May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022. Other Short-term Borrowings In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid. Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 22, 2018. 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 2017, the Utility issued $400 million principal amount of 3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, 2046. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. Pollution Control Bonds In June 2017, the Utility repurchased and retired $345 million principal amount of pollution control bonds Series 2004 A through D. Additionally in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018. At June 30, 2017, 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 0.84% to 0.95%. At June 30, 2017, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 0.88%. |
Equity
Equity | 6 Months Ended |
Jun. 30, 2017 | |
Equity | NOTE 5: EQUITY PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2017 were as follows: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2016 $ 18,192 $ 18,395 Comprehensive income 990 979 Equity contributions - 190 Common stock issued 257 - Share-based compensation (13) - Common stock dividends declared (528) (514) Preferred stock dividend requirement - (7) Preferred stock dividend requirement of subsidiary (7) - Balance at June 30, 2017 $ 18,891 $ 19,043 In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate price of up to $275 million. During the six months ended June 30, 2017, PG&E Corporation sold 0.4 million shares of its common stock under the February 2017 EDA for cash proceeds of $ 28.4 million, net of commissions paid of $ 0.2 million. There were no issuances under the February 2017 EDA for the three months ended June 30, 2017. As of June 30, 2017, the remaining sales available under this agreement were $ 246.3 million. PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the six months ended June 30, 2017 , 4.9 million shares were issued for cash proceeds of $ 218 million under these plans. |
Earnings Per Share
Earnings Per Share | 6 Months Ended |
Jun. 30, 2017 | |
Earnings Per Share | NOTE 6: EARNINGS PER SHARE PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS: Three Months Ended Six Months Ended June 30, June 30, (in millions, except per share amounts) 2017 2016 2017 2016 Income available for common shareholders $ 406 $ 206 $ 982 $ 313 Weighted average common shares outstanding, basic 511 497 510 495 Add incremental shares from assumed conversions: Employee share-based compensation 2 1 2 2 Weighted average common shares outstanding, diluted 513 498 512 497 Total earnings per common share, diluted $ 0.79 $ 0.41 $ 1.92 $ 0.63 For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive. |
Derivatives
Derivatives | 6 Months Ended |
Jun. 30, 2017 | |
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 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 presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty . The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist. Price risk management activities that meet the definition of derivatives are recorded at fair value on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers. The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting. Volume of Derivative Activity The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at June 30, December 31, Underlying Product Instruments 2017 2016 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 288,947,618 323,301,331 Options 76,490,259 96,602,785 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,706,674 3,287,397 Congestion Revenue Rights (3) 254,357,332 278,143,281 (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 June 30, 2017 , 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 $ 56 $ (10) $ 16 $ 62 Other noncurrent assets – other 123 (4) - 119 Current liabilities – other (52) 10 7 (35) Noncurrent liabilities – other (88) 4 9 (75) Total commodity risk $ 39 $ - $ 32 $ 71 At December 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95 Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended Six Months Ended June 30, June 30, (in millions) 2017 2016 2017 2016 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (4) $ 66 $ (52) $ 59 Realized gain (loss) - cost of electricity (2) 1 (12) (4) (41) Realized loss - cost of natural gas (2) (3) (5) (4) (6) Net commodity risk $ (6) $ 49 $ (60) $ 12 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows. The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2017 , the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions. The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows: Balance at June 30, December 31, (in millions) 2017 2016 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (1) $ (24) Related derivatives in an asset position - 19 Collateral posting in the normal course of business related to these derivatives - 4 Net position of derivative contracts/additional collateral posting requirements (1) $ (1) $ (1) (1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies. |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2017 | |
Fair Value Measurements | NOTE 8: FAIR VALUE MEASUREMENTS PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2 – Other inputs that are directly or indirectly observable in the marketplace. Level 3 – Unobservable inputs which are supported by little or no market activities. The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At June 30, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 121 $ - $ - $ - $ 121 Nuclear decommissioning trusts Short-term investments 10 - - - 10 Global equity securities 1,786 - - - 1,786 Fixed-income securities 740 571 - - 1,311 Assets measured at NAV - - - - 16 Total nuclear decommissioning trusts (2) 2,536 571 - - 3,123 Price risk management instruments (Note 7) Electricity 5 9 158 3 175 Gas 2 5 - (1) 6 Total price risk management instruments 7 14 158 2 181 Rabbi trusts Fixed-income securities - 63 - - 63 Life insurance contracts - 71 - - 71 Total rabbi trusts - 134 - - 134 Long-term disability trust Short-term investments 5 - - - 5 Assets measured at NAV - - - - 156 Total long-term disability trust 5 - - - 161 TOTAL ASSETS $ 2,669 $ 719 $ 158 $ 2 $ 3,720 Liabilities: Price risk management instruments (Note 7) Electricity $ 12 $ 17 $ 110 $ (30) $ 109 Gas - 1 - - 1 TOTAL LIABILITIES $ 12 $ 18 $ 110 $ (30) $ 110 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 390 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management instruments 30 29 181 (18) 222 Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value. Valuation Techniques The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the six months ended June 30, 2017 and 2016 . Trust Assets Assets Measured at Fair Value In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1. Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable. Assets Measured at NAV Using Practical Expedient Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of 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 corroborated with market data are classified as Level 2. Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data. The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3. Level 3 Measurements and Sensitivity Analysis The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, 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 June 30, 2017 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 158 $ 37 Market approach CRR auction prices $ (11.88) - 10.54 Power purchase agreements $ - $ 73 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 38.80 (1) Represents price per megawatt-hour Level 3 Reconciliation The following table presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2017 and 2016 : Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of April 1 $ 49 $ 75 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (1) (9) Asset (liability) balance as of June 30 $ 48 $ 66 (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) 2017 2016 Asset (liability) balance as of January 1 $ 55 $ 89 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (7) (23) Asset (liability) balance as of June 30 $ 48 $ 66 (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 June 30, 2017 and December 31, 2016 , as they are short-term in nature or have interest rates that reset daily. The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at June 30, 2017 and December 31, 2016 . 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 June 30, 2017 At December 31, 2016 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 348 $ 352 $ 348 $ 352 Utility 16,208 18,583 15,813 17,790 Available for Sale Investments The following table provides a summary of available-for-sale investments: Total Total Amortized Unrealized Unrealized Total Fair (in millions) Cost Gains Losses Value As of June 30, 2017 Nuclear decommissioning trusts Short-term investments $ 10 $ - $ - $ 10 Global equity securities 527 1,277 (2) 1,802 Fixed-income securities 1,260 57 (6) 1,311 Total (1) $ 1,797 $ 1,334 $ (8) $ 3,123 As of December 31, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 (1) Represents amounts before deducting $ 390 million and $333 million at June 30, 2017 and December 31, 2016 , 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) June 30, 2017 Less than 1 year $ 6 1–5 years 452 5–10 years 308 More than 10 years 545 Total maturities of fixed-income securities $ 1,311 The following table provides a summary of activity for fixed income and equity securities: Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 324 $ 282 $ 794 $ 721 Gross realized gains on securities held as available-for-sale 13 4 42 9 Gross realized losses on securities held as available-for-sale (3) (1) (8) (3) |
