Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 17, 2017 | Jun. 30, 2016 | |
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | PEG | ||
Entity Registrant Name | PUBLIC SERVICE ENTERPRISE GROUP INC | ||
Entity Central Index Key | 788,784 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 506,217,300 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 23,504,828,537 | ||
PSE&G [Member] | |||
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | PUBLIC SERVICE ELECTRIC & GAS CO | ||
Entity Central Index Key | 81,033 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 132,450,344 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Power [Member] | |||
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | PSEG POWER LLC | ||
Entity Central Index Key | 1,158,659 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Revenues | $ 9,061 | $ 10,415 | $ 10,886 |
Operating Expenses [Abstract] | |||
Energy Costs | 3,001 | 3,261 | 3,886 |
Operation and Maintenance | 3,008 | 2,978 | 3,150 |
Depreciation and Amortization | 1,476 | 1,214 | 1,227 |
Total Operating Expenses | 7,485 | 7,453 | 8,263 |
OPERATING INCOME | 1,576 | 2,962 | 2,623 |
Income from Equity Method Investments | 11 | 12 | 13 |
Other Income | 191 | 254 | 290 |
Other Deductions | (67) | (102) | (61) |
Other-than-Temporary-Impairments | 28 | 53 | 20 |
Interest Expense | (385) | (393) | (389) |
INCOME BEFORE INCOME TAXES | 1,298 | 2,680 | 2,456 |
Income Tax (Expense) Benefit | (411) | (1,001) | (938) |
Net Income | $ 887 | $ 1,679 | $ 1,518 |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | |||
BASIC | 505 | 505 | 506 |
DILUTED | 508 | 508 | 508 |
EARNINGS PER SHARE: | |||
NET INCOME, BASIC | $ 1.76 | $ 3.32 | $ 3 |
NET INCOME, DILUTED | $ 1.75 | $ 3.30 | $ 2.99 |
PSE&G [Member] | |||
Operating Revenues | $ 6,221 | $ 6,636 | $ 6,766 |
Operating Expenses [Abstract] | |||
Energy Costs | 2,567 | 2,722 | 2,909 |
Operation and Maintenance | 1,475 | 1,560 | 1,558 |
Depreciation and Amortization | 565 | 892 | 906 |
Total Operating Expenses | 4,607 | 5,174 | 5,373 |
OPERATING INCOME | 1,614 | 1,462 | 1,393 |
Other Income | 83 | 79 | 61 |
Other Deductions | (4) | (4) | (3) |
Interest Expense | (289) | (280) | (277) |
INCOME BEFORE INCOME TAXES | 1,404 | 1,257 | 1,174 |
Income Tax (Expense) Benefit | (515) | (470) | (449) |
Net Income | 889 | 787 | 725 |
Power [Member] | |||
Operating Revenues | 4,023 | 4,928 | 5,434 |
Operating Expenses [Abstract] | |||
Energy Costs | 1,986 | 2,150 | 2,747 |
Operation and Maintenance | 1,143 | 1,057 | 1,186 |
Depreciation and Amortization | 881 | 291 | 292 |
Total Operating Expenses | 4,010 | 3,498 | 4,225 |
OPERATING INCOME | 13 | 1,430 | 1,209 |
Income from Equity Method Investments | 11 | 14 | 14 |
Other Income | 102 | 169 | 222 |
Other Deductions | (57) | (72) | (52) |
Other-than-Temporary-Impairments | 28 | 53 | 20 |
Interest Expense | (84) | (121) | (122) |
INCOME BEFORE INCOME TAXES | (43) | 1,367 | 1,251 |
Income Tax (Expense) Benefit | 61 | (511) | (491) |
Net Income | $ 18 | $ 856 | $ 760 |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net Income | $ 887 | $ 1,679 | $ 1,518 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | 42 | (27) | (27) |
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit for the years ended | 2 | (10) | 12 |
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended | (12) | 25 | (173) |
Other Comprehensive Income (Loss), net of tax | 32 | (12) | (188) |
Comprehensive Income | 919 | 1,667 | 1,330 |
PSE&G [Member] | |||
Net Income | 889 | 787 | 725 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | 0 | (1) | 1 |
Other Comprehensive Income (Loss), net of tax | 0 | (1) | 1 |
Comprehensive Income | 889 | 786 | 726 |
Power [Member] | |||
Net Income | 18 | 856 | 760 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | 42 | (25) | (30) |
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit for the years ended | 0 | (11) | 12 |
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended | (13) | 24 | (147) |
Other Comprehensive Income (Loss), net of tax | 29 | (12) | (165) |
Comprehensive Income | $ 47 | $ 844 | $ 595 |
Consolidated Statements Of Com4
Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Available-for-Sale Securities, tax | $ (41) | $ 34 | $ 26 |
Change in Fair Value of Derivative Instruments, tax | (1) | 7 | (8) |
Pension/OPEB adjustment, tax | 8 | (18) | 120 |
PSE&G [Member] | |||
Available-for-Sale Securities, tax | 0 | 0 | 0 |
Power [Member] | |||
Available-for-Sale Securities, tax | (41) | 32 | 28 |
Change in Fair Value of Derivative Instruments, tax | 0 | 7 | (8) |
Pension/OPEB adjustment, tax | $ 9 | $ (16) | $ 101 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
CURRENT ASSETS | |||
Cash and Cash Equivalents | $ 423 | $ 394 | |
Accounts Receivable, net of allowances | 1,161 | 1,068 | |
Tax Receivable | 78 | 305 | |
Unbilled Revenues | 260 | 197 | |
Fuel | 326 | 463 | |
Materials and Supplies, net | 561 | 513 | |
Prepayments | 76 | 135 | |
Derivative Contracts | 163 | 242 | |
Regulatory Assets | 199 | 164 | |
Other | 7 | 13 | |
Total Current Assets | 3,254 | 3,494 | |
PROPERTY, PLANT AND EQUIPMENT | 39,337 | 35,494 | |
Less: Accumulated Depreciation and Amortization | (10,051) | (8,955) | |
Net Property, Plant and Equipment | 29,286 | 26,539 | |
NONCURRENT ASSETS | |||
Regulatory Assets | 3,319 | 3,196 | |
Long-Term Investments | 1,050 | 1,233 | |
Nuclear Decommissioning Trust (NDT) Fund | 1,859 | 1,754 | |
Long-Term Tax Receivable | 104 | 171 | |
Long-Term Receivable of VIEs | 589 | 495 | |
Other Special Funds | 217 | 227 | |
Goodwill | 16 | 16 | |
Other Intangibles | 98 | 102 | |
Derivative Contracts | 24 | 77 | |
Other | 254 | 231 | |
Total Noncurrent Assets | 7,530 | 7,502 | |
Total Assets | 40,070 | 37,535 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 500 | 734 | |
Commercial Paper and Loans | 388 | 364 | |
Accounts Payable | 1,459 | 1,369 | |
Derivative Contracts | 13 | 76 | |
Accrued Interest | 97 | 96 | |
Accrued Taxes | 31 | 42 | |
Clean Energy Program | 142 | 142 | |
Obligation to Return Cash Collateral | 132 | 128 | |
Regulatory Liabilities | 88 | 123 | |
Regulatory Liabilities of Consolidated VIEs | 0 | 42 | |
Other | 426 | 459 | |
Total Current Liabilities | 3,276 | 3,575 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 8,658 | 8,166 | |
Regulatory Liabilities | 118 | 175 | |
Asset Retirement Obligations | 726 | 679 | |
Other Postretirement Benefit (OPEB) Costs | 1,324 | 1,228 | |
OPEB Costs of Servco | 452 | 375 | |
Accrued Pension Costs | 568 | 487 | |
Accrued Pension Costs of Servco | 128 | 114 | |
Environmental Costs | 401 | 415 | |
Derivative Contracts | 3 | 27 | |
Long-Term Accrued Taxes | 180 | 212 | |
Other | 211 | 181 | |
Total Noncurrent Liabilities | 12,769 | 12,059 | |
COMMITMENTS AND CONTINGENT LIABILITIES | |||
LONG-TERM DEBT | |||
Total Long-Term Debt | 10,895 | 8,834 | |
STOCKHOLDER'S EQUITY | |||
Common Stock | 4,936 | 4,915 | |
Treasury Stock, at cost | (717) | (671) | |
Retained Earnings | 9,174 | 9,117 | |
Accumulated Other Comprehensive Income (Loss) | (263) | (295) | |
Total Common Stockholders' Equity | 13,130 | 13,066 | |
Noncontrolling Interest | 0 | 1 | |
Total Stockholder's Equity | 13,130 | 13,067 | |
Total Capitalization | 24,025 | 21,901 | |
TOTAL LIABILITIES AND CAPITALIZATION | 40,070 | 37,535 | |
PSE&G [Member] | |||
CURRENT ASSETS | |||
Cash and Cash Equivalents | 390 | 198 | |
Accounts Receivable, net of allowances | 810 | 787 | |
Accounts Receivable-Affiliated Companies | 76 | 222 | |
Unbilled Revenues | 260 | 197 | |
Materials and Supplies, net | 180 | 148 | |
Prepayments | 9 | 31 | |
Derivative Contracts | 0 | 13 | |
Regulatory Assets | 199 | 164 | |
Other | 6 | 9 | |
Total Current Assets | 1,930 | 1,769 | |
PROPERTY, PLANT AND EQUIPMENT | 26,347 | 23,732 | |
Less: Accumulated Depreciation and Amortization | (5,760) | (5,504) | |
Net Property, Plant and Equipment | 20,587 | 18,228 | |
NONCURRENT ASSETS | |||
Regulatory Assets | 3,319 | 3,196 | |
Long-Term Investments | 299 | 330 | |
Other Special Funds | 43 | 49 | |
Other | 110 | 105 | |
Total Noncurrent Assets | 3,771 | 3,680 | |
Total Assets | 26,288 | 23,677 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 0 | 171 | |
Commercial Paper and Loans | 0 | 153 | |
Accounts Payable | 718 | 724 | |
Derivative Contracts | 5 | 0 | |
Accounts Payable-Affiliated Companies | 260 | 292 | |
Accrued Interest | 76 | 70 | |
Clean Energy Program | 142 | 142 | |
Obligation to Return Cash Collateral | 132 | 128 | |
Regulatory Liabilities | 88 | 123 | |
Regulatory Liabilities of Consolidated VIEs | 0 | 42 | |
Other | 296 | 297 | |
Total Current Liabilities | 1,717 | 2,142 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 5,873 | 5,181 | |
Regulatory Liabilities | 118 | 175 | |
Regulatory Liabilities of VIEs | 0 | ||
Asset Retirement Obligations | 213 | 218 | |
Other Postretirement Benefit (OPEB) Costs | 1,009 | 937 | |
Accrued Pension Costs | 250 | 202 | |
Environmental Costs | 332 | 365 | |
Derivative Contracts | 0 | 11 | |
Long-Term Accrued Taxes | 130 | 109 | |
Other | 116 | 114 | |
Total Noncurrent Liabilities | 8,041 | 7,312 | |
COMMITMENTS AND CONTINGENT LIABILITIES | |||
LONG-TERM DEBT | |||
Total Long-Term Debt | 7,818 | 6,650 | |
STOCKHOLDER'S EQUITY | |||
Common Stock | 892 | 892 | |
Contributed Capital | 945 | 695 | |
Basis Adjustment | 986 | 986 | |
Retained Earnings | 5,888 | 4,999 | |
Accumulated Other Comprehensive Income (Loss) | 1 | 1 | |
Total Stockholder's Equity | 8,712 | 7,573 | |
Total Capitalization | 16,530 | 14,223 | |
TOTAL LIABILITIES AND CAPITALIZATION | 26,288 | 23,677 | |
Power [Member] | |||
CURRENT ASSETS | |||
Cash and Cash Equivalents | 11 | 12 | |
Accounts Receivable, net of allowances | 276 | 217 | |
Accounts Receivable-Affiliated Companies | 205 | 276 | |
Short-Term Loan to Affiliate | 87 | 363 | |
Fuel | 326 | 463 | |
Materials and Supplies, net | 381 | 363 | |
Prepayments | 10 | 25 | |
Derivative Contracts | 162 | 223 | [1] |
Other | 2 | 7 | |
Total Current Assets | 1,460 | 1,949 | |
PROPERTY, PLANT AND EQUIPMENT | 12,655 | 11,354 | |
Less: Accumulated Depreciation and Amortization | (4,135) | (3,227) | |
Net Property, Plant and Equipment | 8,520 | 8,127 | |
NONCURRENT ASSETS | |||
Long-Term Investments | 102 | 119 | |
Nuclear Decommissioning Trust (NDT) Fund | 1,859 | 1,754 | |
Other Special Funds | 53 | 55 | |
Goodwill | 16 | 16 | |
Other Intangibles | 98 | 102 | |
Derivative Contracts | 24 | 77 | [1] |
Other | 61 | 51 | |
Total Noncurrent Assets | 2,213 | 2,174 | |
Total Assets | 12,193 | 12,250 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 0 | 553 | |
Accounts Payable | 539 | 432 | |
Derivative Contracts | 8 | 76 | [1] |
Accounts Payable-Affiliated Companies | 25 | 33 | |
Accrued Interest | 20 | 25 | |
Other | 88 | 107 | |
Total Current Liabilities | 680 | 1,226 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 2,170 | 2,347 | |
Asset Retirement Obligations | 511 | 457 | |
Other Postretirement Benefit (OPEB) Costs | 251 | 230 | |
Accrued Pension Costs | 191 | 166 | |
Derivative Contracts | 3 | 16 | [1] |
Long-Term Accrued Taxes | 77 | 35 | |
Other | 129 | 87 | |
Total Noncurrent Liabilities | 3,332 | 3,338 | |
COMMITMENTS AND CONTINGENT LIABILITIES | |||
LONG-TERM DEBT | |||
Total Long-Term Debt | 2,382 | 1,684 | |
STOCKHOLDER'S EQUITY | |||
Contributed Capital | 2,214 | 2,214 | |
Basis Adjustment | (986) | (986) | |
Retained Earnings | 4,782 | 5,014 | |
Accumulated Other Comprehensive Income (Loss) | (211) | (240) | |
Total Stockholder's Equity | 5,799 | 6,002 | |
TOTAL LIABILITIES AND CAPITALIZATION | $ 12,193 | $ 12,250 | |
[1] | Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements. |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Accounts Receivable,allowances | $ 68 | $ 67 |
Common Stock, issued | 533,556,660 | 533,556,660 |
Common Stock, authorized | 1,000,000,000 | 1,000,000,000 |
Treasury Stock, Shares | 28,690,488 | 28,274,239 |
PSE&G [Member] | ||
Accounts Receivable,allowances | $ 68 | $ 67 |
Common Stock, issued | 132,450,344 | 132,450,344 |
Common Stock, authorized | 150,000,000 | 150,000,000 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | $ 887 | $ 1,679 | $ 1,518 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 1,476 | 1,214 | 1,227 |
Amortization of Nuclear Fuel | 203 | 213 | 200 |
Renewable Energy Credit Compliance Accrual | 109 | 104 | 69 |
Impairment Costs for Early Plant Retirements | 102 | 0 | 0 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | 474 | 685 | 515 |
Non-Cash Employee Benefit Plan Costs | 127 | 161 | 47 |
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes | (6) | 26 | (4) |
Net (Gain) Loss on Lease Investments | 92 | 0 | (3) |
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | 183 | (143) | (93) |
Net Change in Regulatory Assets and Liabilities | (138) | (48) | 187 |
Cost of Removal | (131) | (120) | (98) |
Net Realized (Gains) Losses and (Income) Expense from NDT Fund | (26) | (38) | (166) |
Net Change in Certain Current Assets and Liabilities: | |||
Margin Deposits | (76) | 122 | (22) |
Tax Receivable | 303 | (94) | 30 |
Accrued Taxes | 3 | (91) | (156) |
Other Current Assets and Liabilities | (180) | 288 | (31) |
Employee Benefit Plan Funding and Related Payments | (103) | (109) | (95) |
Other | 12 | 70 | 35 |
Net Cash Provided By (Used In) Operating Activities | 3,311 | 3,919 | 3,160 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (4,199) | (3,863) | (2,820) |
Purchase of Emissions Allowances and RECs | (99) | (106) | (101) |
Proceeds from Sale of Capital Leases and Investments | 0 | 14 | 25 |
Proceeds from Sale of Available-for-Sale Securities | 824 | 1,501 | 1,915 |
Investments in Available-for-Sale Securities | (856) | (1,552) | (1,934) |
Other | 82 | 64 | 23 |
Net Cash Provided By (Used In) Investing Activities | (4,248) | (3,942) | (2,892) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net Change in Commercial Paper and Loans | 24 | 364 | (60) |
Issuance of Long-Term Debt | 2,675 | 1,350 | 1,250 |
Redemption of Long-Term Debt | (824) | (600) | (500) |
Redemption of Securitization Debt | 0 | (259) | (237) |
Cash Dividend Paid | (830) | (789) | (748) |
Other | (79) | (51) | (64) |
Net Cash Provided By (Used In) Financing Activities | 966 | 15 | (359) |
Net Increase (Decrease) In Cash and Cash Equivalents | 29 | (8) | (91) |
Cash and Cash Equivalents at Beginning of Period | 394 | 402 | 493 |
Cash and Cash Equivalents at End of Period | 423 | 394 | 402 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | (245) | 447 | 538 |
Interest Paid, Net of Amounts Capitalized | 365 | 381 | 382 |
Accrued Property, Plant and Equipment Expenditures | 664 | 510 | 382 |
PSE&G [Member] | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | 889 | 787 | 725 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 565 | 892 | 906 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | 658 | 386 | 310 |
Non-Cash Employee Benefit Plan Costs | 72 | 95 | 27 |
Net Change in Regulatory Assets and Liabilities | (138) | (48) | 187 |
Cost of Removal | (131) | (120) | (98) |
Net Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable and Unbilled Revenues | (84) | 165 | 63 |
Fuel, Materials and Supplies | (7) | (15) | (18) |
Prepayments | 22 | 11 | (18) |
Accounts Payable | (29) | 45 | (3) |
Accounts Receivable/Payable-Affiliated Companies, net | 199 | 0 | (167) |
Other Current Assets and Liabilities | 8 | (29) | 6 |
Employee Benefit Plan Funding and Related Payments | (82) | (91) | (83) |
Other | (48) | 47 | (4) |
Net Cash Provided By (Used In) Operating Activities | 1,894 | 2,125 | 1,833 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (2,816) | (2,692) | (2,164) |
Proceeds from Sale of Available-for-Sale Securities | 22 | 21 | 103 |
Investments in Available-for-Sale Securities | (24) | (22) | (101) |
Solar Loan Investments | 14 | 11 | 7 |
Other | 15 | 11 | 0 |
Net Cash Provided By (Used In) Investing Activities | (2,789) | (2,671) | (2,155) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net Change in Short-Term Debt | (153) | 153 | (60) |
Issuance of Long-Term Debt | 1,275 | 850 | 1,250 |
Redemption of Long-Term Debt | (271) | (300) | (500) |
Contributed Capital | 250 | 0 | 175 |
Redemption of Securitization Debt | 0 | (259) | (237) |
Other | (14) | (10) | (14) |
Net Cash Provided By (Used In) Financing Activities | 1,087 | 434 | 614 |
Net Increase (Decrease) In Cash and Cash Equivalents | 192 | (112) | 292 |
Cash and Cash Equivalents at Beginning of Period | 198 | 310 | 18 |
Cash and Cash Equivalents at End of Period | 390 | 198 | 310 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | (295) | (28) | 283 |
Interest Paid, Net of Amounts Capitalized | 273 | 261 | 259 |
Accrued Property, Plant and Equipment Expenditures | 420 | 396 | 292 |
Power [Member] | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | 18 | 856 | 760 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 881 | 291 | 292 |
Amortization of Nuclear Fuel | 203 | 213 | 200 |
Renewable Energy Credit Compliance Accrual | 109 | 104 | 69 |
Impairment Costs for Early Plant Retirements | 102 | 0 | 0 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | (208) | 261 | 221 |
Interest Accretion on Asset Retirement Obligation | 26 | 26 | 30 |
Non-Cash Employee Benefit Plan Costs | 39 | 48 | 13 |
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | 183 | (143) | (93) |
Net Realized (Gains) Losses and (Income) Expense from NDT Fund | (26) | (38) | (166) |
Net Change in Certain Current Assets and Liabilities: | |||
Fuel, Materials and Supplies | 31 | 62 | 19 |
Margin Deposits | (76) | 122 | (22) |
Accounts Receivable | (71) | 63 | (15) |
Accounts Payable | (22) | (46) | (59) |
Accounts Receivable/Payable-Affiliated Companies, net | 6 | (84) | 220 |
Other Current Assets and Liabilities | 10 | (36) | (6) |
Employee Benefit Plan Funding and Related Payments | (13) | (11) | (7) |
Other | 63 | 18 | (31) |
Net Cash Provided By (Used In) Operating Activities | 1,255 | 1,706 | 1,425 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (1,343) | (1,117) | (626) |
Purchase of Emissions Allowances and RECs | (99) | (106) | (101) |
Proceeds from Sale of Available-for-Sale Securities | 739 | 1,422 | 1,557 |
Investments in Available-for-Sale Securities | (766) | (1,455) | (1,573) |
Short-Term Loan-Affiliated Company, net | 276 | 221 | 206 |
Other | 46 | 34 | 13 |
Net Cash Provided By (Used In) Investing Activities | (1,147) | (1,001) | (524) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Issuance of Long-Term Debt | 700 | 0 | 0 |
Redemption of Long-Term Debt | (553) | (300) | 0 |
Cash Dividend Paid | (250) | (400) | (895) |
Other | (6) | (2) | (3) |
Net Cash Provided By (Used In) Financing Activities | (109) | (702) | (898) |
Net Increase (Decrease) In Cash and Cash Equivalents | (1) | 3 | 3 |
Cash and Cash Equivalents at Beginning of Period | 12 | 9 | 6 |
Cash and Cash Equivalents at End of Period | 11 | 12 | 9 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | 50 | 393 | 68 |
Interest Paid, Net of Amounts Capitalized | 81 | 116 | 119 |
Accrued Property, Plant and Equipment Expenditures | $ 244 | $ 114 | $ 91 |
Consolidated Statements Of Stoc
Consolidated Statements Of Stockholders' Equity - USD ($) shares in Millions, $ in Millions | Total | Common Stock [Member] | Treasury Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Noncontrolling Interest [Member] | PSE&G [Member] | PSE&G [Member]Common Stock [Member] | PSE&G [Member]Contributed Capital [Member] | PSE&G [Member]Basis Adjustment [Member] | PSE&G [Member]Retained Earnings [Member] | PSE&G [Member]Accumulated Other Comprehensive Income (Loss) [Member] | Power [Member] | Power [Member]Contributed Capital [Member] | Power [Member]Basis Adjustment [Member] | Power [Member]Retained Earnings [Member] | Power [Member]Accumulated Other Comprehensive Income (Loss) [Member] |
Beginning Balance (in value) at Dec. 31, 2013 | $ 11,609 | $ 4,861 | $ (615) | $ 7,457 | $ (95) | $ 1 | $ 5,886 | $ 892 | $ 520 | $ 986 | $ 3,487 | $ 1 | $ 5,858 | $ 2,214 | $ (986) | $ 4,693 | $ (63) |
Beginning Balance, shares at Dec. 31, 2013 | 534 | (28) | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net Income | 1,518 | 1,518 | 725 | 725 | 760 | 760 | |||||||||||
Other Comprehensive Income (Loss), net of tax | |||||||||||||||||
Other Comprehensive Income (Loss), net of tax | (188) | (188) | 0 | 1 | 1 | (165) | (165) | ||||||||||
Comprehensive Income | 1,330 | 726 | 595 | ||||||||||||||
Contributed Capital | 175 | 175 | |||||||||||||||
Cash Dividends on Common Stock | (748) | (748) | 0 | 0 | (895) | (895) | |||||||||||
Other | (5) | $ 15 | $ (20) | 0 | 0 | 0 | |||||||||||
Ending Balance (in value) at Dec. 31, 2014 | 12,186 | $ 4,876 | $ (635) | 8,227 | (283) | 1 | 6,787 | 892 | 695 | 986 | 4,212 | 2 | 5,558 | 2,214 | (986) | 4,558 | (228) |
Ending Balance, shares at Dec. 31, 2014 | 534 | (28) | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net Income | 1,679 | 1,679 | 787 | 787 | 856 | 856 | |||||||||||
Other Comprehensive Income (Loss), net of tax | |||||||||||||||||
Other Comprehensive Income (Loss), net of tax | (12) | (12) | (1) | (1) | (12) | (12) | |||||||||||
Comprehensive Income | 1,667 | 786 | 844 | ||||||||||||||
Contributed Capital | 0 | ||||||||||||||||
Cash Dividends on Common Stock | (789) | (789) | (400) | (400) | |||||||||||||
Other | 3 | $ 39 | $ (36) | ||||||||||||||
Ending Balance (in value) at Dec. 31, 2015 | 13,067 | $ 4,915 | $ (671) | 9,117 | (295) | 1 | 7,573 | 892 | 695 | 986 | 4,999 | 1 | 6,002 | 2,214 | (986) | 5,014 | (240) |
Ending Balance, shares at Dec. 31, 2015 | 534 | (28) | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net Income | 887 | 887 | 889 | 889 | 18 | 18 | |||||||||||
Other Comprehensive Income (Loss), net of tax | |||||||||||||||||
Other Comprehensive Income (Loss), net of tax | 32 | 32 | 0 | 0 | 29 | 29 | |||||||||||
Comprehensive Income | 919 | 889 | 47 | ||||||||||||||
Contributed Capital | 250 | 250 | |||||||||||||||
Cash Dividends on Common Stock | (830) | (830) | (250) | (250) | |||||||||||||
Other | (26) | $ 21 | $ (46) | (1) | |||||||||||||
Treasury Stock, Shares, Acquired | (1) | ||||||||||||||||
Ending Balance (in value) at Dec. 31, 2016 | $ 13,130 | $ 4,936 | $ (717) | $ 9,174 | $ (263) | $ 0 | $ 8,712 | $ 892 | $ 945 | $ 986 | $ 5,888 | $ 1 | $ 5,799 | $ 2,214 | $ (986) | $ 4,782 | $ (211) |
Ending Balance, shares at Dec. 31, 2016 | 534 | (29) |
Consolidated Statements Of Sto9
Consolidated Statements Of Stockholders' Equity (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Other Comprehensive Income (Loss), tax | $ (34) | $ 23 | $ 138 |
PSE&G [Member] | |||
Other Comprehensive Income (Loss), tax | 0 | 0 | 0 |
Power [Member] | |||
Other Comprehensive Income (Loss), tax | $ (32) | $ 23 | $ 121 |
Organization, Basis Of Presenta
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies | Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (Power) —which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate. PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entities . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities . Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entities for further information. Depreciation and Amortization PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2016 2015 2014 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.45 % 2.46 % 2.47 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 70 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2016 , 2015 and 2014 were as follows: AFUDC/IDC Capitalized 2016 2015 2014 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 66 7.81 % $ 65 8.01 % $ 44 8.09 % Power $ 54 4.87 % $ 27 5.14 % $ 24 5.14 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion. Impairment of Long-Lived Assets Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Cash and Cash Equivalents Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Available-for-Sale Securities These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 12. Pension and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. |
PSE&G [Member] | |
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies | Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (Power) —which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate. PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entities . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities . Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entities for further information. Depreciation and Amortization PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2016 2015 2014 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.45 % 2.46 % 2.47 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 70 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2016 , 2015 and 2014 were as follows: AFUDC/IDC Capitalized 2016 2015 2014 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 66 7.81 % $ 65 8.01 % $ 44 8.09 % Power $ 54 4.87 % $ 27 5.14 % $ 24 5.14 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion. Impairment of Long-Lived Assets Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Cash and Cash Equivalents Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Available-for-Sale Securities These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 12. Pension and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. |
Power [Member] | |
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies | Organization, Basis of Presentation and Summary of Significant Accounting Policies Public Service Enterprise Group Incorporated (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid-Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are: • Public Service Electric and Gas Company (PSE&G) —which is a public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs in New Jersey, which are regulated by the BPU. • PSEG Power LLC (Power) —which is a multi-regional energy supply company that integrates the operations of its merchant nuclear and fossil generating assets with its power marketing businesses through competitive energy sales in well-developed energy markets and fuel supply functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. In addition, Power owns and operates solar generation in various states. Power’s subsidiaries are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA) and the states in which they operate. PSEG’s other direct wholly owned subsidiaries include PSEG Energy Holdings L.L.C. (Energy Holdings), which primarily has investments in leveraged leases; PSEG Long Island LLC (PSEG LI), which operates the Long Island Power Authority’s (LIPA) transmission and distribution (T&D) system under an Operations Services Agreement (OSA); and PSEG Services Corporation (Services), which provides certain management, administrative and general services to PSEG and its subsidiaries at cost. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). Significant Accounting Policies Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entities . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities . Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities . Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entities for further information. Depreciation and Amortization PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2016 2015 2014 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.45 % 2.46 % 2.47 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 70 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2016 , 2015 and 2014 were as follows: AFUDC/IDC Capitalized 2016 2015 2014 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 66 7.81 % $ 65 8.01 % $ 44 8.09 % Power $ 54 4.87 % $ 27 5.14 % $ 24 5.14 % Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion. Impairment of Long-Lived Assets Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). Cash and Cash Equivalents Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. Available-for-Sale Securities These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion. Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 12. Pension and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion. Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. |
Recent Accounting Standards
Recent Accounting Standards | 12 Months Ended |
Dec. 31, 2016 | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Issued and Adopted Stock Compensation-Improvements to Employee Share-Based Payment Accounting This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Statement of Cash Flows. Under the new guidance, all excess tax benefits and tax deficiencies related to employee share-based payments will be recognized in income tax expense rather than recognized in additional paid in capital. In the Statement of Cash Flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG adopted this standard in the fourth quarter of 2016. The impact to the financial statements was immaterial. Disclosure for Investments in Certain Entities that Calculate Net Asset Value (NAV) per Share This accounting standard eliminates the requirement to categorize, in the fair value hierarchy, investments whose fair values are measured at NAV using the practical expedient provided in the fair value guidance. The practical expedient applies to investments in mutual funds or structures similar to a mutual fund for which there is not a readily determinable fair value. Although not required in the fair value hierarchy, sufficient information must be provided to allow for reconciliation between the fair value of assets categorized in the hierarchy and the balance sheet. The standard is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. PSEG adopted this standard in the fourth quarter 2016 on a retrospective basis and has reflected the effect of the new disclosure requirements in Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plan. Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This accounting standard requires management to assess an entity’s ability to continue as a going concern and provide related disclosures in certain circumstances. These disclosures are only required when conditions give rise to substantial doubt about an entity’s ability to continue as a going concern within one year from the financial statement issuance date. The standard is effective for annual and interim periods beginning after December 15, 2016. PSEG adopted this standard in the fourth quarter of 2016; however, no disclosures were required this period based on the above criteria. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures. The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possibly changes in presentation. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues continue to be debated and are currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. As the ultimate impact of the new standard has not yet been determined, PSEG has not elected its transition method. Recognition and Measurement of Financial Assets and Financial Liabilities This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the NDT and Rabbi Trust Funds. Leases This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change. The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Measurement of Credit Losses on Financial Instruments This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination. The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Restricted Cash This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in its reconciliation of beginning of period and end-of-period amounts in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG will include those amounts that are deemed to be restricted cash and restricted cash equivalents in its cash and cash equivalents balances in the statement of cash flows as well as disclosure regarding the nature of restricted amounts. Business Combinations: Clarifying the Definition of a Business This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes a filter that would consider whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG is currently evaluating the impact of this standard on its financial statements; however, PSEG does not expect this guidance to materially impact its financial statements upon adoption. Simplifying the Test for Goodwill Impairment This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements. |
PSE&G [Member] | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Issued and Adopted Stock Compensation-Improvements to Employee Share-Based Payment Accounting This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Statement of Cash Flows. Under the new guidance, all excess tax benefits and tax deficiencies related to employee share-based payments will be recognized in income tax expense rather than recognized in additional paid in capital. In the Statement of Cash Flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG adopted this standard in the fourth quarter of 2016. The impact to the financial statements was immaterial. Disclosure for Investments in Certain Entities that Calculate Net Asset Value (NAV) per Share This accounting standard eliminates the requirement to categorize, in the fair value hierarchy, investments whose fair values are measured at NAV using the practical expedient provided in the fair value guidance. The practical expedient applies to investments in mutual funds or structures similar to a mutual fund for which there is not a readily determinable fair value. Although not required in the fair value hierarchy, sufficient information must be provided to allow for reconciliation between the fair value of assets categorized in the hierarchy and the balance sheet. The standard is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. PSEG adopted this standard in the fourth quarter 2016 on a retrospective basis and has reflected the effect of the new disclosure requirements in Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plan. Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This accounting standard requires management to assess an entity’s ability to continue as a going concern and provide related disclosures in certain circumstances. These disclosures are only required when conditions give rise to substantial doubt about an entity’s ability to continue as a going concern within one year from the financial statement issuance date. The standard is effective for annual and interim periods beginning after December 15, 2016. PSEG adopted this standard in the fourth quarter of 2016; however, no disclosures were required this period based on the above criteria. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures. The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possibly changes in presentation. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues continue to be debated and are currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. As the ultimate impact of the new standard has not yet been determined, PSEG has not elected its transition method. Recognition and Measurement of Financial Assets and Financial Liabilities This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the NDT and Rabbi Trust Funds. Leases This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change. The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Measurement of Credit Losses on Financial Instruments This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination. The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Restricted Cash This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in its reconciliation of beginning of period and end-of-period amounts in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG will include those amounts that are deemed to be restricted cash and restricted cash equivalents in its cash and cash equivalents balances in the statement of cash flows as well as disclosure regarding the nature of restricted amounts. Business Combinations: Clarifying the Definition of a Business This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes a filter that would consider whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG is currently evaluating the impact of this standard on its financial statements; however, PSEG does not expect this guidance to materially impact its financial statements upon adoption. Simplifying the Test for Goodwill Impairment This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements. |