Commitments And Contingencies
Commitments And Contingencies | 6 Months Ended |
Jun. 30, 2017 | |
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 incurred and the amount of the loss can be reasonably estimated. A gain contingency is recorded in the period in which all uncertainties have been resolved. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. 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 Butte Fire Litigation and Regulatory Citations In September 2015, a wildfire (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, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. Third-Party Claims On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management 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 Sacramento County. As of June 30, 2017, approximately 60 complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 2,050 individual plaintiffs representing approximately 1,180 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 other costs, principally based on inverse condemnation and negligence theories of liability. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases . In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include cost s that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire. Two trials have been scheduled in connection with the Butte fire. On April 14, 2017, the Superior Court of California for Sacramento County found that six “preference” households (households that include individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling) are entitled to a trial. The trial has been scheduled to commence on August 14, 2017 in Sacramento. The court also set a representative trial date for October 30, 2017 in Sacramento. A representative trial is a trial where the parties agree, or the court decides, on plaintiffs who are “representative” of broader groups of plaintiffs such that the trial may assist the parties in settling other cases after obtaining verdicts in the representative trial. Estimated Losses from Third-Party Claims 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. On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the Utility is liable for inverse condemnation. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. 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. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. The Utility believes that it is probable that it will incur a loss of at least $750 million in connection with the Butte fire. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages, but does not include punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility’s early assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility currently does not have sufficient information to reasonably estimate any liability it may have for these additional claims. The Utility currently is unable to reasonably estimate the upper end of the range of losses because it is still in an early 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 requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of potential claims from the OES and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, that the Utility could be liable for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued. The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: Loss Accrual (in millions) Balance at December 31, 2015 $ - Accrued losses 750 Payments (1) (60) Balance at December 31, 2016 $ 690 Accrued losses - Payments (1) (116) Balance at June 30, 2017 $ 574 (1) As of June 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $380 million of which $176 million has been paid by the Utility. In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $54 million in connection with the Butte fire. For the three months and six months ended June 30, 2017, the Utility has incurred legal expenses in connection with the Butte fire of $17 and $27 million, respectively. Loss Recoveries The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million. 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. Through June 30, 2017, the Utility recorded $646 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, in the second quarter of 2017, the Utility received $32 million of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain. The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: Insurance Receivable (in millions) Balance at December 31, 2015 $ - Accrued insurance recoveries 625 Reimbursements (50) Balance at December 31, 2016 $ 575 Accrued insurance recoveries 21 Reimbursements (75) Balance at June 30, 2017 $ 521 If the 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. If the Utility’s ultimate liability were to exceed amounts recoverable under its liability insurance coverage and from third parties, the Utility would expect to seek authorization from the CPUC to recover any excess amounts from customers. On July 26, 2017, the Utility filed an application with the CPUC requesting to establish a Wildfire Expense Memorandum Account to track wildfire expenses and to preserve the opportunity for the Utility to request recovery of wildfire costs in excess of insurance at a future date. The resolution of claims, the recoveries from other potentially responsible parties, and future regulatory proceedings, if any, could extend over a number of years. Regulatory Citations On April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED’s investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. The Utility paid the citations in June 2017. CPUC Matters Order Instituting an Investigation into Compliance with Ex Parte Communication Rules On March 28, 2017, the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN (together, the “parties”) jointly submitted to the CPUC a settlement agreement in connection with the order instituting an investigation into the Utility’s compliance with the CPUC’s ex parte communication rules and jointly moved for its approval. As previously disclosed, the Utility has already incurred a disallowance of $72 million imposed by the CPUC in connection with certain ex parte communications in the Utility’s 2015 GT&S rate case. Of the $72 million total GT&S ex parte disallowance, $57 million was recognized in 2016 and the remaining $15 million was recognized in the first quarter of 2017. Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $86.5 million comprised of: (1) a $1 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over its next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above. On June 19, 2017, the assigned ALJ issued a ruling requesting that the Utility file a supplemental briefing on the number of admitted violations and whether or not those violations were continuing. The Utility filed the brief on June 23, 2017, admitting that 12 communications were violations of the CPUC’s ex parte rules and noting that the additional communications at issue in the proceeding had been included by other parties and the Utility did not agree they constituted violations. The Utility did not admit that any particular violation was continuing, which would be decided by the CPUC if there were no settlement. The CPUC may accept, reject, or modify the terms of the settlement agreement, including imposing additional penalties on the Utility. The statutory deadline for this proceeding was extended from May 17, 2017 to December 29, 2017. The Utility is unable to predict the outcome of this proceeding. At June 30, 2017, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $13 million accrual for the portions of the settlement agreement that would be payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the periods in which they are incurred. For more information about the proceeding, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Order Instituting an Investigation into the Utility’s Safety Culture On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment. On May 8, 