Power [Member] | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Issued and Adopted Stock Compensation-Improvements to Employee Share-Based Payment Accounting This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Statement of Cash Flows. Under the new guidance, all excess tax benefits and tax deficiencies related to employee share-based payments will be recognized in income tax expense rather than recognized in additional paid in capital. In the Statement of Cash Flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG adopted this standard in the fourth quarter of 2016. The impact to the financial statements was immaterial. Disclosure for Investments in Certain Entities that Calculate Net Asset Value (NAV) per Share This accounting standard eliminates the requirement to categorize, in the fair value hierarchy, investments whose fair values are measured at NAV using the practical expedient provided in the fair value guidance. The practical expedient applies to investments in mutual funds or structures similar to a mutual fund for which there is not a readily determinable fair value. Although not required in the fair value hierarchy, sufficient information must be provided to allow for reconciliation between the fair value of assets categorized in the hierarchy and the balance sheet. The standard is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. PSEG adopted this standard in the fourth quarter 2016 on a retrospective basis and has reflected the effect of the new disclosure requirements in Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plan. Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This accounting standard requires management to assess an entity’s ability to continue as a going concern and provide related disclosures in certain circumstances. These disclosures are only required when conditions give rise to substantial doubt about an entity’s ability to continue as a going concern within one year from the financial statement issuance date. The standard is effective for annual and interim periods beginning after December 15, 2016. PSEG adopted this standard in the fourth quarter of 2016; however, no disclosures were required this period based on the above criteria. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures. The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possibly changes in presentation. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues continue to be debated and are currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. As the ultimate impact of the new standard has not yet been determined, PSEG has not elected its transition method. Recognition and Measurement of Financial Assets and Financial Liabilities This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the NDT and Rabbi Trust Funds. Leases This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change. The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Measurement of Credit Losses on Financial Instruments This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination. The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Restricted Cash This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in its reconciliation of beginning of period and end-of-period amounts in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG will include those amounts that are deemed to be restricted cash and restricted cash equivalents in its cash and cash equivalents balances in the statement of cash flows as well as disclosure regarding the nature of restricted amounts. Business Combinations: Clarifying the Definition of a Business This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes a filter that would consider whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG is currently evaluating the impact of this standard on its financial statements; however, PSEG does not expect this guidance to materially impact its financial statements upon adoption. Simplifying the Test for Goodwill Impairment This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements. |
Early Plant Retirements Early P
Early Plant Retirements Early Plant Retirements | 12 Months Ended |
Dec. 31, 2016 | |
Restructuring Cost and Reserve [Line Items] | |
Early Plant Retirements [Text Block] | Early Plant Retirements On October 3, 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise. PSEG and Power undertake their annual five-year strategic planning process primarily during the third and fourth quarters of each year. The primary factors considered during this process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 for the capacity period from June 2020 to May 2021 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance regulations. During the current annual five-year strategic planning process, Power determined, on October 3, 2016, that the costs to upgrade the existing units at the Hudson and Mercer stations to comply with these higher reliability standards to be too significant and not economic given current market conditions, including anticipated future capacity prices, current forward energy prices and past operational performance results of the units. While these units have the capability to run on both coal and natural gas, they have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. The decision to retire the Hudson and Mercer units early had and will continue to have a material effect on PSEG’s and Power’s results of operations. In 2016, PSEG and Power recognized the following pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation expense during the period following the announcement of the early retirement of the plants: Year Ended December 31, 2016 Millions Statement of Operations Expense (pre-tax) Energy Costs Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties $ 62 Operation and Maintenance Materials and Supplies Obsolescence 31 Write-down of Construction Work in Progress 14 Other (A) 8 Depreciation and Amortization Depreciation including Asset Retirement Costs 571 Total Pre-Tax Expense $ 686 (A) Includes severance and miscellaneous costs. Power recorded $7 million of severance expense which it expects to pay in 2017. In addition to these charges, Power expects to recognize the remaining Depreciation and Amortization of $958 million in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material. Because the Hudson and Mercer generating units will cease operations significantly before the end of their previously estimated useful lives, Power performed a recoverability test for its portfolio of generating assets in the PJM region to determine if an impairment exists. As of September 30, 2016, the estimated undiscounted future cash flows of the PJM asset group exceeded the carrying amount and no impairment was identified. For additional information on impairment of long-lived assets, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies . In addition, Power has reduced the estimated useful life of Bridgeport Harbor Station unit 3 from 2025 to the summer of 2021 as it is more likely than not it will retire the unit by this time. The change in the estimated useful life is not expected to have a material impact on Power’s future financial results. PSEG and Power continue to monitor their Keystone and Conemaugh generating stations to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain these assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results. |
Power [Member] | |
Restructuring Cost and Reserve [Line Items] | |
Early Plant Retirements [Text Block] | Early Plant Retirements On October 3, 2016, Power determined that it would cease generation operations of the existing coal/gas units at the Hudson and Mercer generating stations on June 1, 2017. Power has filed deactivation notices with PJM for these existing units at both stations and final must-offer exception requests for the 2020-2021 PJM capacity auction to the PJM Independent Market Monitor. Power expects the units to continue to be available to generate electricity and receive previously cleared capacity payments through the date the units cease operations. The exact timing of the early retirement of these units may be impacted by operational and other conditions that could subsequently arise. PSEG and Power undertake their annual five-year strategic planning process primarily during the third and fourth quarters of each year. The primary factors considered during this process that contributed to the decision to retire these units early include significant declines in revenues and margin caused by a sustained period of depressed wholesale power prices and reduced capacity factors caused by lower natural gas prices making coal generation less economically competitive than natural gas-fired generation. Despite experiencing recent warmer than normal weather in PJM this summer, Power did not experience the usual increase in electricity prices in PJM as it had in past hot summers. This trend has a further adverse economic impact to these units because they generally dispatch and earn energy margin on peak hot and cold days. In addition, the upcoming PJM capacity auction in May 2017 for the capacity period from June 2020 to May 2021 will be the first to require all generating units to meet the increased operating performance standards of PJM’s new capacity performance regulations. During the current annual five-year strategic planning process, Power determined, on October 3, 2016, that the costs to upgrade the existing units at the Hudson and Mercer stations to comply with these higher reliability standards to be too significant and not economic given current market conditions, including anticipated future capacity prices, current forward energy prices and past operational performance results of the units. While these units have the capability to run on both coal and natural gas, they have higher operating costs and fuel consumption as well as longer start-up times compared to newer combined cycle gas units. The decision to retire the Hudson and Mercer units early had and will continue to have a material effect on PSEG’s and Power’s results of operations. In 2016, PSEG and Power recognized the following pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation expense during the period following the announcement of the early retirement of the plants: Year Ended December 31, 2016 Millions Statement of Operations Expense (pre-tax) Energy Costs Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties $ 62 Operation and Maintenance Materials and Supplies Obsolescence 31 Write-down of Construction Work in Progress 14 Other (A) 8 Depreciation and Amortization Depreciation including Asset Retirement Costs 571 Total Pre-Tax Expense $ 686 (A) Includes severance and miscellaneous costs. Power recorded $7 million of severance expense which it expects to pay in 2017. In addition to these charges, Power expects to recognize the remaining Depreciation and Amortization of $958 million in 2017 due to the significant shortening of the expected economic useful lives of Hudson and Mercer. Additional employee-related salary continuance and severance costs and various miscellaneous costs may also be incurred during the period prior to retirement. Finally, Power currently anticipates using the sites for alternative industrial activity. However, if Power determines not to use the sites for alternative industrial activity, the early retirement of the units at such sites would trigger obligations under certain environmental regulations, including possible remediation. The amounts for any such environmental remediation are neither currently probable nor estimable but may be material. Because the Hudson and Mercer generating units will cease operations significantly before the end of their previously estimated useful lives, Power performed a recoverability test for its portfolio of generating assets in the PJM region to determine if an impairment exists. As of September 30, 2016, the estimated undiscounted future cash flows of the PJM asset group exceeded the carrying amount and no impairment was identified. For additional information on impairment of long-lived assets, see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies . In addition, Power has reduced the estimated useful life of Bridgeport Harbor Station unit 3 from 2025 to the summer of 2021 as it is more likely than not it will retire the unit by this time. The change in the estimated useful life is not expected to have a material impact on Power’s future financial results. PSEG and Power continue to monitor their Keystone and Conemaugh generating stations to assess their economic viability through the end of their designated useful lives and their continued classification as held for use. The precise timing of a change in useful lives may be dependent upon events out of PSEG’s and Power’s control and may impact their ability to operate or maintain these assets in the future. These generating stations may be impacted by factors such as environmental legislation, co-owner capital requirements and continued depressed wholesale power prices or capacity factors, among other things. Any early retirement or change in the classification as held for use of our remaining coal units may have a material adverse impact on PSEG’s and Power’s future financial results. |
Variable Interest Entities (VIE
Variable Interest Entities (VIEs) | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entity [Line Items] | |
Variable Interest Entities (VIEs) [Text Block] | Variable Interest Entities (VIEs) VIEs for which PSE&G is the Primary Beneficiary PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. During 2016, Transition Funding and Transition Funding II refunded final over-collected transition charges to ratepayers and as of December 31, 2016 the securitization program was completed. VIE for which PSEG LI is the Primary Beneficiary PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG. Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics. For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2016 , 2015 and 2014, Servco recorded $410 million , $375 million and $389 million , respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations. |
PSE&G [Member] | |
Variable Interest Entity [Line Items] | |
Variable Interest Entities (VIEs) [Text Block] | Variable Interest Entities (VIEs) VIEs for which PSE&G is the Primary Beneficiary PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which was pledged as collateral to a trustee. PSE&G acted as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds were remitted to Transition Funding and Transition Funding II and were used for interest and principal payments on the transition bonds and related costs. During 2015, Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015, no further debt or related costs remained with these VIEs. During 2016, Transition Funding and Transition Funding II refunded final over-collected transition charges to ratepayers and as of December 31, 2016 the securitization program was completed. VIE for which PSEG LI is the Primary Beneficiary PSEG LI consolidates Servco, a marginally capitalized VIE, which was created for the purpose of operating LIPA’s T&D system in Long Island, New York as well as providing administrative support functions to LIPA. PSEG LI is the primary beneficiary of Servco because it directs the operations of Servco, the activity that most significantly impacts Servco’s economic performance and it has the obligation to absorb losses of Servco that could potentially be significant to Servco. Such losses would be immaterial to PSEG. Pursuant to the OSA, Servco’s operating costs are reimbursable entirely by LIPA, and therefore, PSEG LI’s risk is limited related to the activities of Servco. PSEG LI has no current obligation to provide direct financial support to Servco. In addition to reimbursement of Servco’s operating costs as provided for in the OSA, PSEG LI receives an annual contract management fee. PSEG LI’s annual contractual management fee, in certain situations, could be partially offset by Servco’s annual storm costs not approved by the Federal Emergency Management Agency, limited contingent liabilities and penalties for failing to meet certain performance metrics. For transactions in which Servco acts as principal, such as transactions with its employees for labor and labor-related activities, including pension and OPEB-related transactions, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and O&M Expense, respectively. In 2016 , 2015 and 2014, Servco recorded $410 million , $375 million and $389 million , respectively, of O&M costs, the full reimbursement of which was reflected in Operating Revenues. For transactions in which Servco acts as an agent for LIPA, it records revenues and the related expenses on a net basis, resulting in no impact on PSEG’s Consolidated Statement of Operations. |
Property, Plant And Equipment A
Property, Plant And Equipment And Jointly-Owned Facilities | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |
Property Plant And Equipment And Jointly-Owned Facilities | Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2016 and 2015 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2016 Transmission and Distribution: Electric Transmission $ 9,132 $ — $ — $ 9,132 Electric Distribution 7,974 — — 7,974 Gas Transmission 89 — — 89 Gas Distribution 6,369 — — 6,369 Construction Work in Progress 1,501 — — 1,501 Plant Held for Future Use 19 — — 19 Other 439 — — 439 Total Transmission and Distribution 25,523 — — 25,523 Generation: Fossil Production — 7,096 — 7,096 Nuclear Production — 2,516 — 2,516 Nuclear Fuel in Service — 783 — 783 Other Production-Solar 591 687 — 1,278 Construction Work in Progress — 1,483 — 1,483 Total Generation 591 12,565 — 13,156 Other 233 90 335 658 Total $ 26,347 $ 12,655 $ 335 $ 39,337 PSE&G Power Other PSEG Consolidated Millions 2015 Transmission and Distribution: Electric Transmission $ 7,554 $ — $ — $ 7,554 Electric Distribution 7,553 — — 7,553 Gas Transmission 89 — — 89 Gas Distribution 5,875 — — 5,875 Construction Work in Progress 1,459 — — 1,459 Plant Held for Future Use 26 — — 26 Other 411 — — 411 Total Transmission and Distribution 22,967 — — 22,967 Generation: Fossil Production — 7,005 — 7,005 Nuclear Production — 2,202 — 2,202 Nuclear Fuel in Service — 785 — 785 Other Production-Solar 569 389 — 958 Construction Work in Progress — 892 — 892 Total Generation 569 11,273 — 11,842 Other 196 81 408 685 Total $ 23,732 $ 11,354 $ 408 $ 35,494 PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2016 2015 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 169 $ 65 $ 166 $ 72 Power: Coal Generating: Conemaugh 23 % $ 408 $ 166 $ 404 $ 154 Keystone 23 % $ 409 $ 176 $ 408 $ 163 Nuclear Generating: Peach Bottom 50 % $ 1,272 $ 306 $ 1,219 $ 262 Salem 57 % $ 1,077 $ 304 $ 990 $ 276 Nuclear Support Facilities Various $ 238 $ 71 $ 226 $ 60 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 25 $ 42 $ 24 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. |
PSE&G [Member] | |
Property, Plant and Equipment [Line Items] | |
Property Plant And Equipment And Jointly-Owned Facilities | Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2016 and 2015 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2016 Transmission and Distribution: Electric Transmission $ 9,132 $ — $ — $ 9,132 Electric Distribution 7,974 — — 7,974 Gas Transmission 89 — — 89 Gas Distribution 6,369 — — 6,369 Construction Work in Progress 1,501 — — 1,501 Plant Held for Future Use 19 — — 19 Other 439 — — 439 Total Transmission and Distribution 25,523 — — 25,523 Generation: Fossil Production — 7,096 — 7,096 Nuclear Production — 2,516 — 2,516 Nuclear Fuel in Service — 783 — 783 Other Production-Solar 591 687 — 1,278 Construction Work in Progress — 1,483 — 1,483 Total Generation 591 12,565 — 13,156 Other 233 90 335 658 Total $ 26,347 $ 12,655 $ 335 $ 39,337 PSE&G Power Other PSEG Consolidated Millions 2015 Transmission and Distribution: Electric Transmission $ 7,554 $ — $ — $ 7,554 Electric Distribution 7,553 — — 7,553 Gas Transmission 89 — — 89 Gas Distribution 5,875 — — 5,875 Construction Work in Progress 1,459 — — 1,459 Plant Held for Future Use 26 — — 26 Other 411 — — 411 Total Transmission and Distribution 22,967 — — 22,967 Generation: Fossil Production — 7,005 — 7,005 Nuclear Production — 2,202 — 2,202 Nuclear Fuel in Service — 785 — 785 Other Production-Solar 569 389 — 958 Construction Work in Progress — 892 — 892 Total Generation 569 11,273 — 11,842 Other 196 81 408 685 Total $ 23,732 $ 11,354 $ 408 $ 35,494 PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2016 2015 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 169 $ 65 $ 166 $ 72 Power: Coal Generating: Conemaugh 23 % $ 408 $ 166 $ 404 $ 154 Keystone 23 % $ 409 $ 176 $ 408 $ 163 Nuclear Generating: Peach Bottom 50 % $ 1,272 $ 306 $ 1,219 $ 262 Salem 57 % $ 1,077 $ 304 $ 990 $ 276 Nuclear Support Facilities Various $ 238 $ 71 $ 226 $ 60 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 25 $ 42 $ 24 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. |