2017, the CPUC President released the consultant’s report, accompanied by a scoping memo and ruling. The scoping memo establishes a second phase in this OII in which the CPUC will evaluate the safety recommendations of the consultant which may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phase of the proceeding will also consider all necessary measures, including, but not limited to, a reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented. The Utility plans to adopt the vast majority of the consultant’s recommendations and to have completed most of the agreed-upon recommendations by the middle of 2018. A prehearing conference has been scheduled for August 1, 2017. Under the current schedule, the Utility’s testimony is expected to occur in the fourth quarter of 2017 with other parties’ testimony and evidentiary hearings expected in the first quarter of 2018. PG&E Corporation and the Utility are unable to predict the outcome of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity for the Utility be dependent on making safety progress as the CPUC may define in this proceeding. Natural Gas Transmission Pipeline Rights-of-Way In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. T he Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties. Potential Safety Citations The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, on which the SED has yet to act. This includes the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will impose penalties or take other enforcement action with respect to some or all of these violations. 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 and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines. The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED historically has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even after the SED has issued a citation. 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. Federal Investigations In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. 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 contained an osprey nest and egg in Inverness, California, on March 18, 2016. The utility is cooperating with this investigation. It is uncertain whether any charges will be brought against the Utility as a result of these investigations. Other Matters 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 related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $43 million at June 30, 2017 and $45 million at December 31, 2016. These amounts are included in Other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. Disallowance of Plant Costs In May 2017, the Utility filed a settlement agreement with the CPUC related to the recovery of license renewal costs and cancelled project costs within its pending application to retire Diablo Canyon Power Plant. The settlement agreement allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the three and six months ended June 30, 2017, the Utility incurred charges of $47 million related to settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs. In addition, the Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. Charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending related to its 2015 GT&S rate case. PG&E Corporation and the Utility would 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 operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. Environmental Remediation Contingencies The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following: Balance at June 30, December 31, (in millions) 2017 2016 Topock natural gas compressor station (1) $ 313 $ 299 Hinkley natural gas compressor station (1) 128 135 Former manufactured gas plant sites owned by the Utility or third parties 319 285 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 131 131 Fossil fuel-fired generation facilities and sites 124 108 Total environmental remediation liability $ 1,015 $ 958 (1) See “Natural Gas Compressor Station Sites” below. The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility’s environmental remediation liability at June 30, 2017 reflects its best estimate of probable future costs associated with its final remediation plans. 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 remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on the Utility’s future financial condition and cash flows. At June 30, 2017 , the Utility expected to recover $ 718 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates. Natural Gas Compressor Station Sites The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Needles, California and is referred to below as the “Topock site.” Another station is located near Hinkley, California and is referred to below as the “Hinkley site.” The Utility is also required to take measures to abate the effects of the contamination on the environment. Topock Site The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in late 2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in 2018. Hinkley Site The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the Regional Board. In November 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets. Reasonably Possible Environmental Contingencies Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase by as much as $ 1.0 billion (including amounts related to the Topock and Hinkley sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. Nuclear Insurance The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non- nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a maximum aggregate annual retrospective premium obligation of approximately $ 58 million. EMANI provides $ 200 million for any one accident and in the annual aggregate the excess of the combined amount recoverable under the Utility’s NEIL policies. For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K. Resolution of Remaining Chapter 11 Disputed Claims Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility has entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods. At December 31, 2016, the Consolidated Balance Sheets reflected $236 million in net claims within Disputed claims and customer refunds. There were no significant changes to this balance during the six months ended June 30, 2017. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved. Tax Matters PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of June 30, 2017 , it is reasonably possible that unrecognized tax benefits will decrease by approximately $ 70 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. Gain Contingencies Litigation Related to the San Bruno Accident As of June 30, 2017, there were seven shareholder derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by certain current and former officers and directors (the “Individual Defendants”), among other claims. Four of the cases were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo (the “Court”). The remaining th |
New And Significant Accountin18
New And Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
Variable Interest Entities | Variable Interest Entities A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at June 30, 2017 , 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 was not the primary beneficiary of any of these VIEs at June 30, 2017 , it did not consolidate any of them. |
Asset Retirement Obligations | Asset Retirement Obligations Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the Condensed Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was $ 3.4 billion at June 30, 2017, and $3.5 billion at December 31, 2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets. |
Recently Adopted Accounting Guidance | Recently Adopted Accounting Guidance 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 statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016. ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $34 million for the six months ended June 30, 2016. |
New And Significant Accountin19
New And Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Components Of Net Periodic Benefit Cost | The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2017 and 2016 were as follows: Pension Benefits Other Benefits Three Months Ended June 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 118 $ 113 $ 15 $ 13 Interest cost 178 179 19 19 Expected return on plan assets (192) (207) (25) (27) Amortization of prior service cost (2) 2 4 4 Amortization of net actuarial loss 5 6 1 1 Net periodic benefit cost 107 93 14 10 Regulatory account transfer (1) (23) (8) - - Total $ 84 $ 85 $ 14 $ 10 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. Pension Benefits Other Benefits Six Months Ended June 30, (in millions) 2017 2016 2017 2016 Service cost for benefits earned $ 236 $ 226 $ 30 $ 26 Interest cost 357 358 38 38 Expected return on plan assets (385) (414) (49) (54) Amortization of prior service cost (4) 4 8 8 Amortization of net actuarial loss 11 12 2 2 Net periodic benefit cost 215 186 29 20 Regulatory account transfer (1) (46) (17) - - Total $ 169 $ 169 $ 29 $ 20 (1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates. |