Power [Member] | |
Property, Plant and Equipment [Line Items] | |
Property Plant And Equipment And Jointly-Owned Facilities | Property, Plant and Equipment and Jointly-Owned Facilities Information related to Property, Plant and Equipment as of December 31, 2016 and 2015 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2016 Transmission and Distribution: Electric Transmission $ 9,132 $ — $ — $ 9,132 Electric Distribution 7,974 — — 7,974 Gas Transmission 89 — — 89 Gas Distribution 6,369 — — 6,369 Construction Work in Progress 1,501 — — 1,501 Plant Held for Future Use 19 — — 19 Other 439 — — 439 Total Transmission and Distribution 25,523 — — 25,523 Generation: Fossil Production — 7,096 — 7,096 Nuclear Production — 2,516 — 2,516 Nuclear Fuel in Service — 783 — 783 Other Production-Solar 591 687 — 1,278 Construction Work in Progress — 1,483 — 1,483 Total Generation 591 12,565 — 13,156 Other 233 90 335 658 Total $ 26,347 $ 12,655 $ 335 $ 39,337 PSE&G Power Other PSEG Consolidated Millions 2015 Transmission and Distribution: Electric Transmission $ 7,554 $ — $ — $ 7,554 Electric Distribution 7,553 — — 7,553 Gas Transmission 89 — — 89 Gas Distribution 5,875 — — 5,875 Construction Work in Progress 1,459 — — 1,459 Plant Held for Future Use 26 — — 26 Other 411 — — 411 Total Transmission and Distribution 22,967 — — 22,967 Generation: Fossil Production — 7,005 — 7,005 Nuclear Production — 2,202 — 2,202 Nuclear Fuel in Service — 785 — 785 Other Production-Solar 569 389 — 958 Construction Work in Progress — 892 — 892 Total Generation 569 11,273 — 11,842 Other 196 81 408 685 Total $ 23,732 $ 11,354 $ 408 $ 35,494 PSE&G and Power have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities to which they are a party. All amounts reflect PSE&G’s or Power’s share of the jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2016 2015 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 169 $ 65 $ 166 $ 72 Power: Coal Generating: Conemaugh 23 % $ 408 $ 166 $ 404 $ 154 Keystone 23 % $ 409 $ 176 $ 408 $ 163 Nuclear Generating: Peach Bottom 50 % $ 1,272 $ 306 $ 1,219 $ 262 Salem 57 % $ 1,077 $ 304 $ 990 $ 276 Nuclear Support Facilities Various $ 238 $ 71 $ 226 $ 60 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 25 $ 42 $ 24 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly-owned facilities is included in the appropriate expense category. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures. Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process. Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power’s approval as part of the normal Power governance process. |
Regulatory Assets And Liabiliti
Regulatory Assets And Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets And Liabilities [Line Items] | |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies . PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2016 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods. Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income. PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Weather Normalization Clause (WNC) 49 10 Annual filing for recovery (2) Underrecovered Electric Energy Costs—Basic Generation Service 2 11 Annual filing for recovery (1) (2) Other 6 1 Various Total Current Regulatory Assets $ 199 $ 164 Noncurrent Pension and OPEB Costs $ 1,403 $ 1,270 Various Deferred Income Taxes 507 467 Various Manufactured Gas Plant (MGP) Remediation Costs 403 431 Various (2) Storm Damage Deferrals 239 233 To be determined Electric Transmission and Gas Cost of Removal 189 160 Through depreciation rates Remediation Adjustment Charge (RAC) (Other SBC) 180 174 Through 2022 (1) (2) Conditional Asset Retirement Obligation 157 152 Various Green Program Recovery Charges (GPRC) 91 104 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 61 67 Over remaining debt life Mark-to-Market (MTM) Contracts — 63 Through 2017 Other 89 75 Various Total Noncurrent Regulatory Assets $ 3,319 $ 3,196 Total Regulatory Assets $ 3,518 $ 3,360 As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Liabilities Current FERC Formula Rate True-up $ 34 $ 19 Annual filing for recovery (1) (2) GPRC 28 36 Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 11 13 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 6 1 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 5 1 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 4 31 Various (1) (2) Stranded Costs (including $42 in 2015 related to VIEs) — 64 Through December 2016 (2) Total Current Regulatory Liabilities $ 88 $ 165 Noncurrent Electric Distribution Cost of Removal $ 94 $ 122 Through depreciation rates MTM Contracts 20 — Various FERC Formula Rate True-up 1 49 Annual filing for recovery (1) (2) Other 3 4 Various Total Noncurrent Regulatory Liabilities $ 118 $ 175 Total Regulatory Liabilities $ 206 $ 340 (1) Recovered/Refunded with interest. (2) Recoverable/Refundable per specific rate order. All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows: • Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates. • Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. • Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its transmission and distribution assets upon retirement. The regulatory asset or liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred. • FERC Formula Rate True-up: Overcollection or undercollection of transmission earnings calculated using a FERC approved formula. • Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. • GPRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic (EEE) Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All), Solar 4 All Extension, Solar 4 All Extension II, Solar Loan II Program and Solar Loan III Program. • MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plants that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC. • MTM Contracts: The estimated fair value of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets. • New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2017. The BPU funding requirements are recovered through the SBC. • NGC: These costs represent the difference between the cost of non-utility generation and the benefit realized from the energy received at market rates. • Overrecovered Gas Costs: These costs represent the overrecovered amounts associated with Basic Gas Supply Service (BGSS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. For BGSS, interest is accrued only on overrecovered balances. • Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates. • RAC (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years. • SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries. • Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2016. As of December 31, 2016, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for recovery in a future base rate case proceeding under a BPU order received in September 2014. • Stranded Costs: As of December 31, 2015 , the balance represented overrecovered costs, which were collected by PSE&G as servicer on behalf of Transition Funding and Transition Funding II, respectively through the securitization transition charges authorized by the BPU in irrevocable financing. Collected funds were remitted to Transition Funding and Transition Funding II and used for interest and principal payments on the transition bonds and related costs and taxes. During 2015 , Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015 , no further debt or related costs remained. In 2016 , PSE&G refunded over-collections from customers associated with Stranded Costs and as of December 31, 2016 , there were no remaining Regulatory Assets or Liabilities associated with this program. • Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt. • Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with BGS, as approved by the BPU. For BGS, interest is accrued on both overrecovered and underrecovered balances. • WNC: This represents the over- or under- collection of gas margin refundable or recoverable under the BPU’s weather normalization clause. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are refunded to customers in the next winter season while under recoveries (subject to an earnings cap) are collected from customers in the next winter season. Significant 2016 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Transmission Formula Rate Filings —In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015. For the year ended December 31, 2016, PSE&G does not anticipate a significant true-up adjustment to its 2016 Annual Formula rate. That true-up will be filed by no later than June 15, 2017. In October 2016, the 2017 Annual Formula Rate Update was filed with FERC and requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to true-up. • Energy Strong Recovery Filing —In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million , respectively. In August 2016, the BPU approved these rate increases effective September 1, 2016. In September 2016, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2016 through November 30, 2016. In February 2017, the BPU approved PSE&G’s request for an annualized increase in electric revenue requirements of $12 million with rates effective March 1, 2017. • Gas System Modernization Program (GSMP) —In December 2016, the BPU approved PSE&G’s initial annual GSMP cost recovery petition which results in an annual revenue increase of $10 million effective January 1, 2017. This increase represents the return of and on investment for GSMP infrastructure in service through September 30, 2016. • Green Program Recovery Charges (GPRC) —Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In July 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. In September 2016, the BPU approved rates on a provisional basis effective October 1, 2016 designed to recover approximately $44 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved programs. In November 2016, the BPU approved PSE&G’s petition for a Solar 4 All Extension II Program for an additional 33 MWs of solar development on brownfields and closed landfills. The order allows PSE&G to extend the program under the same clause recovery process as its existing Solar 4 All Programs, with an estimated initial capital investment (excluding AFUDC) of approximately $80 million with a 9.75% ROE. The Solar 4 All Extension II Program is the tenth component of the GPRC. • BGSS —In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. In September 2016, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. The rate is subject to final settlement. In December 2016, PSE&G filed with the BPU for a self-implementing two-month bill credit of 7.5 cents per therm for the months of January and February 2017. In February 2017, PSE&G filed with the BPU to extend the self-implementing bill credit of 7.5 cents per therm to customers through March 2017. The 3-month bill credits are estimated to provide approximately $47 million in customer credits. The specific amount returned will depend on actual usage over that period. • Weather Normalization Clause —In July 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). In September 2016, the BPU approved PSE&G’s filing on a provisional basis with respect to the $54 million in deficiency revenues to be collected from customers effective October 1, 2016. This matter is pending. • Remediation Adjustment Charge (RAC) —In April 2016, the BPU approved PSE&G’s filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015. In November 2016, PSE&G filed a RAC 24 Petition with the BPU requesting recovery of $41 million of net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016. This matter is pending. • Universal Service Fund (USF)/Lifeline —In September 2016, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2016. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations. |
PSE&G [Member] | |
Regulatory Assets And Liabilities [Line Items] | |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities PSE&G prepares its financial statements in accordance with GAAP for regulated utilities as described in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies . PSE&G has deferred certain costs based on rate orders issued by the BPU or FERC or based on PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2016 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items. These costs will be recovered and amortized over various future periods. Regulatory Assets and other investments and costs incurred under our various infrastructure filings and clause mechanisms are subject to prudence reviews and can be disallowed in the future by regulatory authorities. To the extent that collection of any infrastructure or clause mechanism revenue, Regulatory Assets or payments of Regulatory Liabilities is no longer probable, the amounts would be charged or credited to income. PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Weather Normalization Clause (WNC) 49 10 Annual filing for recovery (2) Underrecovered Electric Energy Costs—Basic Generation Service 2 11 Annual filing for recovery (1) (2) Other 6 1 Various Total Current Regulatory Assets $ 199 $ 164 Noncurrent Pension and OPEB Costs $ 1,403 $ 1,270 Various Deferred Income Taxes 507 467 Various Manufactured Gas Plant (MGP) Remediation Costs 403 431 Various (2) Storm Damage Deferrals 239 233 To be determined Electric Transmission and Gas Cost of Removal 189 160 Through depreciation rates Remediation Adjustment Charge (RAC) (Other SBC) 180 174 Through 2022 (1) (2) Conditional Asset Retirement Obligation 157 152 Various Green Program Recovery Charges (GPRC) 91 104 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 61 67 Over remaining debt life Mark-to-Market (MTM) Contracts — 63 Through 2017 Other 89 75 Various Total Noncurrent Regulatory Assets $ 3,319 $ 3,196 Total Regulatory Assets $ 3,518 $ 3,360 As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Liabilities Current FERC Formula Rate True-up $ 34 $ 19 Annual filing for recovery (1) (2) GPRC 28 36 Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 11 13 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 6 1 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 5 1 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 4 31 Various (1) (2) Stranded Costs (including $42 in 2015 related to VIEs) — 64 Through December 2016 (2) Total Current Regulatory Liabilities $ 88 $ 165 Noncurrent Electric Distribution Cost of Removal $ 94 $ 122 Through depreciation rates MTM Contracts 20 — Various FERC Formula Rate True-up 1 49 Annual filing for recovery (1) (2) Other 3 4 Various Total Noncurrent Regulatory Liabilities $ 118 $ 175 Total Regulatory Liabilities $ 206 $ 340 (1) Recovered/Refunded with interest. (2) Recoverable/Refundable per specific rate order. All Regulatory Assets and Liabilities are excluded from PSE&G’s rate base unless otherwise noted. The Regulatory Assets and Liabilities in the table above are defined as follows: • Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates. • Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices. • Electric and Gas Cost of Removal: PSE&G accrues and collects in rates for the cost of removing, dismantling and disposing of its transmission and distribution assets upon retirement. The regulatory asset or liability for non-legally required cost of removal represents the difference between amounts collected in rates and costs actually incurred. • FERC Formula Rate True-up: Overcollection or undercollection of transmission earnings calculated using a FERC approved formula. • Gas Margin Adjustment Clause: This mechanism credits Firm delivery customers for net distribution margin revenue collected from Transportation Gas Service Non-Firm (TSG-NF) delivery customers. The balance represents the difference between the net margin collected from the TSG-NF Customers versus bill credits provided to Firm delivery customers. • GPRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the GPRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic (EEE) Extension Program, EEE Extension II Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All), Solar 4 All Extension, Solar 4 All Extension II, Solar Loan II Program and Solar Loan III Program. • MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plants that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC. • MTM Contracts: The estimated fair value of gas hedge contracts and gas cogeneration supply contract. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets. • New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2017. The BPU funding requirements are recovered through the SBC. • NGC: These costs represent the difference between the cost of non-utility generation and the benefit realized from the energy received at market rates. • Overrecovered Gas Costs: These costs represent the overrecovered amounts associated with Basic Gas Supply Service (BGSS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for gas customers within its service territory that are not served by another supplier. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for PSE&G’s operations. For BGSS, interest is accrued only on overrecovered balances. • Pension and OPEB Costs: Pursuant to the adoption of accounting guidance for employers’ defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates. • RAC (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years. • SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act, includes costs related to PSE&G’s electric and gas business as follows: (1) the Universal Service Fund (USF); (2) Energy Efficiency and Renewable Energy Programs; (3) Electric bad debt expense; and (4) the RAC for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries. • Storm Damage Deferrals: Costs incurred in the cleanup of major storms in 2010 through 2016. As of December 31, 2016, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for recovery in a future base rate case proceeding under a BPU order received in September 2014. • Stranded Costs: As of December 31, 2015 , the balance represented overrecovered costs, which were collected by PSE&G as servicer on behalf of Transition Funding and Transition Funding II, respectively through the securitization transition charges authorized by the BPU in irrevocable financing. Collected funds were remitted to Transition Funding and Transition Funding II and used for interest and principal payments on the transition bonds and related costs and taxes. During 2015 , Transition Funding and Transition Funding II paid their final securitization bond payments and as of December 31, 2015 , no further debt or related costs remained. In 2016 , PSE&G refunded over-collections from customers associated with Stranded Costs and as of December 31, 2016 , there were no remaining Regulatory Assets or Liabilities associated with this program. • Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt and expenses associated with issuances of new debt, which are recovered through rates over the remaining life of the debt. • Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with BGS, as approved by the BPU. For BGS, interest is accrued on both overrecovered and underrecovered balances. • WNC: This represents the over- or under- collection of gas margin refundable or recoverable under the BPU’s weather normalization clause. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. Over recoveries are refunded to customers in the next winter season while under recoveries (subject to an earnings cap) are collected from customers in the next winter season. Significant 2016 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Transmission Formula Rate Filings —In June 2016, PSE&G filed its 2015 true-up adjustment pertaining to its transmission formula rates in effect for 2015. This resulted in an adjustment of $34 million less than the 2015 originally filed revenues primarily due to the impact of bonus depreciation legislation enacted after PSE&G filed its 2015 formula rate requirement in October 2014. PSE&G had recognized the majority of this adjustment in its Consolidated Statement of Operations for the year ended December 31, 2015. For the year ended December 31, 2016, PSE&G does not anticipate a significant true-up adjustment to its 2016 Annual Formula rate. That true-up will be filed by no later than June 15, 2017. In October 2016, the 2017 Annual Formula Rate Update was filed with FERC and requests approximately $121 million in increased annual transmission revenues effective January 1, 2017, subject to true-up. • Energy Strong Recovery Filing —In March and September of each year, PSE&G files with the BPU for base rate recovery of Energy Strong investments which include a return of and on its investment. In June 2016, PSE&G updated its March cost recovery petition to include Energy Strong investments in service as of May 31, 2016 which represents estimated annual increases in electric and gas revenues of $16 million and $23 million , respectively. In August 2016, the BPU approved these rate increases effective September 1, 2016. In September 2016, PSE&G filed its Energy Strong electric cost recovery petition seeking BPU approval to recover the revenue requirements associated with Energy Strong capitalized investment costs placed in service from June 1, 2016 through November 30, 2016. In February 2017, the BPU approved PSE&G’s request for an annualized increase in electric revenue requirements of $12 million with rates effective March 1, 2017. • Gas System Modernization Program (GSMP) —In December 2016, the BPU approved PSE&G’s initial annual GSMP cost recovery petition which results in an annual revenue increase of $10 million effective January 1, 2017. This increase represents the return of and on investment for GSMP infrastructure in service through September 30, 2016. • Green Program Recovery Charges (GPRC) —Each year PSE&G files with the BPU for annual recovery of its Green Program investments which include a return on its investment and recovery of expenses. In July 2016, PSE&G filed its 2016 GPRC cost recovery petition requesting recovery for the nine combined components of the electric and gas GPRC. In September 2016, the BPU approved rates on a provisional basis effective October 1, 2016 designed to recover approximately $44 million and $13 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G’s implementation of these BPU approved programs. In November 2016, the BPU approved PSE&G’s petition for a Solar 4 All Extension II Program for an additional 33 MWs of solar development on brownfields and closed landfills. The order allows PSE&G to extend the program under the same clause recovery process as its existing Solar 4 All Programs, with an estimated initial capital investment (excluding AFUDC) of approximately $80 million with a 9.75% ROE. The Solar 4 All Extension II Program is the tenth component of the GPRC. • BGSS —In June 2016, PSE&G made its annual BGSS filing with the BPU requesting a reduction of $87 million in annual BGSS revenues. In September 2016, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 40 cents to 34 cents per therm effective October 1, 2016. The rate is subject to final settlement. In December 2016, PSE&G filed with the BPU for a self-implementing two-month bill credit of 7.5 cents per therm for the months of January and February 2017. In February 2017, PSE&G filed with the BPU to extend the self-implementing bill credit of 7.5 cents per therm to customers through March 2017. The 3-month bill credits are estimated to provide approximately $47 million in customer credits. The specific amount returned will depend on actual usage over that period. • Weather Normalization Clause —In July 2016, PSE&G filed a petition requesting approval to collect $54 million in net deficiency gas revenues as a result of the warmer than normal 2015-2016 Winter Period. The deficiency gas revenues would be collected from customers over the 2016-2017 and 2017-2018 Winter Periods (October 1 through May 31). In September 2016, the BPU approved PSE&G’s filing on a provisional basis with respect to the $54 million in deficiency revenues to be collected from customers effective October 1, 2016. This matter is pending. • Remediation Adjustment Charge (RAC) —In April 2016, the BPU approved PSE&G’s filing with respect to its RAC 23 petition allowing recovery of $54 million effective May 7, 2016 related to net Manufactured Gas Plant expenditures from August 1, 2014 through July 31, 2015. In November 2016, PSE&G filed a RAC 24 Petition with the BPU requesting recovery of $41 million of net Manufactured Gas Plant expenditures from August 1, 2015 through July 31, 2016. This matter is pending. • Universal Service Fund (USF)/Lifeline —In September 2016, the BPU approved rates set to recover state-wide costs incurred by New Jersey electric and gas distribution companies under the State’s USF/Lifeline energy assistance programs effective October 1, 2016. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on its Consolidated Statement of Operations. |
Long-Term Investments
Long-Term Investments | 12 Months Ended |
Dec. 31, 2016 | |
Long-Term Investments [Line Items] | |
Long-Term Investments [Text Block] | Long-Term Investments Long-Term Investments as of December 31, 2016 and 2015 included the following: As of December 31, 2016 2015 Millions PSE&G Life Insurance and Supplemental Benefits $ 140 $ 150 Solar Loans 159 175 Other Investments — 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 102 119 Energy Holdings Lease Investments 649 784 Total Long-Term Investments $ 1,050 $ 1,233 (A) During the three years ended December 31, 2016 , 2015 and 2014 , dividends from these investments were $18 million , $16 million and $17 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements , negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016 , calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016. For additional information, see Note 8. Financing Receivables . The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 2015 Millions Lease Receivables (net of Non-Recourse Debt) $ 629 $ 631 Estimated Residual Value of Leased Assets 346 519 Total Investment in Rental Receivables 975 1,150 Unearned and Deferred Income (326 ) (366 ) Gross Investments in Leases 649 784 Deferred Tax Liabilities (674 ) (724 ) Net Investments in Leases $ (25 ) $ 60 The pre-tax income (loss) and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2016 2015 2014 Millions Pre-Tax Income (Loss) from Leases $ (135 ) $ 12 $ 24 Income Tax Expense (Benefit) on Income from Leases $ (51 ) $ 5 $ 32 Equity Method Investments Power had the following equity method investments as of December 31, 2016 and 2015 : As of December 31, Name 2016 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 7 $ 16 PA 23% Conemaugh Fuels, LLC $ 8 $ 14 PA 23% PennEast Pipeline $ 11 $ 5 PA 10% Kalaeloa $ 76 $ 84 HI 50% |
PSE&G [Member] | |
Long-Term Investments [Line Items] | |
Long-Term Investments [Text Block] | Long-Term Investments Long-Term Investments as of December 31, 2016 and 2015 included the following: As of December 31, 2016 2015 Millions PSE&G Life Insurance and Supplemental Benefits $ 140 $ 150 Solar Loans 159 175 Other Investments — 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 102 119 Energy Holdings Lease Investments 649 784 Total Long-Term Investments $ 1,050 $ 1,233 (A) During the three years ended December 31, 2016 , 2015 and 2014 , dividends from these investments were $18 million , $16 million and $17 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements , negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016 , calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016. For additional information, see Note 8. Financing Receivables . The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 2015 Millions Lease Receivables (net of Non-Recourse Debt) $ 629 $ 631 Estimated Residual Value of Leased Assets 346 519 Total Investment in Rental Receivables 975 1,150 Unearned and Deferred Income (326 ) (366 ) Gross Investments in Leases 649 784 Deferred Tax Liabilities (674 ) (724 ) Net Investments in Leases $ (25 ) $ 60 The pre-tax income (loss) and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2016 2015 2014 Millions Pre-Tax Income (Loss) from Leases $ (135 ) $ 12 $ 24 Income Tax Expense (Benefit) on Income from Leases $ (51 ) $ 5 $ 32 Equity Method Investments Power had the following equity method investments as of December 31, 2016 and 2015 : As of December 31, Name 2016 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 7 $ 16 PA 23% Conemaugh Fuels, LLC $ 8 $ 14 PA 23% PennEast Pipeline $ 11 $ 5 PA 10% Kalaeloa $ 76 $ 84 HI 50% |
Power [Member] | |
Long-Term Investments [Line Items] | |
Long-Term Investments [Text Block] | Long-Term Investments Long-Term Investments as of December 31, 2016 and 2015 included the following: As of December 31, 2016 2015 Millions PSE&G Life Insurance and Supplemental Benefits $ 140 $ 150 Solar Loans 159 175 Other Investments — 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 102 119 Energy Holdings Lease Investments 649 784 Total Long-Term Investments $ 1,050 $ 1,233 (A) During the three years ended December 31, 2016 , 2015 and 2014 , dividends from these investments were $18 million , $16 million and $17 million , respectively. Leases Energy Holdings, through several of its indirect subsidiary companies, has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third-party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. During the third quarter of 2016, Energy Holdings completed its annual review of estimated residual values embedded in the NRG REMA, LLC (REMA) leveraged leases. The outcome indicated that the revised residual value estimates were lower than the recorded residual values and the decline was deemed to be other than temporary due to the adverse economic conditions experienced by coal generation in PJM, as discussed in Note 3. Early Plant Retirements , negatively impacting the economic outlook of the leased assets. As a result, a pre-tax write-down of $137 million was reflected in Operating Revenues in the quarter ended September 30, 2016 , calculated by comparing the gross investment in the leases before and after the revised residual estimates. During the fourth quarter of 2016, Energy Holdings recorded a $10 million charge for its best estimate of loss as a result of the current liquidity issues facing REMA, which was reflected in Operating Revenues and is included in Gross Investments in Leases as of December 31, 2016. For additional information, see Note 8. Financing Receivables . The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 2015 Millions Lease Receivables (net of Non-Recourse Debt) $ 629 $ 631 Estimated Residual Value of Leased Assets 346 519 Total Investment in Rental Receivables 975 1,150 Unearned and Deferred Income (326 ) (366 ) Gross Investments in Leases 649 784 Deferred Tax Liabilities (674 ) (724 ) Net Investments in Leases $ (25 ) $ 60 The pre-tax income (loss) and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2016 2015 2014 Millions Pre-Tax Income (Loss) from Leases $ (135 ) $ 12 $ 24 Income Tax Expense (Benefit) on Income from Leases $ (51 ) $ 5 $ 32 Equity Method Investments Power had the following equity method investments as of December 31, 2016 and 2015 : As of December 31, Name 2016 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 7 $ 16 PA 23% Conemaugh Fuels, LLC $ 8 $ 14 PA 23% PennEast Pipeline $ 11 $ 5 PA 10% Kalaeloa $ 76 $ 84 HI 50% |
Financing Receivables
Financing Receivables | 12 Months Ended |
Dec. 31, 2016 | |
Financing Receivable, Recorded Investment [Line Items] | |
Financing Receivables | Financing Receivables PSE&G PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. The following table reflects the outstanding loans, including the noncurrent portion reported in Note 7. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2016 2015 Millions Commercial/Industrial $ 164 $ 177 Residential 11 12 Total $ 175 $ 189 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $(25) million as of December 31, 2016 and $60 million as of December 31, 2015 (See Note 7. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2016 As of December 31, 2016 Millions AA $ 16 BBB+ — BBB- 316 BB- 133 CCC 164 Total $ 629 The “BB-” and the “CCC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2016 , the gross investment in the leases of such assets, net of non-recourse debt, was $426 million , ( $(131) million , net of deferred taxes). A more detailed description of such assets under lease is presented in the following table. Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 134 64 % 1,538 Coal BB- NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 83 64 % 1,036 Gas BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Conemaugh Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Shawville Station Units 1, 2, 3 and 4 PA $ 99 100 % 596 Gas CCC (A) REMA (A) REMA’s parent company, GenOn Energy Inc. (GenOn), reported in August 2016 that GenOn did not expect to have sufficient liquidity to repay its senior unsecured notes due in June 2017. In January 2017, S&P further lowered its corporate credit rating on GenOn and its affiliates (including REMA) to “CCC - “ from “CCC” reflecting the primary credit concern of the near-term maturity of GenOn’s senior unsecured notes in June 2017 and expressed a negative outlook reflecting the continuing pressure on financial measures. In October 2016, Moody’s downgraded the GenOn Corporate Family Rating to “Caa3” to reflect its high debt burden relative to cash flow. The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service. Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease. |
PSE&G [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Financing Receivables | Financing Receivables PSE&G PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with solar renewable energy certificates (SRECs) generated from the installed solar electric system. The following table reflects the outstanding loans, including the noncurrent portion reported in Note 7. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2016 2015 Millions Commercial/Industrial $ 164 $ 177 Residential 11 12 Total $ 175 $ 189 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $(25) million as of December 31, 2016 and $60 million as of December 31, 2015 (See Note 7. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2016 As of December 31, 2016 Millions AA $ 16 BBB+ — BBB- 316 BB- 133 CCC 164 Total $ 629 The “BB-” and the “CCC” ratings in the preceding table represent lease receivables related to coal and gas-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2016 , the gross investment in the leases of such assets, net of non-recourse debt, was $426 million , ( $(131) million , net of deferred taxes). A more detailed description of such assets under lease is presented in the following table. Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 134 64 % 1,538 Coal BB- NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 83 64 % 1,036 Gas BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Conemaugh Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Shawville Station Units 1, 2, 3 and 4 PA $ 99 100 % 596 Gas CCC (A) REMA (A) REMA’s parent company, GenOn Energy Inc. (GenOn), reported in August 2016 that GenOn did not expect to have sufficient liquidity to repay its senior unsecured notes due in June 2017. In January 2017, S&P further lowered its corporate credit rating on GenOn and its affiliates (including REMA) to “CCC - “ from “CCC” reflecting the primary credit concern of the near-term maturity of GenOn’s senior unsecured notes in June 2017 and expressed a negative outlook reflecting the continuing pressure on financial measures. In October 2016, Moody’s downgraded the GenOn Corporate Family Rating to “Caa3” to reflect its high debt burden relative to cash flow. The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease structures. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital and trigger certain material tax obligations which could wholly or partially be mitigated by tax indemnification claims against the counterparty. A bankruptcy of a lessee would likely delay and potentially limit any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the assets under lease by the lenders. Although all lease payments are current, PSEG cannot predict the outcome of GenOn’s efforts to restructure its portfolio and improve its liquidity and the possible related impact on REMA. PSEG continues to monitor any changes to REMA’s and GenOn’s status and potential impacts on Energy Holdings’ lease investments. If lease rejections or foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities to the Internal Revenue Service. Additional factors that may impact future lease cash flows include, but are not limited to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel, electricity and capacity, overall financial condition of lease counterparties and their affiliates and the quality and condition of assets under lease. |
Available-for-Sale Securities