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income | 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 June 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1) 3 2 Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) 3 - 3 Regulatory account transfer (net of taxes of $1 and $2, respectively) (2) (2) (4) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (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 June 30, 2016 Beginning balance $ (23) $ 16 $ (7) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $1 and $1, respectively) 1 3 4 Amortization of net actuarial loss (net of taxes of $2, and $1, respectively) 4 - 4 Regulatory account transfer (net of taxes of $3 and $2, respectively) (5) (3) (8) 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) Six Months Ended June 30, 2017 Beginning balance $ (25) $ 16 $ (9) Amounts reclassified from other comprehensive income: (1) Amortization of prior service cost (net of taxes of $2 and $3, respectively) (2) 5 3 Amortization of net actuarial loss (net of taxes of $5 and $1, respectively) 6 1 7 Regulatory account transfer (net of taxes of $3 and $4, respectively) (4) (5) (9) Net current period other comprehensive gain (loss) - 1 1 Ending balance $ (25) $ 17 $ (8) (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) Six Months Ended June 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 $3, respectively) 2 5 7 Amortization of net actuarial loss (net of taxes of $4 and $1, respectively) 8 1 9 Regulatory account transfer (net of taxes of $6 and $4, respectively) (10) (6) (16) 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.) |
Regulatory Assets, Liabilitie20
Regulatory Assets, Liabilities, And Balancing Accounts (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Long-Term Regulatory Assets | Long-term regulatory assets and liabilities are comprised of the following: Asset Balance at (in millions) June 30, 2017 December 31, 2016 Deferred income taxes $ 4,195 $ 3,859 Pension benefits 2,467 2,429 Environmental compliance costs 770 778 Utility retained generation 342 364 Price risk management 84 92 Unamortized loss, net of gain, on reacquired debt 69 76 Other 384 353 Total long-term regulatory assets $ 8,311 $ 7,951 |
Long-Term Regulatory Liabilities | Liability Balance at (in millions) June 30, 2017 December 31, 2016 Cost of removal obligations $ 5,342 $ 5,060 Recoveries in excess of AROs 661 626 Public purpose programs 554 567 Other 568 552 Total long-term regulatory liabilities $ 7,125 $ 6,805 |
Regulatory Balancing Accounts Receivable | Current regulatory balancing accounts receivable and payable are comprised of the following: Receivable Balance at (in millions) June 30, 2017 December 31, 2016 Electric distribution $ 285 $ 132 Electric transmission 212 244 Utility generation 117 48 Gas distribution and transmission 433 541 Energy procurement - 132 Public purpose programs 129 106 Other 389 297 Total regulatory balancing accounts receivable $ 1,565 $ 1,500 |
Regulatory Balancing Accounts Payable | Payable Balance at (in millions) June 30, 2017 December 31, 2016 Electric transmission $ 171 $ 99 Gas distribution and transmission - 48 Energy procurement 86 13 Public purpose programs 376 264 Other 238 221 Total regulatory balancing accounts payable $ 871 $ 645 |
Debt (Tables)
Debt (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Disclosure Debt [Abstract] | |
Schedule Of Debt | The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at June 30, 2017 : Letters of Termination Facility Credit Commercial Facility (in millions) Date Limit Outstanding Paper Availability PG&E Corporation April 2022 $ 300 (1) $ - $ - $ 300 Utility April 2022 3,000 (2) 42 681 2,277 Total revolving credit facilities $ 3,300 $ 42 $ 681 $ 2,577 (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) | 6 Months Ended |
Jun. 30, 2017 | |
Changes In Equity | PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2017 were as follows: PG&E Corporation Utility Total Total (in millions) Equity Shareholders' Equity Balance at December 31, 2016 $ 18,192 $ 18,395 Comprehensive income 990 979 Equity contributions - 190 Common stock issued 257 - Share-based compensation (13) - Common stock dividends declared (528) (514) Preferred stock dividend requirement - (7) Preferred stock dividend requirement of subsidiary (7) - Balance at June 30, 2017 $ 18,891 $ 19,043 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted | Three Months Ended Six Months Ended June 30, June 30, (in millions, except per share amounts) 2017 2016 2017 2016 Income available for common shareholders $ 406 $ 206 $ 982 $ 313 Weighted average common shares outstanding, basic 511 497 510 495 Add incremental shares from assumed conversions: Employee share-based compensation 2 1 2 2 Weighted average common shares outstanding, diluted 513 498 512 497 Total earnings per common share, diluted $ 0.79 $ 0.41 $ 1.92 $ 0.63 |
Derivatives (Tables)
Derivatives (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Volumes Of Outstanding Derivative Contracts | The volumes of the Utility’s outstanding derivatives were as follows: Contract Volume at June 30, December 31, Underlying Product Instruments 2017 2016 Natural Gas (1) (MMBtus (2) ) Forwards, Futures and Swaps 288,947,618 323,301,331 Options 76,490,259 96,602,785 Electricity (Megawatt-hours) Forwards, Futures and Swaps 3,706,674 3,287,397 Congestion Revenue Rights (3) 254,357,332 278,143,281 (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 June 30, 2017 , 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 $ 56 $ (10) $ 16 $ 62 Other noncurrent assets – other 123 (4) - 119 Current liabilities – other (52) 10 7 (35) Noncurrent liabilities – other (88) 4 9 (75) Total commodity risk $ 39 $ - $ 32 $ 71 At December 31, 2016 , the Utility’s outstanding derivative balances were as follows: Commodity Risk Gross Derivative Total Derivative (in millions) Balance Netting Cash Collateral Balance Current assets – other $ 91 $ (10) $ 1 $ 82 Other noncurrent assets – other 149 (9) - 140 Current liabilities – other (48) 10 - (38) Noncurrent liabilities – other (101) 9 3 (89) Total commodity risk $ 91 $ - $ 4 $ 95 |
Gains And Losses On Derivative Instruments | Gains and losses associated with price risk management activities were recorded as follows: Commodity Risk Three Months Ended Six Months Ended June 30, June 30, (in millions) 2017 2016 2017 2016 Unrealized gain (loss) - regulatory assets and liabilities (1) $ (4) $ 66 $ (52) $ 59 Realized gain (loss) - cost of electricity (2) 1 (12) (4) (41) Realized loss - cost of natural gas (2) (3) (5) (4) (6) Net commodity risk $ (6) $ 49 $ (60) $ 12 (1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered | The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows: Balance at June 30, December 31, (in millions) 2017 2016 Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized $ (1) $ (24) Related derivatives in an asset position - 19 Collateral posting in the normal course of business related to these derivatives - 4 Net position of derivative contracts/additional collateral posting requirements (1) $ (1) $ (1) (1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Assets And Liabilities Measured At Fair Value On A Recurring Basis | Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. Fair Value Measurements At June 30, 2017 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 121 $ - $ - $ - $ 121 Nuclear decommissioning trusts Short-term investments 10 - - - 10 Global equity securities 1,786 - - - 1,786 Fixed-income securities 740 571 - - 1,311 Assets measured at NAV - - - - 16 Total nuclear decommissioning trusts (2) 2,536 571 - - 3,123 Price risk management instruments (Note 7) Electricity 5 9 158 3 175 Gas 2 5 - (1) 6 Total price risk management instruments 7 14 158 2 181 Rabbi trusts Fixed-income securities - 63 - - 63 Life insurance contracts - 71 - - 71 Total rabbi trusts - 134 - - 134 Long-term disability trust Short-term investments 5 - - - 5 Assets measured at NAV - - - - 156 Total long-term disability trust 5 - - - 161 TOTAL ASSETS $ 2,669 $ 719 $ 158 $ 2 $ 3,720 Liabilities: Price risk management instruments (Note 7) Electricity $ 12 $ 17 $ 110 $ (30) $ 109 Gas - 1 - - 1 TOTAL LIABILITIES $ 12 $ 18 $ 110 $ (30) $ 110 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $ 390 million, primarily related to deferred taxes on appreciation of investment value. Fair Value Measurements At December 31, 2016 (in millions) Level 1 Level 2 Level 3 Netting (1) Total Assets: Short-term investments $ 105 $ - $ - $ - $ 105 Nuclear decommissioning trusts Short-term investments 9 - - - 9 Global equity securities 1,724 - - - 1,724 Fixed-income securities 665 527 - - 1,192 Assets measured at NAV - - - - 14 Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity 30 18 181 (18) 211 Gas - 11 - - 11 Total price risk management instruments 30 29 181 (18) 222 Rabbi trusts Fixed-income securities - 61 - - 61 Life insurance contracts - 70 - - 70 Total rabbi trusts - 131 - - 131 Long-term disability trust Short-term investments 8 - - - 8 Assets measured at NAV - - - - 170 Total long-term disability trust 8 - - - 178 TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 Liabilities: Price risk management instruments (Note 9 in the 2016 Form 10-K) Electricity $ 9 $ 12 $ 126 $ (21) $ 126 Gas - 2 - (1) 1 TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 (1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. (2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value. |