Available-for-Sale Securities | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-Sale Securities [Text Block] | Available-for-Sale Securities NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2016 was approximately $454 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 705 $ 263 $ (11 ) $ 957 Debt Securities Government 518 8 (6 ) 520 Corporate 337 4 (4 ) 337 Total Debt Securities 855 12 (10 ) 857 Other Securities 44 — — 44 Total NDT Available-for-Sale Securities (A) $ 1,604 $ 275 $ (21 ) $ 1,858 (A) The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund. As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government 483 8 (3 ) 488 Corporate 366 3 (10 ) 359 Total Debt Securities 849 11 (13 ) 847 Other Securities 42 — — 42 Total NDT Available-for-Sale Securities $ 1,584 $ 196 $ (26 ) $ 1,754 The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 8 $ 17 Accounts Payable $ 5 $ 10 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months. As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ 120 $ (10 ) $ 8 $ (1 ) $ 151 $ (13 ) $ 1 $ — Debt Securities Government (B) 276 (6 ) 4 — 245 (2 ) 19 (1 ) Corporate (C) 139 (3 ) 15 (1 ) 222 (7 ) 36 (3 ) Total Debt Securities 415 (9 ) 19 (1 ) 467 (9 ) 55 (4 ) NDT Available-for-Sale Securities $ 535 $ (19 ) $ 27 $ (2 ) $ 618 $ (22 ) $ 56 $ (4 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2016 . (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Sales (A) $ 711 $ 1,397 $ 1,448 Net Realized Gains (Losses): Gross Realized Gains $ 53 $ 97 $ 177 Gross Realized Losses (32 ) (37 ) (23 ) Net Realized Gains (Losses) on NDT Fund $ 21 $ 60 $ 154 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $128 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2016 . The available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 15 1 - 5 years 257 6 - 10 years 193 11 - 15 years 50 16 - 20 years 60 Over 20 years 282 Total NDT Available-for-Sale Debt Securities $ 857 The cost of these securities was determined on the basis of specific identification. Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2016 , other-than-temporary impairments of $28 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 11 $ 11 $ — $ 22 Debt Securities Government 105 — (2 ) 103 Corporate 92 1 (2 ) 91 Total Debt Securities 197 1 (4 ) 194 Other Securities 1 — — 1 Total Rabbi Trust Available-for-Sale Securities $ 209 $ 12 $ (4 ) $ 217 As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government 108 1 (1 ) 108 Corporate 82 — (1 ) 81 Total Debt Securities 190 1 (2 ) 189 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 204 $ 11 $ (2 ) $ 213 The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 5 $ 1 Accounts Payable $ 3 $ — The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months: As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ — $ — $ — $ — $ — $ — $ — $ — Debt Securities Government (B) 60 (2 ) 1 — 53 (1 ) 2 — Corporate (C) 46 (2 ) 3 — 46 (1 ) 9 — Total Debt Securities 106 (4 ) 4 — 99 (2 ) 11 — Rabbi Trust Available-for-Sale Securities $ 106 $ (4 ) $ 4 $ — $ 99 $ (2 ) $ 11 $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. (B) Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Rabbi Trust Sales (A) $ 113 $ 104 $ 467 Net Realized Gains (Losses): Gross Realized Gains $ 6 $ 3 $ 4 Gross Realized Losses (5 ) (2 ) (3 ) Net Realized Gains (Losses) on Rabbi Trust $ 1 $ 1 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $5 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2016 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 8 1 - 5 years 44 6 - 10 years 44 11 - 15 years 9 16 - 20 years 8 Over 20 years 81 Total Rabbi Trust Available-for-Sale Debt Securities $ 194 The cost of these securities was determined on the basis of specific identification. PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2016 , there were no other-than-temporary impairments recognized on investments of the Rabbi Trust. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, 2016 As of December 31, 2015 Millions PSE&G $ 43 $ 42 Power 53 52 Other 121 119 Total Rabbi Trust Available-for-Sale Securities $ 217 $ 213 |
PSE&G [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-Sale Securities [Text Block] | Available-for-Sale Securities NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2016 was approximately $454 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 705 $ 263 $ (11 ) $ 957 Debt Securities Government 518 8 (6 ) 520 Corporate 337 4 (4 ) 337 Total Debt Securities 855 12 (10 ) 857 Other Securities 44 — — 44 Total NDT Available-for-Sale Securities (A) $ 1,604 $ 275 $ (21 ) $ 1,858 (A) The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund. As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government 483 8 (3 ) 488 Corporate 366 3 (10 ) 359 Total Debt Securities 849 11 (13 ) 847 Other Securities 42 — — 42 Total NDT Available-for-Sale Securities $ 1,584 $ 196 $ (26 ) $ 1,754 The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 8 $ 17 Accounts Payable $ 5 $ 10 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months. As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ 120 $ (10 ) $ 8 $ (1 ) $ 151 $ (13 ) $ 1 $ — Debt Securities Government (B) 276 (6 ) 4 — 245 (2 ) 19 (1 ) Corporate (C) 139 (3 ) 15 (1 ) 222 (7 ) 36 (3 ) Total Debt Securities 415 (9 ) 19 (1 ) 467 (9 ) 55 (4 ) NDT Available-for-Sale Securities $ 535 $ (19 ) $ 27 $ (2 ) $ 618 $ (22 ) $ 56 $ (4 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2016 . (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Sales (A) $ 711 $ 1,397 $ 1,448 Net Realized Gains (Losses): Gross Realized Gains $ 53 $ 97 $ 177 Gross Realized Losses (32 ) (37 ) (23 ) Net Realized Gains (Losses) on NDT Fund $ 21 $ 60 $ 154 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $128 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2016 . The available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 15 1 - 5 years 257 6 - 10 years 193 11 - 15 years 50 16 - 20 years 60 Over 20 years 282 Total NDT Available-for-Sale Debt Securities $ 857 The cost of these securities was determined on the basis of specific identification. Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2016 , other-than-temporary impairments of $28 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 11 $ 11 $ — $ 22 Debt Securities Government 105 — (2 ) 103 Corporate 92 1 (2 ) 91 Total Debt Securities 197 1 (4 ) 194 Other Securities 1 — — 1 Total Rabbi Trust Available-for-Sale Securities $ 209 $ 12 $ (4 ) $ 217 As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government 108 1 (1 ) 108 Corporate 82 — (1 ) 81 Total Debt Securities 190 1 (2 ) 189 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 204 $ 11 $ (2 ) $ 213 The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 5 $ 1 Accounts Payable $ 3 $ — The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months: As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ — $ — $ — $ — $ — $ — $ — $ — Debt Securities Government (B) 60 (2 ) 1 — 53 (1 ) 2 — Corporate (C) 46 (2 ) 3 — 46 (1 ) 9 — Total Debt Securities 106 (4 ) 4 — 99 (2 ) 11 — Rabbi Trust Available-for-Sale Securities $ 106 $ (4 ) $ 4 $ — $ 99 $ (2 ) $ 11 $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. (B) Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Rabbi Trust Sales (A) $ 113 $ 104 $ 467 Net Realized Gains (Losses): Gross Realized Gains $ 6 $ 3 $ 4 Gross Realized Losses (5 ) (2 ) (3 ) Net Realized Gains (Losses) on Rabbi Trust $ 1 $ 1 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $5 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2016 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 8 1 - 5 years 44 6 - 10 years 44 11 - 15 years 9 16 - 20 years 8 Over 20 years 81 Total Rabbi Trust Available-for-Sale Debt Securities $ 194 The cost of these securities was determined on the basis of specific identification. PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2016 , there were no other-than-temporary impairments recognized on investments of the Rabbi Trust. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, 2016 As of December 31, 2015 Millions PSE&G $ 43 $ 42 Power 53 52 Other 121 119 Total Rabbi Trust Available-for-Sale Securities $ 217 $ 213 |
Power [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-Sale Securities [Text Block] | Available-for-Sale Securities NDT Fund In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power is required to file periodic reports with the NRC demonstrating that its NDT Fund meets the formula-based minimum NRC funding requirements. Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.8 billion and $3.0 billion , including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2016 was approximately $454 million and is included in the Asset Retirement Obligation. The funds are managed by third-party investment managers who operate under investment guidelines developed by Power. Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 705 $ 263 $ (11 ) $ 957 Debt Securities Government 518 8 (6 ) 520 Corporate 337 4 (4 ) 337 Total Debt Securities 855 12 (10 ) 857 Other Securities 44 — — 44 Total NDT Available-for-Sale Securities (A) $ 1,604 $ 275 $ (21 ) $ 1,858 (A) The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund. As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government 483 8 (3 ) 488 Corporate 366 3 (10 ) 359 Total Debt Securities 849 11 (13 ) 847 Other Securities 42 — — 42 Total NDT Available-for-Sale Securities $ 1,584 $ 196 $ (26 ) $ 1,754 The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 8 $ 17 Accounts Payable $ 5 $ 10 The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months. As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ 120 $ (10 ) $ 8 $ (1 ) $ 151 $ (13 ) $ 1 $ — Debt Securities Government (B) 276 (6 ) 4 — 245 (2 ) 19 (1 ) Corporate (C) 139 (3 ) 15 (1 ) 222 (7 ) 36 (3 ) Total Debt Securities 415 (9 ) 19 (1 ) 467 (9 ) 55 (4 ) NDT Available-for-Sale Securities $ 535 $ (19 ) $ 27 $ (2 ) $ 618 $ (22 ) $ 56 $ (4 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2016 . (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Sales (A) $ 711 $ 1,397 $ 1,448 Net Realized Gains (Losses): Gross Realized Gains $ 53 $ 97 $ 177 Gross Realized Losses (32 ) (37 ) (23 ) Net Realized Gains (Losses) on NDT Fund $ 21 $ 60 $ 154 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the preceding table were recognized in Other Income and Other Deductions, respectively, in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $128 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG’s and Power’s Consolidated Balance Sheets as of December 31, 2016 . The available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 15 1 - 5 years 257 6 - 10 years 193 11 - 15 years 50 16 - 20 years 60 Over 20 years 282 Total NDT Available-for-Sale Debt Securities $ 857 The cost of these securities was determined on the basis of specific identification. Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2016 , other-than-temporary impairments of $28 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. Rabbi Trust PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.” PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 11 $ 11 $ — $ 22 Debt Securities Government 105 — (2 ) 103 Corporate 92 1 (2 ) 91 Total Debt Securities 197 1 (4 ) 194 Other Securities 1 — — 1 Total Rabbi Trust Available-for-Sale Securities $ 209 $ 12 $ (4 ) $ 217 As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government 108 1 (1 ) 108 Corporate 82 — (1 ) 81 Total Debt Securities 190 1 (2 ) 189 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 204 $ 11 $ (2 ) $ 213 The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 5 $ 1 Accounts Payable $ 3 $ — The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months: As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ — $ — $ — $ — $ — $ — $ — $ — Debt Securities Government (B) 60 (2 ) 1 — 53 (1 ) 2 — Corporate (C) 46 (2 ) 3 — 46 (1 ) 9 — Total Debt Securities 106 (4 ) 4 — 99 (2 ) 11 — Rabbi Trust Available-for-Sale Securities $ 106 $ (4 ) $ 4 $ — $ 99 $ (2 ) $ 11 $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. (B) Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Rabbi Trust Sales (A) $ 113 $ 104 $ 467 Net Realized Gains (Losses): Gross Realized Gains $ 6 $ 3 $ 4 Gross Realized Losses (5 ) (2 ) (3 ) Net Realized Gains (Losses) on Rabbi Trust $ 1 $ 1 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. Gross realized gains and gross realized losses disclosed in the above table were recognized in Other Income and Other Deductions, respectively, in the Consolidated Statements of Operations. Net unrealized gains of $5 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2016 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 8 1 - 5 years 44 6 - 10 years 44 11 - 15 years 9 16 - 20 years 8 Over 20 years 81 Total Rabbi Trust Available-for-Sale Debt Securities $ 194 The cost of these securities was determined on the basis of specific identification. PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2016 , there were no other-than-temporary impairments recognized on investments of the Rabbi Trust. The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, 2016 As of December 31, 2015 Millions PSE&G $ 43 $ 42 Power 53 52 Other 121 119 Total Rabbi Trust Available-for-Sale Securities $ 217 $ 213 |
Goodwill And Other Intangibles
Goodwill And Other Intangibles | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill [Line Items] | |
Goodwill And Other Intangibles | Goodwill and Other Intangibles As of December 31, 2016 and 2015 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2016 and concluded that goodwill was not impaired. In addition to goodwill, as of December 31, 2016 and 2015 , Power had intangible assets of $ 98 million and $ 102 million , respectively, related to emissions allowances and renewable energy credits. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. Such expenses for the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, 2016 2015 2014 Millions Emissions Expense $ 14 $ 13 $ 10 Renewable Energy Expense $ 95 $ 91 $ 59 |
Power [Member] | |
Goodwill [Line Items] | |
Goodwill And Other Intangibles | Goodwill and Other Intangibles As of December 31, 2016 and 2015 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment in the fourth quarter of 2016 and concluded that goodwill was not impaired. In addition to goodwill, as of December 31, 2016 and 2015 , Power had intangible assets of $ 98 million and $ 102 million , respectively, related to emissions allowances and renewable energy credits. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. Such expenses for the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, 2016 2015 2014 Millions Emissions Expense $ 14 $ 13 $ 10 Renewable Energy Expense $ 95 $ 91 $ 59 |
Asset Retirement Obligations (A
Asset Retirement Obligations (AROs) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Line Items] | |
Asset Retirement Obligations (AROs) | Asset Retirement Obligations (AROs) PSEG, PSE&G and Power have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015. When assumptions are revised to calculate fair values of existing AROs, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2015 and 2016 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2015 $ 743 $ 290 $ 450 $ 3 Liabilities Settled (5 ) (4 ) (1 ) — Liabilities Incurred 14 1 12 1 Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 16 16 — — Revision to Present Values of Estimated Cash Flows (115 ) (85 ) (30 ) — ARO Liability as of December 31, 2015 $ 679 $ 218 $ 457 $ 4 Liabilities Settled (13 ) (9 ) (4 ) — Liabilities Incurred 25 2 23 — Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (3 ) (10 ) 9 (2 ) ARO Liability as of December 31, 2016 $ 726 $ 213 $ 511 $ 2 (A) Not reflected as expense in Consolidated Statements of Operations During 2016, PSE&G recorded a reduction in its ARO liabilities primarily due to the impact of settlements and changes to cash flow estimates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2016, Power recorded $23 million primarily related to new ARO liabilities at its fossil units coupled with new solar generation ARO liabilities. |
PSE&G [Member] | |
Asset Retirement Obligation [Line Items] | |
Asset Retirement Obligations (AROs) | Asset Retirement Obligations (AROs) PSEG, PSE&G and Power have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015. When assumptions are revised to calculate fair values of existing AROs, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2015 and 2016 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2015 $ 743 $ 290 $ 450 $ 3 Liabilities Settled (5 ) (4 ) (1 ) — Liabilities Incurred 14 1 12 1 Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 16 16 — — Revision to Present Values of Estimated Cash Flows (115 ) (85 ) (30 ) — ARO Liability as of December 31, 2015 $ 679 $ 218 $ 457 $ 4 Liabilities Settled (13 ) (9 ) (4 ) — Liabilities Incurred 25 2 23 — Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (3 ) (10 ) 9 (2 ) ARO Liability as of December 31, 2016 $ 726 $ 213 $ 511 $ 2 (A) Not reflected as expense in Consolidated Statements of Operations During 2016, PSE&G recorded a reduction in its ARO liabilities primarily due to the impact of settlements and changes to cash flow estimates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2016, Power recorded $23 million primarily related to new ARO liabilities at its fossil units coupled with new solar generation ARO liabilities. |
Power [Member] | |
Asset Retirement Obligation [Line Items] | |
Asset Retirement Obligations (AROs) | Asset Retirement Obligations (AROs) PSEG, PSE&G and Power have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement. PSE&G has conditional AROs primarily for legal obligations related to the removal of treated wood poles and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G does not record an ARO for its protected steel and poly-based natural gas lines, as management believes that these categories of gas lines have an indeterminable life. Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities . Power also identified conditional AROs primarily related to Power’s fossil generation units and solar facilities, including liabilities for removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites, and demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service. To estimate the fair value of its AROs, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on third-party decommissioning cost estimates, cost escalation rates, inflation rates and discount rates. Updated cost studies are obtained triennially unless new information necessitates more frequent updates. The most recent cost study was done in 2015. When assumptions are revised to calculate fair values of existing AROs, the ARO balance and corresponding long-lived asset are adjusted which impact the amount of accretion and depreciation expense recognized in future periods. For PSE&G, Regulatory Assets and Regulatory Liabilities result when accretion and amortization are adjusted to match rates established by regulators resulting in the regulatory deferral of any gain or loss. The changes to the ARO liabilities for PSEG, PSE&G and Power during 2015 and 2016 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2015 $ 743 $ 290 $ 450 $ 3 Liabilities Settled (5 ) (4 ) (1 ) — Liabilities Incurred 14 1 12 1 Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 16 16 — — Revision to Present Values of Estimated Cash Flows (115 ) (85 ) (30 ) — ARO Liability as of December 31, 2015 $ 679 $ 218 $ 457 $ 4 Liabilities Settled (13 ) (9 ) (4 ) — Liabilities Incurred 25 2 23 — Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (3 ) (10 ) 9 (2 ) ARO Liability as of December 31, 2016 $ 726 $ 213 $ 511 $ 2 (A) Not reflected as expense in Consolidated Statements of Operations During 2016, PSE&G recorded a reduction in its ARO liabilities primarily due to the impact of settlements and changes to cash flow estimates. These changes had no impact in PSE&G’s Consolidated Statement of Operations . During 2016, Power recorded $23 million primarily related to new ARO liabilities at its fossil units coupled with new solar generation ARO liabilities. |