Level 3 Measurements And Sensitivity Analysis | Fair Value at (in millions) At June 30, 2017 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 158 $ 37 Market approach CRR auction prices $ (11.88) - 10.54 Power purchase agreements $ - $ 73 Discounted cash flow Forward prices $ 18.81 - 38.80 (1) Represents price per megawatt-hour Fair Value at (in millions) At December 31, 2016 Valuation Unobservable Fair Value Measurement Assets Liabilities Technique Input Range (1) Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 Power purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 38.80 (1) Represents price per megawatt-hour |
Level 3 Reconciliation | The following table presents the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2017 and 2016 : Price Risk Management Instruments (in millions) 2017 2016 Asset (liability) balance as of April 1 $ 49 $ 75 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (1) (9) Asset (liability) balance as of June 30 $ 48 $ 66 (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) 2017 2016 Asset (liability) balance as of January 1 $ 55 $ 89 Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts (1) (7) (23) Asset (liability) balance as of June 30 $ 48 $ 66 (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 | 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 June 30, 2017 At December 31, 2016 (in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value PG&E Corporation $ 348 $ 352 $ 348 $ 352 Utility 16,208 18,583 15,813 17,790 |
Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments | The following table provides a summary of available-for-sale investments: Total Total Amortized Unrealized Unrealized Total Fair (in millions) Cost Gains Losses Value As of June 30, 2017 Nuclear decommissioning trusts Short-term investments $ 10 $ - $ - $ 10 Global equity securities 527 1,277 (2) 1,802 Fixed-income securities 1,260 57 (6) 1,311 Total (1) $ 1,797 $ 1,334 $ (8) $ 3,123 As of December 31, 2016 Nuclear decommissioning trusts Short-term investments $ 9 $ - $ - $ 9 Global equity securities 584 1,157 (3) 1,738 Fixed-income securities 1,156 48 (12) 1,192 Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 (1) Represents amounts before deducting $ 390 million and $333 million at June 30, 2017 and December 31, 2016 , respectively, primarily related to deferred taxes on appreciation of investment value. |
Schedule Of Maturities On Debt Instruments | The fair value of fixed-income securities by contractual maturity is as follows: As of (in millions) June 30, 2017 Less than 1 year $ 6 1–5 years 452 5–10 years 308 More than 10 years 545 Total maturities of fixed-income securities $ 1,311 |
Schedule Of Activity For Debt And Equity Securities | The following table provides a summary of activity for fixed income and equity securities: Three Months Ended Six Months Ended June 30, June 30, 2017 2016 2017 2016 (in millions) Proceeds from sales and maturities of nuclear decommissioning trust investments $ 324 $ 282 $ 794 $ 721 Gross realized gains on securities held as available-for-sale 13 4 42 9 Gross realized losses on securities held as available-for-sale (3) (1) (8) (3) |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Change In Accruals Related To Third-Party Claims | The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: Loss Accrual (in millions) Balance at December 31, 2015 $ - Accrued losses 750 Payments (1) (60) Balance at December 31, 2016 $ 690 Accrued losses - Payments (1) (116) Balance at June 30, 2017 $ 574 (1) As of June 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $380 million of which $176 million has been paid by the Utility. |
Schedule Of Environmental Remediation Liability | The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following: Balance at June 30, December 31, (in millions) 2017 2016 Topock natural gas compressor station (1) $ 313 $ 299 Hinkley natural gas compressor station (1) 128 135 Former manufactured gas plant sites owned by the Utility or third parties 319 285 Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites 131 131 Fossil fuel-fired generation facilities and sites 124 108 Total environmental remediation liability $ 1,015 $ 958 (1) See “Natural Gas Compressor Station Sites” below. |
Insurance Receivable [Text Block] | The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets: Insurance Receivable (in millions) Balance at December 31, 2015 $ - Accrued insurance recoveries 625 Reimbursements (50) Balance at December 31, 2016 $ 575 Accrued insurance recoveries 21 Reimbursements (75) Balance at June 30, 2017 $ 521 |
New And Significant Accountin27
New And Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Total nuclear decommissioning asset retirement obligation | $ 3,400,000 | $ 3,400,000 | $ 3,500,000 | |
Reduction to ARO | 66,000 | |||
Decrease to cash flow from financing activities | (75,000) | $ (13,000) | ||
2015 NDCTP Adopted Amounts | 3,500,000 | 3,500,000 | ||
2015 NDCTP Requested Amounts | 4,800,000 | 4,800,000 | ||
Diablo Canyon [Member] | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
2015 NDCTP Adopted Amounts | 2,400,000 | 2,400,000 | ||
2015 NDCTP Requested Amounts | $ 3,800,000 | $ 3,800,000 | ||
Percentage Of Decommissioning Cost Estimate Approved | 64.00% | 64.00% | ||
Humboldt Bay Unit [Member] | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
2015 NDCTP Adopted Amounts | $ 1,100,000 | $ 1,100,000 | ||
Pacific Gas And Electric Company [Member] | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Decrease to cash flow from financing activities | $ (68,000) | (7,000) | ||
New Accounting Pronouncement [Member] | ||||
Public Utility, Property, Plant and Equipment [Line Items] | ||||
Decrease to cash flow from financing activities | $ 34,000 |
New And Significant Accountin28
New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |||
Pension Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost for benefits earned | $ 118 | $ 113 | $ 236 | $ 226 | ||
Interest cost | 178 | 179 | 357 | 358 | ||
Expected return on plan assets | (192) | (207) | (385) | (414) | ||
Amortization of prior service cost | (2) | 2 | (4) | 4 | ||
Amortization of net actuarial loss | 5 | 6 | 11 | 12 | ||
Net periodic benefit cost | 107 | 93 | 215 | 186 | ||
Regulatory account transfer | (23) | [1] | (8) | [1] | (46) | (17) |
Total | 84 | 85 | 169 | 169 | ||
Other Benefits [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost for benefits earned | 15 | 13 | 30 | 26 | ||
Interest cost | 19 | 19 | 38 | 38 | ||
Expected return on plan assets | (25) | (27) | (49) | (54) | ||
Amortization of prior service cost | 4 | 4 | 8 | 8 | ||
Amortization of net actuarial loss | 1 | 1 | 2 | 2 | ||
Net periodic benefit cost | 14 | 10 | 29 | 20 | ||
Regulatory account transfer | 0 | [1] | 0 | [1] | 0 | 0 |
Total | $ 14 | $ 10 | $ 29 | $ 20 | ||
[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 | 6 Months Ended | ||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ||||||
Beginning balance | $ (9) | $ (7) | $ (9) | $ (7) | ||
Net current period other comprehensive income (loss) | 1 | 0 | 1 | 0 | ||
Ending balance | (8) | (7) | (8) | (7) | ||
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 | 2 | [1] | 4 | [1] | 3 | 7 |
Amortization of net actuarial loss | 3 | [1] | 4 | [1] | 7 | 9 |
Regulatory account transfer | (4) | [1] | (8) | [1] | (9) | (16) |
Pension Benefits [Member] | ||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ||||||
Beginning balance | (25) | (23) | (25) | (23) | ||
Amortization of prior service cost | (2) | 2 | (4) | 4 | ||
Amortization of net actuarial loss | 5 | 6 | 11 | 12 | ||
Net current period other comprehensive income (loss) | 0 | 0 | 0 | 0 | ||
Ending balance | (25) | (23) | (25) | (23) | ||
Pension Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | ||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ||||||
Amortization of prior service cost | (1) | [1] | 1 | [1] | (2) | 2 |
Amortization of net actuarial loss | 3 | [1] | 4 | [1] | 6 | 8 |
Regulatory account transfer | (2) | [1] | (5) | [1] | (4) | (10) |
Amortization of prior service cost tax | 1 | 1 | 2 | 2 | ||
Net actuarial loss tax | 2 | 2 | 5 | 4 | ||
Regulatory account transfer tax | 1 | 3 | 3 | 6 | ||
Other Benefits [Member] | ||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ||||||
Beginning balance | 16 | 16 | 16 | 16 | ||
Amortization of prior service cost | 4 | 4 | 8 | 8 | ||
Amortization of net actuarial loss | 1 | 1 | 2 | 2 | ||
Net current period other comprehensive income (loss) | 1 | 0 | 1 | 0 | ||
Ending balance | 17 | 16 | 17 | 16 | ||
Other Benefits [Member] | Amounts Reclassified From Other Comprehensive Income [Member] | ||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ||||||
Amortization of prior service cost | 3 | [1] | 3 | [1] | 5 | 5 |
Amortization of net actuarial loss | 0 | [1] | 0 | [1] | 1 | 1 |
Regulatory account transfer | (2) | [1] | (3) | [1] | (5) | (6) |
Amortization of prior service cost tax | 1 | 1 | 3 | 3 | ||
Net actuarial loss tax | 1 | 1 | 1 | 1 | ||
Regulatory account transfer tax | $ 2 | $ 2 | $ 4 | $ 4 | ||
[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 | Jun. 30, 2017 | Dec. 31, 2016 |
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 8,311 | $ 7,951 |
Pension Benefits [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 2,467 | 2,429 |
Deferred Income Taxes [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 4,195 | 3,859 |
Utility Retained Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 342 | 364 |
Environmental Compliance Costs [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 770 | 778 |
Price Risk Management [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 84 | 92 |
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | 69 | 76 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Assets [Line Items] | ||
Total long-term regulatory assets | $ 384 | $ 353 |
Regulatory Assets, Liabilitie31
Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 7,125 | $ 6,805 |
Cost Of Removal Obligations [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 5,342 | 5,060 |
Recoveries In Excess Of AROs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 661 | 626 |
Public Purpose Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | 554 | 567 |
Other Long Term Regulatory Assets (Liabilities) [Member] | ||
Regulatory Liabilities [Line Items] | ||
Total long-term regulatory liabilities | $ 568 | $ 552 |
Regulatory Assets, Liabilitie32
Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Regulatory Balancing Accounts Receivable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 1,565 | $ 1,500 |
Regulatory Balancing Accounts Receivable [Member] | Electric Distribution [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 285 | 132 |
Regulatory Balancing Accounts Receivable [Member] | Utility Generation [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 117 | 48 |
Regulatory Balancing Accounts Receivable [Member] | Gas Distribution and Transmission [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 433 | 541 |
Regulatory Balancing Accounts Receivable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 0 | 132 |
Regulatory Balancing Accounts Receivable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 129 | 106 |
Regulatory Balancing Accounts Receivable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 389 | 297 |
Regulatory Balancing Accounts Receivable [Member] | Electric Transmission [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 212 | 244 |
Regulatory Balancing Accounts Payable [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 871 | 645 |
Regulatory Balancing Accounts Payable [Member] | Gas Distribution and Transmission [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 0 | 48 |
Regulatory Balancing Accounts Payable [Member] | Energy Procurement [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 86 | 13 |
Regulatory Balancing Accounts Payable [Member] | Public Purpose Programs [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 376 | 264 |
Regulatory Balancing Accounts Payable [Member] | Other Current Balancing Accounts [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | 238 | 221 |
Regulatory Balancing Accounts Payable [Member] | Electric Transmission [Member] | ||
Regulatory Assets [Line Items] | ||
Total regulatory balancing accounts, net | $ 171 | $ 99 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - Utility [Member] - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Mar. 31, 2017 | |
Debt [Line Items] | ||
Short term borrowing outstanding | $ 250 | |
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-B [Member] | ||
Debt [Line Items] | ||
Debt instrument, face amount | 149 | |
Pollution Control Bonds Series 2004 A-D [Member] | ||
Debt [Line Items] | ||
Repayments Of Pollution Control Bond | 345 | |
Pollution Control Bonds Series 2008 F, G, and 2010 E [Member] | ||
Debt [Line Items] | ||
Debt instrument, face amount | $ 145 | |
Pollution Control Bonds Series 2008 G [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 1.05% | |
Pollution Control Bonds Series Two Thousand Eight F And Two Thousand Ten E [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 1.75% | |
Senior Notes, 4.00%, Due 2046 [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 4.00% | |
Senior Notes | $ 200 | |
Senior Notes, 3.30%, Due 2027 [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 3.30% | |
Senior Notes | $ 400 | |
Minimum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 0.84% | |
Minimum [Member] | Pollution Control Bonds Series 2009 A-B [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 0.88% | |
Maximum [Member] | Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 0.95% | |
Maximum [Member] | Pollution Control Bonds Series 2009 A-B [Member] | ||
Debt [Line Items] | ||
Debt instrument, interest rate | 0.88% | |
Floating Rate Senior Notes [Member] | ||
Debt [Line Items] | ||
Floating rate unsecured term loan, matured 2017 | $ 250 |
Debt (Schedule Of Line Of Credi
Debt (Schedule Of Line Of Credit) (Details) $ in Millions | 6 Months Ended | |
Jun. 30, 2017USD ($) | ||
Pacific Gas And Electric Company [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2022 | |
Letters of Credit Sublimit | $ 500 | |
Utility [Member] | ||
Debt [Line Items] | ||
Facility limit | 3,000 | [1] |
Letters Of Credit Outstanding Amount | 42 | |
Commercial Paper | 681 | |
Facility Availability | 2,277 | |
Swingline Loans Sublimit | $ 75 | |
P G E Corporation [Member] | ||
Debt [Line Items] | ||
Expiration date for credit agreement | Apr. 27, 2022 | |
Facility limit | $ 300 | [2] |
Letters Of Credit Outstanding Amount | 0 | |
Commercial Paper | 0 | |
Facility Availability | 300 | |
Letters of Credit Sublimit | 50 | |
Swingline Loans Sublimit | $ 100 | |
Swingline Loan Repay Term | 7 days | |
Credit Facilities [Member] | ||
Debt [Line Items] | ||
Facility limit | $ 3,300 | |
Letters Of Credit Outstanding Amount | 42 | |
Commercial Paper | 681 | |
Facility Availability | $ 2,577 | |
[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 | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Common Stock Value | $ 12,442,000 | $ 12,198,000 |
Pacific Gas And Electric Company [Member] | ||
Common Stock Value | $ 1,322,000 | $ 1,322,000 |
Equity Contract [Member] | ||
Equity Distribution Agreement, shares issued | 400,000 | |
Remaining equity distribution agreement amount | $ 246,000 | |
Fees and commissions | 200 | |
Stock Issued During Period Value Under Equity Distribution Agreement | 28,000 | |
Equity Distribution Agreement Total Contract Value | $ 275,000 | |
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 | 4,900,000 | |
Stock Issued During Period Value Stock Options Exercised | $ 218,000 |
Equity (Changes In Equity) (Det
Equity (Changes In Equity) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Balance at December 31, 2016 | $ 17,940 | |||
Balance at December 31, 2016 | 18,192 | |||
Comprehensive Income Net Of Tax | $ 411 | $ 210 | 990 | $ 320 |
Common stock issued | 257 | |||
Share-based compensation | 13 | |||
Common stock dividends declared | (528) | |||
Preferred stock dividend requirement of subsidiary | (4) | (4) | (7) | (7) |
Balance at June 30, 2017 | 18,891 | 18,891 | ||
Balance at June 30, 2017 | 18,639 | 18,639 | ||
Pacific Gas And Electric Company [Member] | ||||
Balance at December 31, 2016 | 18,395 | |||
Comprehensive Income Net Of Tax | 409 | 210 | 979 | 318 |
Common stock issued | 0 | |||
Share-based compensation | 0 | |||
Common stock dividends declared | (514) | |||
Preferred stock dividend requirement | (4) | $ (4) | (7) | (7) |