Pension, OPEB and Savings Plans
Pension, OPEB and Savings Plans | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension, OPEB and Savings Plans | Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change was reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $34 million and $13 million , respectively, as compared to the 2016 amounts that would have been derived from applying PSEG’s 2015 and prior years’ methodology. As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. No changes were made to the benefit formulas, the vesting provisions, or to the employees covered by the plans. Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Service Cost 109 123 17 22 Interest Cost 202 234 59 67 Actuarial (Gain) Loss (B) 219 (289 ) 127 (45 ) Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Plan Amendments 2 — (4 ) — Benefit Obligation at End of Year (A) $ 5,772 $ 5,522 $ 1,754 $ 1,612 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,039 $ 5,293 $ 374 $ 361 Actual Return on Plan Assets 403 (11 ) 32 (1 ) Employer Contributions 33 25 71 84 Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Fair Value of Assets at End of Year $ 5,193 $ 5,039 $ 420 $ 374 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ — $ 14 $ — $ — Current Accrued Benefit Cost (11 ) (10 ) (10 ) (10 ) Noncurrent Accrued Benefit Cost (568 ) (487 ) (1,324 ) (1,228 ) Amounts Recognized $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (63 ) $ (83 ) $ (14 ) $ (25 ) Net Actuarial Loss 1,763 1,710 523 438 Total $ 1,700 $ 1,627 $ 509 $ 413 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Includes $ 679 million ($ 398 million , after-tax) and $ 658 million ($ 386 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2016 and 2015 , respectively. The pension benefits table above provides information relating to the funded status of the qualified, nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2016 , PSEG had funded approximately 90% of its projected benefit obligation. This percentage does not include $ 217 million of assets in the Rabbi Trust as of December 31, 2016 which were used partially to fund the nonqualified pension plans. As of December 31, 2016 , the nonqualified pension plans included in the projected benefit obligation in the above table were $161 million . The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets. Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.6 billion as of December 31, 2016 and $ 5.4 billion as of December 31, 2015 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 109 $ 123 $ 104 $ 17 $ 22 18 Interest Cost 202 234 234 59 67 69 Expected Return on Plan Assets (394 ) (414 ) (399 ) (31 ) (31 ) (26 ) Amortization of Net Prior Service Credit (19 ) (19 ) (18 ) (14 ) (14 ) (14 ) Actuarial Loss 158 150 56 40 43 23 Net Periodic Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions PSE&G $ 29 $ 40 $ (19 ) $ 43 $ 55 $ 46 Power 16 21 (7 ) 23 27 20 Other 11 13 3 5 5 4 Total Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2016 2015 2016 2015 Millions Net Actuarial (Gain) Loss in Current Period $ 211 $ 136 $ 125 $ (14 ) Amortization of Net Actuarial Gain (Loss) (158 ) (150 ) (40 ) (43 ) Prior Service Cost (Credit) in current period 1 — (3 ) — Amortization of Prior Service Credit 19 19 14 14 Total $ 73 $ 5 $ 96 $ (43 ) Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2017 are as follows: Pension Benefits Other Benefits 2017 2017 Millions Actuarial (Gain) Loss $ 97 $ 51 Prior Service Cost $ (18 ) $ (11 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.29 % 4.54 % 4.20 % 4.37 % 4.58 % 4.21 % Rate of Compensation Increase 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Service Cost Interest Rate 4.81 % 4.20 % 5.00 % 4.87 % 4.21 % 5.01 % Interest Cost Interest Rate 3.75 % 4.20 % 5.00 % 3.76 % 4.21 % 5.01 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 3.00 % 3.00 % 3.00 % Health Care Costs Immediate Rate 7.55 % 7.75 % 7.40 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2022 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 11 $ 12 $ 13 Postretirement Benefit Obligation $ 191 $ 194 $ 201 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (9 ) $ (10 ) $ (10 ) Postretirement Benefit Obligation $ (160 ) $ (160 ) $ (165 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2016 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 93% and 7% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 107 $ 105 $ 2 $ — Equities (B) Common Stock 944 944 — — Commingled (C) 1,387 1,247 140 — Preferred Stock 1 1 — — Bonds (D) US Treasury 441 — 441 — Government—Other 263 — 263 — Corporate 836 — 836 — Subtotal Fair Value $ 3,979 $ 2,297 $ 1,682 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,604 Private Equity (E) 16 Total Fair Value (F) $ 5,599 Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 96 $ 95 $ 1 $ — Equities (B) Common Stock 816 816 — — Commingled (C) 1,463 1,269 194 — Bonds (D) US Treasury 322 — 322 — Government—Other 279 — 279 — Corporate 906 — 906 — Subtotal Fair Value $ 3,882 $ 2,180 $ 1,702 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,504 Private Equity (E) 19 Total Fair Value (F) $ 5,405 (A) Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2. (C) In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. See Note 2. Recent Accounting Standards . These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015. (D) Fixed income securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. (E) Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. (F) Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015 , respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 70 % 70 % Fixed Income Securities 28 28 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.0% for 2016 and will be 7.8% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception, which was 9.3% . Plan Contributions PSEG plans to contribute $14 million into its OPEB plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2017 $ 310 $ 82 2018 307 86 2019 319 90 2020 331 94 2021 343 99 2022-2026 1,887 534 Total $ 3,497 $ 985 401(k) Plans PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution retirement plans. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2016 2015 2014 Millions PSE&G $ 24 $ 22 $ 20 Power 12 12 11 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 39 $ 36 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entities . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 211 $ 195 $ 375 $ 452 Service Cost 24 26 12 17 Interest Cost 9 9 17 21 Actuarial (Gain) Loss 14 (20 ) 50 (114 ) Gross Benefits Paid (1 ) — (2 ) (1 ) Plan Amendments 5 1 — — Benefit Obligation at End of Year (A) $ 262 $ 211 $ 452 $ 375 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 97 $ 69 $ — $ — Actual Return on Plan Assets 10 (2 ) — — Employer Contributions 28 30 2 1 Gross Benefits Paid (1 ) — (2 ) (1 ) Fair Value of Assets at End of Year $ 134 $ 97 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (128 ) $ (114 ) $ (452 ) $ (375 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (128 ) $ (114 ) N/A N/A OPEB Costs of Servco N/A N/A (452 ) (375 ) Amounts Recognized (B) $ (128 ) $ (114 ) $ (452 ) $ (375 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2016 , 2015 and 2014 were $28 million , $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2016 . The OPEB-related revenues earned and costs incurred in 2016 was $2 million , and were immaterial 2015 and 2014 . The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.61 % 4.92 % 4.50 % 4.71 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.55 % 7.33 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 97 $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (75 ) $ (60 ) $ (106 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 96 $ — $ 96 $ — Commingled Bonds (A) 38 — 38 — Total $ 134 $ — $ 134 $ — Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 68 $ — $ 68 $ — Commingled Bonds (A) 29 — 29 — Total $ 97 $ — $ 97 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as Level 2. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 71 % 71 % Fixed Income Securities 29 29 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.7% for 2016 and will be 7.6% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $35 million into its pension plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2017 $ 2 $ 4 2018 3 6 2019 5 9 2020 7 11 2021 8 13 2022-2026 76 96 Total $ 101 $ 139 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2016 , 2015 and 2014 were $5 million , $4 million and $3 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs. |
PSE&G [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension, OPEB and Savings Plans | Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change was reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $34 million and $13 million , respectively, as compared to the 2016 amounts that would have been derived from applying PSEG’s 2015 and prior years’ methodology. As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. No changes were made to the benefit formulas, the vesting provisions, or to the employees covered by the plans. Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Service Cost 109 123 17 22 Interest Cost 202 234 59 67 Actuarial (Gain) Loss (B) 219 (289 ) 127 (45 ) Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Plan Amendments 2 — (4 ) — Benefit Obligation at End of Year (A) $ 5,772 $ 5,522 $ 1,754 $ 1,612 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,039 $ 5,293 $ 374 $ 361 Actual Return on Plan Assets 403 (11 ) 32 (1 ) Employer Contributions 33 25 71 84 Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Fair Value of Assets at End of Year $ 5,193 $ 5,039 $ 420 $ 374 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ — $ 14 $ — $ — Current Accrued Benefit Cost (11 ) (10 ) (10 ) (10 ) Noncurrent Accrued Benefit Cost (568 ) (487 ) (1,324 ) (1,228 ) Amounts Recognized $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (63 ) $ (83 ) $ (14 ) $ (25 ) Net Actuarial Loss 1,763 1,710 523 438 Total $ 1,700 $ 1,627 $ 509 $ 413 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Includes $ 679 million ($ 398 million , after-tax) and $ 658 million ($ 386 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2016 and 2015 , respectively. The pension benefits table above provides information relating to the funded status of the qualified, nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2016 , PSEG had funded approximately 90% of its projected benefit obligation. This percentage does not include $ 217 million of assets in the Rabbi Trust as of December 31, 2016 which were used partially to fund the nonqualified pension plans. As of December 31, 2016 , the nonqualified pension plans included in the projected benefit obligation in the above table were $161 million . The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets. Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.6 billion as of December 31, 2016 and $ 5.4 billion as of December 31, 2015 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 109 $ 123 $ 104 $ 17 $ 22 18 Interest Cost 202 234 234 59 67 69 Expected Return on Plan Assets (394 ) (414 ) (399 ) (31 ) (31 ) (26 ) Amortization of Net Prior Service Credit (19 ) (19 ) (18 ) (14 ) (14 ) (14 ) Actuarial Loss 158 150 56 40 43 23 Net Periodic Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions PSE&G $ 29 $ 40 $ (19 ) $ 43 $ 55 $ 46 Power 16 21 (7 ) 23 27 20 Other 11 13 3 5 5 4 Total Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2016 2015 2016 2015 Millions Net Actuarial (Gain) Loss in Current Period $ 211 $ 136 $ 125 $ (14 ) Amortization of Net Actuarial Gain (Loss) (158 ) (150 ) (40 ) (43 ) Prior Service Cost (Credit) in current period 1 — (3 ) — Amortization of Prior Service Credit 19 19 14 14 Total $ 73 $ 5 $ 96 $ (43 ) Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2017 are as follows: Pension Benefits Other Benefits 2017 2017 Millions Actuarial (Gain) Loss $ 97 $ 51 Prior Service Cost $ (18 ) $ (11 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.29 % 4.54 % 4.20 % 4.37 % 4.58 % 4.21 % Rate of Compensation Increase 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Service Cost Interest Rate 4.81 % 4.20 % 5.00 % 4.87 % 4.21 % 5.01 % Interest Cost Interest Rate 3.75 % 4.20 % 5.00 % 3.76 % 4.21 % 5.01 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 3.00 % 3.00 % 3.00 % Health Care Costs Immediate Rate 7.55 % 7.75 % 7.40 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2022 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 11 $ 12 $ 13 Postretirement Benefit Obligation $ 191 $ 194 $ 201 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (9 ) $ (10 ) $ (10 ) Postretirement Benefit Obligation $ (160 ) $ (160 ) $ (165 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2016 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 93% and 7% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 107 $ 105 $ 2 $ — Equities (B) Common Stock 944 944 — — Commingled (C) 1,387 1,247 140 — Preferred Stock 1 1 — — Bonds (D) US Treasury 441 — 441 — Government—Other 263 — 263 — Corporate 836 — 836 — Subtotal Fair Value $ 3,979 $ 2,297 $ 1,682 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,604 Private Equity (E) 16 Total Fair Value (F) $ 5,599 Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 96 $ 95 $ 1 $ — Equities (B) Common Stock 816 816 — — Commingled (C) 1,463 1,269 194 — Bonds (D) US Treasury 322 — 322 — Government—Other 279 — 279 — Corporate 906 — 906 — Subtotal Fair Value $ 3,882 $ 2,180 $ 1,702 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,504 Private Equity (E) 19 Total Fair Value (F) $ 5,405 (A) Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2. (C) In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. See Note 2. Recent Accounting Standards . These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015. (D) Fixed income securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. (E) Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. (F) Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015 , respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 70 % 70 % Fixed Income Securities 28 28 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.0% for 2016 and will be 7.8% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception, which was 9.3% . Plan Contributions PSEG plans to contribute $14 million into its OPEB plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2017 $ 310 $ 82 2018 307 86 2019 319 90 2020 331 94 2021 343 99 2022-2026 1,887 534 Total $ 3,497 $ 985 401(k) Plans PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution retirement plans. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2016 2015 2014 Millions PSE&G $ 24 $ 22 $ 20 Power 12 12 11 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 39 $ 36 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entities . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 211 $ 195 $ 375 $ 452 Service Cost 24 26 12 17 Interest Cost 9 9 17 21 Actuarial (Gain) Loss 14 (20 ) 50 (114 ) Gross Benefits Paid (1 ) — (2 ) (1 ) Plan Amendments 5 1 — — Benefit Obligation at End of Year (A) $ 262 $ 211 $ 452 $ 375 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 97 $ 69 $ — $ — Actual Return on Plan Assets 10 (2 ) — — Employer Contributions 28 30 2 1 Gross Benefits Paid (1 ) — (2 ) (1 ) Fair Value of Assets at End of Year $ 134 $ 97 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (128 ) $ (114 ) $ (452 ) $ (375 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (128 ) $ (114 ) N/A N/A OPEB Costs of Servco N/A N/A (452 ) (375 ) Amounts Recognized (B) $ (128 ) $ (114 ) $ (452 ) $ (375 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2016 , 2015 and 2014 were $28 million , $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2016 . The OPEB-related revenues earned and costs incurred in 2016 was $2 million , and were immaterial 2015 and 2014 . The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.61 % 4.92 % 4.50 % 4.71 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.55 % 7.33 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 97 $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (75 ) $ (60 ) $ (106 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 96 $ — $ 96 $ — Commingled Bonds (A) 38 — 38 — Total $ 134 $ — $ 134 $ — Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 68 $ — $ 68 $ — Commingled Bonds (A) 29 — 29 — Total $ 97 $ — $ 97 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as Level 2. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 71 % 71 % Fixed Income Securities 29 29 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.7% for 2016 and will be 7.6% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $35 million into its pension plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2017 $ 2 $ 4 2018 3 6 2019 5 9 2020 7 11 2021 8 13 2022-2026 76 96 Total $ 101 $ 139 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2016 , 2015 and 2014 were $5 million , $4 million and $3 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs. |