Equity contributions | 190 | $ 280 | ||
Balance at June 30, 2017 | $ 19,043 | $ 19,043 |
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 | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Income available for common shareholders | $ 406 | $ 206 | $ 982 | $ 313 |
Weighted average common shares outstanding, basic | 511 | 497 | 510 | 495 |
Employee share-based compensation | 2 | 1 | 2 | 2 |
Weighted average common shares outstanding, diluted | 513 | 498 | 512 | 497 |
Total earnings per common share, diluted | $ 0.79 | $ 0.41 | $ 1.92 | $ 0.63 |
Derivatives (Volumes Of Outstan
Derivatives (Volumes Of Outstanding Derivative Contracts, In Megawatt Hours Unless Otherwise Specified) (Details) | Jun. 30, 2017 | Dec. 31, 2016 | |
Forwards And Swaps [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 288,947,618 | 323,301,331 |
Forwards And Swaps [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | 3,706,674 | 3,287,397 | |
Options [Member] | Natural Gas [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [1],[2] | 76,490,259 | 96,602,785 |
Congestion Revenue Rights [Member] | Electricity [Member] | |||
Derivative [Line Items] | |||
Derivative Number Of Instruments Held | [3] | 254,357,332 | 278,143,281 |
[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 | Jun. 30, 2017 | Dec. 31, 2016 |
Other Current Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | $ 56 | $ 91 |
Cash Collateral | 16 | 1 |
Total Derivative Balance | 62 | 82 |
Netting | (10) | (10) |
Other Noncurrent Assets [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 123 | 149 |
Cash Collateral | 0 | 0 |
Total Derivative Balance | 119 | 140 |
Netting | (4) | (9) |
Other Current Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (52) | (48) |
Cash Collateral | 7 | 0 |
Total Derivative Balance | (35) | (38) |
Netting | 10 | 10 |
Other Noncurrent Liabilities [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | (88) | (101) |
Cash Collateral | 9 | 3 |
Total Derivative Balance | (75) | (89) |
Netting | 4 | 9 |
Gross Derivative Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Gross Derivative Balance | 39 | 91 |
Netting [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Netting | 0 | 0 |
Cash Collateral [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Cash Collateral | 32 | 4 |
Total Derivatve Balance [Member] | ||
Derivatives And Hedging Activities [Line Items] | ||
Total Derivative Balance | $ 71 | $ 95 |
Derivatives (Gains And Losses O
Derivatives (Gains And Losses On Derivative Instruments) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | ||
Net unrealized loss - regulatory assets and liabilities | $ (4) | [1] | $ 66 | $ (52) | $ 59 |
Realized loss - cost of electricity | 1 | [2] | (12) | (4) | (41) |
Realized loss - cost of natural gas | (3) | (5) | (4) | (6) | |
Total commodity risk | $ (6) | $ 49 | $ (60) | $ 12 | |
[1] | Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. | ||||
[2] | These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. |
Derivatives (Additional Cash Co
Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 | |
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized | $ (1) | $ (24) | |
Related derivatives in an asset position | 0 | 19 | |
Collateral posting in the normal course of business related to these derivatives | 0 | 4 | |
Net position of derivative contracts/additional collateral posting requirements | [1] | $ (1) | $ (1) |
[1] | This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies. |
Fair Value Measurements (Assets
Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | $ 121 | $ 105 | ||
Total assets | 3,720 | 3,575 | ||
Electricity | 109 | 126 | ||
Natural Gas | 1 | 1 | ||
Total liabilities | 110 | 127 | ||
Amount primarily related to deferred taxes on appreciation of investment value | 390 | [1] | 333 | [2] |
Nuclear Decommissioning Trusts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | 10 | 9 | ||
Total assets | 3,123 | [1] | 2,939 | [2] |
Fixed-income securities | 1,311 | 1,192 | ||
Global equity securities | 1,786 | 1,724 | ||
Financial Instruments Measured At NAV | 16 | 14 | ||
Price Risk Management Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total assets | 181 | 222 | ||
Electricity | 175 | 211 | ||
Natural Gas | 6 | 11 | ||
Rabbi Trusts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total assets | 134 | 131 | ||
Fixed-income securities | 63 | 61 | ||
Life insurance contracts | 71 | 70 | ||
Long-Term Disability Trust [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | 5 | 8 | ||
Total assets | 161 | 178 | ||
Financial Instruments Measured At NAV | 156 | 170 | ||
Fair Value Measurements, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | 121 | 105 | ||
Total assets | 2,669 | 2,541 | ||
Total liabilities | 12 | 9 | ||
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 | 10 | 9 | ||
Total assets | 2,536 | [1] | 2,398 | [2] |
Fixed-income securities | 740 | 665 | ||
Global equity securities | 1,786 | 1,724 | ||
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 | 7 | 30 | ||
Electricity | 5 | 30 | ||
Natural Gas | 2 | 0 | ||
Electricity | 12 | 9 | ||
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 | 5 | 8 | ||
Total assets | 5 | 8 | ||
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 | 719 | 687 | ||
Total liabilities | 18 | 14 | ||
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 | 571 | [1] | 527 | [2] |
Fixed-income securities | 571 | 527 | ||
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 | 14 | 29 | ||
Electricity | 9 | 18 | ||
Natural Gas | 5 | 11 | ||
Electricity | 17 | 12 | ||
Natural Gas | 1 | 2 | ||
Fair Value Measurements, Level 2 [Member] | Rabbi Trusts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total assets | 134 | 131 | ||
Fixed-income securities | 63 | 61 | ||
Life insurance contracts | 71 | 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 | 158 | 181 | ||
Total liabilities | 110 | 126 | ||
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 | 158 | 181 | ||
Electricity | 158 | 181 | ||
Natural Gas | 0 | 0 | ||
Electricity | 110 | 126 | ||
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 | 0 | 0 | [3] | |
Total assets | 2 | (18) | [3] | |
Total liabilities | (30) | (22) | [3] | |
Netting [Member] | Nuclear Decommissioning Trusts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | 0 | 0 | [3] | |
Total assets | 0 | [1] | 0 | [2],[3] |
Fixed-income securities | 0 | 0 | [3] | |
Global equity securities | 0 | 0 | [3] | |
Financial Instruments Measured At NAV | 0 | 0 | [3] | |
Netting [Member] | Price Risk Management Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total assets | 2 | (18) | [3] | |
Electricity | 3 | (18) | [3] | |
Natural Gas | (1) | 0 | [3] | |
Electricity | (30) | (21) | [3] | |
Natural Gas | 0 | (1) | [3] | |
Netting [Member] | Rabbi Trusts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total assets | 0 | 0 | [3] | |
Fixed-income securities | 0 | 0 | [3] | |
Life insurance contracts | 0 | 0 | [3] | |
Netting [Member] | Long-Term Disability Trust [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term investments | 0 | 0 | [3] | |
Total assets | 0 | 0 | [3] | |
Financial Instruments Measured At NAV | $ 0 | $ 0 | [3] | |
[1] | Represents amount before deducting $390 million, primarily related to deferred taxes on appreciation of investment value. | |||
[2] | Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value. | |||
[3] | Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral. |
Fair Value Measurements (Level
Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2017USD ($) | Dec. 31, 2016USD ($) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | $ 3,720 | $ 3,575 | |
Liabilities, Fair Value | 110 | 127 | |
Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Assets, Fair Value | 158 | 181 | |
Liabilities, Fair Value | $ 37 | $ 35 | |
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 | $ 73 | $ 91 | |
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] | (11.88) | (11.88) |
Minimum [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 18.81 | 18.07 |
Maximum [Member] | Congestion Revenue Rights [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 10.54 | 6.93 |
Maximum [Member] | Power Purchase Agreements [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Range | [1] | 38.8 | 38.8 |
[1] | Represents price per megawatt-hour |
Fair Value Measurements (Leve44
Fair Value Measurements (Level 3 Reconciliation) (Details) - Fair Value Measurements, Level 3 [Member] - Price Risk Management Instruments [Member] - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||||
Beginning asset (liability) balance | $ 49 | $ 75 | $ 55 | $ 89 | ||
Included in regulatory assets and liabilities or balancing accounts | (1) | [1] | (9) | [1] | (7) | (23) |
Ending asset (liability) balance | $ 48 | $ 66 | $ 48 | $ 66 | ||
[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 | Jun. 30, 2017 | Dec. 31, 2016 |
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 | $ 18,583 | $ 17,790 |
Pacific Gas And Electric Company [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | 16,208 | 15,813 |
P G E Corporation [Member] | Fair Value Measurements, Level 2 [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | 352 | 352 |
P G E Corporation [Member] | Carrying Amount [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt financial instrument | $ 348 | $ 348 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2017 | Dec. 31, 2016 | ||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | [1] | $ 1,797 | $ 1,749 | ||
Total Unrealized Gains | [1] | 1,334 | 1,205 | ||
Total Unrealized Losses | [1] | (8) | (15) | ||
Total Fair Value | [1] | 3,123 | 2,939 | ||
Amount primarily related to deferred taxes on appreciation of investment value | 390 | [2] | 333 | [3] | |
Short-term investments [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 10 | 9 | |||
Total Unrealized Gains | 0 | 0 | |||
Total Unrealized Losses | 0 | 0 | |||
Total Fair Value | 10 | 9 | |||
Other Fixed-Income Securities [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 1,260 | 1,156 | |||
Total Unrealized Gains | 57 | 48 | |||
Total Unrealized Losses | (6) | (12) | |||
Total Fair Value | 1,311 | 1,192 | |||
Global equity securities [Member] | |||||
Schedule of Available-for-sale Securities [Line Items] | |||||
Amortized Cost | 527 | 584 | |||
Total Unrealized Gains | 1,277 | 1,157 | |||
Total Unrealized Losses | (2) | (3) | |||
Total Fair Value | $ 1,802 | $ 1,738 | |||
[1] | Represents amounts before deducting $390 million and $333 million at June 30, 2017 and December 31, 2016, respectively, primarily related to deferred taxes on appreciation of investment value. | ||||
[2] | Represents amount before deducting $390 million, primarily related to deferred taxes on appreciation of investment value. | ||||
[3] | Represents amount before deducting $333 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 | Jun. 30, 2017USD ($) |
Less than 1 year | $ 6 |
1-5 years | 452 |
5-10 years | 308 |
More than 10 years | 545 |
Total maturities of fixed-income securities | $ 1,311 |
Fair Value Measurements (Sche48
Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Proceeds from sales and maturities of nuclear decommissioning trust investments | $ 324 | $ 282 | $ 794 | $ 721 |
Gross realized gains on sales of securities held as available-for-sale | 13 | 4 | 42 | 9 |
Gross realized losses on sales of securities held as available-for-sale | $ 3 | $ 1 | $ 8 | $ 3 |
Commitments And Contingencies49
Commitments And Contingencies (Third-Party Power Purchases) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Long-term Purchase Commitment [Line Items] | |
Total | $ 47,000 |
Commitments And Contingencies50
Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Loss Contingencies [Line Items] | ||||||
Unrecognized Tax Benefits | $ 70,000 | $ 70,000 | ||||
Disputed Claims Liability Balance | $ 236,000 | |||||
Charge for disallowed capital | $ 47,000 | $ 425,000 | ||||
Butte Fire [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Number of plaintiffs | 2,050 | 2,050 | ||||
Utility liability insurance for damages | $ 900,000 | |||||
Number of Damaged Structures | 44 | 44 | ||||
Loss Contingency Range Of Possible Loss Minimum | $ 750,000 | $ 750,000 | ||||
Number of complaints filed against utility | 60 | 60 | ||||
Fire Fighting Costs Recovery Requested By Cal Fire | $ 87,000 | |||||
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 | 1,180 | 1,180 | ||||
Number Of Master Complaints | 2 | 2 | ||||
Cumulative Legal Expenses | $ 17,000 | $ 27,000 | ||||
Insurance Settlements Receivable | $ 32,000 | $ 32,000 | ||||
Vegetation Management Contractors | 2 | 2 | ||||
Number Of Preference Households | 6 | 6 | ||||
Citation For Failing To Maintain Electric Line | $ 8,300 | |||||
Office Of Emergency Services Claim | $ 190,000 | |||||
Number of Citations | 2 | |||||
Probable Insurance Recoveries | $ 646,000 | |||||
Settlement Agreements Entered By Utility | 380,000 | |||||
Settlement Agreement Paid By The Utility | 176,000 | |||||
Claim Against The Utility | 85,000 | |||||
Potential Safety Citations [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
SED Maximum Statutory Penalty Per Violaiton | 50 | |||||
SED Administrative Limit Per Citation | 8,000 | |||||
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 | |||||
Ex Parte Communications [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Payment To State General Fund | 1,000 | |||||
Payment To City Of San Bruno | 6,000 | |||||
Payment To City Of San Carlos | 6,000 | |||||
Revenue Requirement Reduction In Next GRC Cycle | 10,000 | |||||
2018 GT&S Revenue Requirement Reduction | 31,750 | |||||
2019 GT&S Revenue Requirement Reduction | 31,750 | |||||
Ex parte disallowance in 2015 GT&S rate case recognized in 2016 | 57,000 | |||||
Ex Parte Disallowance In Twenty Fifteen GTandS Recognized In Twenty Seventeen | $ 15,000 | |||||
Ex Parte Communication Count | 12 | 12 | ||||
Shareholder Derivative Lawsuits [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Number Of Consolidated Shareholder Derivative Lawsuits | 4 | 4 | ||||
Number Of Unconsolidated Cases In Derivative Lawsuits | 3 | 3 | ||||
Number Of Days To Make Payment From Decision | 11 days | |||||
Estimated Cost Of Corporate Governance Therapeutics | $ 32,000 | |||||
Maximum Amount Of Fees Paid to Plaintiffs Counsel | 25,000 | |||||
Maximum Amount Of Expenses Paid To Plaintiffs Counsel | 500 | |||||
Payment Of Individual Defendant Costs | 18,300 | |||||
Payment To The Corporation From Liability Insurance Carriers | 90,000 | |||||
Gain Contingency Unrecorded Amount | $ 65,000 | $ 65,000 | ||||
Number Of Years Of Corporate Governance Therapeutics | 5 years | |||||
Number Of Years Of Gas Operations Therapeutics | 3 years | |||||
Loss Accrual [Member] | Butte Fire [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Accrued Losses | 0 | 750,000 | ||||
Loss Contingency Accrual At Carrying Value | $ 574,000 | 574,000 | 690,000 | $ 0 | ||
Payments For Claims | 116,000 | 60,000 | [1] | |||
Insurance Receivable [Member] | Butte Fire [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Insurance Reimbursement From Contractors | 75,000 | 50,000 | ||||
Insurance Settlements Receivable | 521,000 | 521,000 | 575,000 | $ 0 | ||
Accrued Insurance Recoveries | $ 21,000 | 21,000 | 625,000 | |||
Cumulative Legal Expenses [Member] | Butte Fire [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Cumulative Legal Expenses | $ 54,000 | |||||
Disallowance Of Plant Costs [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Percentage of Recoverable Costs Prior To Specific Date | 100.00% | 100.00% | ||||
Percentage of Recoverable Costs After Specific Date | 25.00% | 25.00% | ||||
Settlement Agreement Length | 8 years | |||||
License Renewal Project Cost | $ 53,000 | |||||
Recoverable Costs From Customers | 18,600 | |||||
Cancelled Capital Project Costs | 24,000 | |||||
Disallowed License Renewal Costs | 23,000 | |||||
Pacific Gas And Electric Company [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Charge for disallowed capital | 47,000 | $ 425,000 | ||||
Utility [Member] | ||||||
Loss Contingencies [Line Items] | ||||||
Accrued legal liabilities | $ 43,000 | $ 43,000 | $ 45,000 | |||
[1] | As of June 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $380 of which $176 million has been paid by the Utility. |
Commitments And Contingencies51
Commitments And Contingencies (Nuclear Insurance) (Details) $ in Millions | 3 Months Ended |
Jun. 30, 2017USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Maximum Aggregate Annual Retrospective Premium Obligation | $ 58 |
EMANI Policy Limit | $ 200 |
Commitments And Contingencies52
Commitments And Contingencies (Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 | |
Topock natural gas compressor station | [1] | $ 313 | $ 299 |
Hinkley natural gas compressor station | [1] | 128 | 135 |
Former manufactured gas plant sites owned by the Utility or third parties | 319 | 285 | |
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites | 131 | 131 | |
Fossil fuel-fired generation facilities and sites | 124 | 108 | |
Total environmental remediation liability | $ 1,015 | $ 958 | |
[1] | See "Natural Gas Compressor Station Sites" below. |
Commitments And Contingencies53
Commitments And Contingencies (Environmental Remediation Contingencies) (Details) $ in Millions | Jun. 30, 2017USD ($) |
Long-term Purchase Commitment [Line Items] | |
Amount of environmental loss accrual expected to be recovered | $ 718 |
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute | $ 1,000 |