Power [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension, OPEB and Savings Plans | Pension, Other Postretirement Benefits (OPEB) and Savings Plans PSEG sponsors qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described below. PSEG, PSE&G and Power are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For underfunded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, GAAP requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses and prior service costs which had not been expensed. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. Effective January 1, 2016, PSEG changed the approach used to measure future service and interest costs for pension benefits. For 2015 and prior, PSEG calculated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016 and beyond, PSEG has elected to calculate service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. PSEG believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations. As a change in accounting estimate, this change was reflected prospectively. Pension and OPEB costs, net of amounts capitalized, were reduced by $34 million and $13 million , respectively, as compared to the 2016 amounts that would have been derived from applying PSEG’s 2015 and prior years’ methodology. As of December 31, 2016, PSEG merged its three qualified defined benefit pension plans (excluding Servco plans) into one plan, thereby also merging all of the pension plans’ assets. No changes were made to the benefit formulas, the vesting provisions, or to the employees covered by the plans. Amounts for Servco are not included in any of the following pension and OPEB benefit information for PSEG and its affiliates but rather are separately disclosed later in this note. The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Service Cost 109 123 17 22 Interest Cost 202 234 59 67 Actuarial (Gain) Loss (B) 219 (289 ) 127 (45 ) Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Plan Amendments 2 — (4 ) — Benefit Obligation at End of Year (A) $ 5,772 $ 5,522 $ 1,754 $ 1,612 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,039 $ 5,293 $ 374 $ 361 Actual Return on Plan Assets 403 (11 ) 32 (1 ) Employer Contributions 33 25 71 84 Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Fair Value of Assets at End of Year $ 5,193 $ 5,039 $ 420 $ 374 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ — $ 14 $ — $ — Current Accrued Benefit Cost (11 ) (10 ) (10 ) (10 ) Noncurrent Accrued Benefit Cost (568 ) (487 ) (1,324 ) (1,228 ) Amounts Recognized $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (63 ) $ (83 ) $ (14 ) $ (25 ) Net Actuarial Loss 1,763 1,710 523 438 Total $ 1,700 $ 1,627 $ 509 $ 413 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Includes $ 679 million ($ 398 million , after-tax) and $ 658 million ($ 386 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2016 and 2015 , respectively. The pension benefits table above provides information relating to the funded status of the qualified, nonqualified pension and OPEB plans on an aggregate basis. As of December 31, 2016 , PSEG had funded approximately 90% of its projected benefit obligation. This percentage does not include $ 217 million of assets in the Rabbi Trust as of December 31, 2016 which were used partially to fund the nonqualified pension plans. As of December 31, 2016 , the nonqualified pension plans included in the projected benefit obligation in the above table were $161 million . The fair values of the Rabbi Trust assets are included in Other Special Funds on the Consolidated Balance Sheets. Accumulated Benefit Obligation The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $ 5.6 billion as of December 31, 2016 and $ 5.4 billion as of December 31, 2015 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 109 $ 123 $ 104 $ 17 $ 22 18 Interest Cost 202 234 234 59 67 69 Expected Return on Plan Assets (394 ) (414 ) (399 ) (31 ) (31 ) (26 ) Amortization of Net Prior Service Credit (19 ) (19 ) (18 ) (14 ) (14 ) (14 ) Actuarial Loss 158 150 56 40 43 23 Net Periodic Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions PSE&G $ 29 $ 40 $ (19 ) $ 43 $ 55 $ 46 Power 16 21 (7 ) 23 27 20 Other 11 13 3 5 5 4 Total Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2016 2015 2016 2015 Millions Net Actuarial (Gain) Loss in Current Period $ 211 $ 136 $ 125 $ (14 ) Amortization of Net Actuarial Gain (Loss) (158 ) (150 ) (40 ) (43 ) Prior Service Cost (Credit) in current period 1 — (3 ) — Amortization of Prior Service Credit 19 19 14 14 Total $ 73 $ 5 $ 96 $ (43 ) Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2017 are as follows: Pension Benefits Other Benefits 2017 2017 Millions Actuarial (Gain) Loss $ 97 $ 51 Prior Service Cost $ (18 ) $ (11 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.29 % 4.54 % 4.20 % 4.37 % 4.58 % 4.21 % Rate of Compensation Increase 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Service Cost Interest Rate 4.81 % 4.20 % 5.00 % 4.87 % 4.21 % 5.01 % Interest Cost Interest Rate 3.75 % 4.20 % 5.00 % 3.76 % 4.21 % 5.01 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 3.00 % 3.00 % 3.00 % Health Care Costs Immediate Rate 7.55 % 7.75 % 7.40 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2022 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 11 $ 12 $ 13 Postretirement Benefit Obligation $ 191 $ 194 $ 201 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (9 ) $ (10 ) $ (10 ) Postretirement Benefit Obligation $ (160 ) $ (160 ) $ (165 ) Plan Assets The investments of pension and OPEB plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of the plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. As of December 31, 2016 , the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 93% and 7% , respectively. The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 107 $ 105 $ 2 $ — Equities (B) Common Stock 944 944 — — Commingled (C) 1,387 1,247 140 — Preferred Stock 1 1 — — Bonds (D) US Treasury 441 — 441 — Government—Other 263 — 263 — Corporate 836 — 836 — Subtotal Fair Value $ 3,979 $ 2,297 $ 1,682 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,604 Private Equity (E) 16 Total Fair Value (F) $ 5,599 Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 96 $ 95 $ 1 $ — Equities (B) Common Stock 816 816 — — Commingled (C) 1,463 1,269 194 — Bonds (D) US Treasury 322 — 322 — Government—Other 279 — 279 — Corporate 906 — 906 — Subtotal Fair Value $ 3,882 $ 2,180 $ 1,702 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,504 Private Equity (E) 19 Total Fair Value (F) $ 5,405 (A) Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2. (C) In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. See Note 2. Recent Accounting Standards . These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015. (D) Fixed income securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. (E) Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. (F) Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015 , respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 70 % 70 % Fixed Income Securities 28 28 Other Investments 2 2 Total Percentage 100 % 100 % PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. PSEG’s latest asset/liability study indicates that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to adjust the fixed income duration of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.0% for 2016 and will be 7.8% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management and considered the plans’ historical annualized rate of return since inception, which was 9.3% . Plan Contributions PSEG plans to contribute $14 million into its OPEB plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2017 $ 310 $ 82 2018 307 86 2019 319 90 2020 331 94 2021 343 99 2022-2026 1,887 534 Total $ 3,497 $ 985 401(k) Plans PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution retirement plans. Eligible represented employees of PSEG’s subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG’s subsidiaries participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans, not to exceed the IRS maximums, including any catch-up contributions for those employees age 50 and above. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants. The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2016 2015 2014 Millions PSE&G $ 24 $ 22 $ 20 Power 12 12 11 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 39 $ 36 Servco Pension and OPEB At the direction of LIPA, effective January 1, 2014, Servco established benefit plans that provide substantially the same benefits to its employees as those previously provided by National Grid Electric Services LLC (NGES), the predecessor T&D system manager for LIPA. Since the vast majority of Servco’s employees had worked under NGES’ T&D operations services arrangement with LIPA, Servco’s plans provide certain of those employees with pension and OPEB vested credit for prior years’ services earned while working for NGES. The benefit plans cover all employees of Servco for current service. Under the OSA, all of these and any future employee benefit costs are to be funded by LIPA. See Note 4. Variable Interest Entities . These obligations, as well as the offsetting long-term receivable, are separately presented on the Consolidated Balance Sheet of PSEG. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 211 $ 195 $ 375 $ 452 Service Cost 24 26 12 17 Interest Cost 9 9 17 21 Actuarial (Gain) Loss 14 (20 ) 50 (114 ) Gross Benefits Paid (1 ) — (2 ) (1 ) Plan Amendments 5 1 — — Benefit Obligation at End of Year (A) $ 262 $ 211 $ 452 $ 375 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 97 $ 69 $ — $ — Actual Return on Plan Assets 10 (2 ) — — Employer Contributions 28 30 2 1 Gross Benefits Paid (1 ) — (2 ) (1 ) Fair Value of Assets at End of Year $ 134 $ 97 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (128 ) $ (114 ) $ (452 ) $ (375 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (128 ) $ (114 ) N/A N/A OPEB Costs of Servco N/A N/A (452 ) (375 ) Amounts Recognized (B) $ (128 ) $ (114 ) $ (452 ) $ (375 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. Pension and OPEB costs of Servco are accounted for according to the OSA. Servco recognizes expenses for contributions to its pension plan trusts and for OPEB payments made to retirees. Operating Revenues are recognized for the reimbursement of these costs. The pension-related revenues and costs for 2016 , 2015 and 2014 were $28 million , $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2016 . The OPEB-related revenues earned and costs incurred in 2016 was $2 million , and were immaterial 2015 and 2014 . The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.61 % 4.92 % 4.50 % 4.71 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.55 % 7.33 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 97 $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (75 ) $ (60 ) $ (106 ) Plan Assets All the investments of Servco’s pension plans are held in a trust account by the Trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. The Actuary maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Actuary to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating plans. The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 96 $ — $ 96 $ — Commingled Bonds (A) 38 — 38 — Total $ 134 $ — $ 134 $ — Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 68 $ — $ 68 $ — Commingled Bonds (A) 29 — 29 — Total $ 97 $ — $ 97 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as Level 2. The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 71 % 71 % Fixed Income Securities 29 29 Total Percentage 100 % 100 % Servco utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. The results from Servco’s latest asset/liability study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. The expected long-term rate of return on plan assets was 7.7% for 2016 and will be 7.6% for 2017 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $35 million into its pension plan during 2017 . Estimated Future Benefit Payments The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2017 $ 2 $ 4 2018 3 6 2019 5 9 2020 7 11 2021 8 13 2022-2026 76 96 Total $ 101 $ 139 Servco 401(k) Plans Servco sponsors two 401(k) plans, which are defined contribution retirement plans subject to ERISA. Eligible non-represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan I (Thrift Plan I), and eligible represented employees of Servco participate in the Long Island Electric Utility Servco LLC Incentive Thrift Plan II (Thrift Plan II). Participants in the Plans may contribute up to 50% of their eligible compensation to these plans, not to exceed the IRS maximums, including any Catch-Up Contributions for those employees age 50 and above. Servco does not provide an employer match or core contribution for employees in Thrift Plan II. For employees in Thrift Plan I, Servco matches 50% of such employee contributions up to 8% of eligible compensation and provides core contributions (based on years of service and age) to employees who do not participate in Servco’s Retirement Income Plan. The amounts expensed by Servco for employer matching contributions for the years ended December 31, 2016 , 2015 and 2014 were $5 million , $4 million and $3 million , respectively, and pursuant to the OSA, Servco recognizes Operating Revenues for the reimbursement of these costs. |
Commitments and Contingent Liab
Commitments and Contingent Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Other Commitments [Line Items] | |
Commitments and Contingent Liabilities | Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2016 and 2015 . As of December 31, 2016 As of December 31, 2015 Millions Face Value of Outstanding Guarantees $ 1,806 $ 1,734 Exposure under Current Guarantees $ 139 $ 172 Letters of Credit Margin Posted $ 157 $ 122 Letters of Credit Margin Received $ 99 $ 192 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (1 ) $ (15 ) Net Broker Balance Deposited (Received) $ 57 $ (5 ) Additional Amounts Posted Other Letters of Credit $ 51 $ 51 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA. The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million . Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G. In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million . Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent . The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal. On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17 -mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River. The CPG, which consisted of 52 members as of December 31, 2016 , provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million , which the CPG continues to incur. Of the estimated $190 million , as of December 31, 2016 , the CPG had spent approximately $158 million , of which PSEG’s total share was approximately $11 million . The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million . Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015. In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of December 31, 2016 , these accruals bring the total liability to approximately $57 million , $46 million applicable to PSE&G and $11 million applicable to Power. Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.” On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $403 million and $460 million through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $403 million as of December 31, 2016 . Of this amount, $81 million was recorded in Other Current Liabilities and $322 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $403 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred. In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter. Clean Water Act Permit Renewals Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by mid-2017. In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements . Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained except for the New Source air permit that is currently in draft form for public comment. Operations are expected to begin in mid-2019. Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter. Jersey City, New Jersey Subsurface Feeder Cable Matter In early October 2016, a discharge of mineral oil dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations. Coal Combustion Residuals (CCRs) On December 19, 2014, the EPA issued a final rule that regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2017 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2017 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2014 2015 2016 2017 36-Month Terms Ending May 2017 May 2018 May 2019 May 2020 (A) Load (MW) 2,800 2,900 2,800 2,800 $ per MWh $97.39 $99.54 $96.38 $90.78 (A) Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 24. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estima |
PSE&G [Member] | |
Other Commitments [Line Items] | |
Commitments and Contingent Liabilities | Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2016 and 2015 . As of December 31, 2016 As of December 31, 2015 Millions Face Value of Outstanding Guarantees $ 1,806 $ 1,734 Exposure under Current Guarantees $ 139 $ 172 Letters of Credit Margin Posted $ 157 $ 122 Letters of Credit Margin Received $ 99 $ 192 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (1 ) $ (15 ) Net Broker Balance Deposited (Received) $ 57 $ (5 ) Additional Amounts Posted Other Letters of Credit $ 51 $ 51 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA. The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million . Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G. In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million . Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent . The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal. On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17 -mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River. The CPG, which consisted of 52 members as of December 31, 2016 , provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million , which the CPG continues to incur. Of the estimated $190 million , as of December 31, 2016 , the CPG had spent approximately $158 million , of which PSEG’s total share was approximately $11 million . The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million . Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015. In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of December 31, 2016 , these accruals bring the total liability to approximately $57 million , $46 million applicable to PSE&G and $11 million applicable to Power. Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.” On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $403 million and $460 million through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $403 million as of December 31, 2016 . Of this amount, $81 million was recorded in Other Current Liabilities and $322 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $403 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred. In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter. Clean Water Act Permit Renewals Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by mid-2017. In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements . Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained except for the New Source air permit that is currently in draft form for public comment. Operations are expected to begin in mid-2019. Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter. Jersey City, New Jersey Subsurface Feeder Cable Matter In early October 2016, a discharge of mineral oil dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations. Coal Combustion Residuals (CCRs) On December 19, 2014, the EPA issued a final rule that regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2017 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2017 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2014 2015 2016 2017 36-Month Terms Ending May 2017 May 2018 May 2019 May 2020 (A) Load (MW) 2,800 2,900 2,800 2,800 $ per MWh $97.39 $99.54 $96.38 $90.78 (A) Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 24. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estima |
Power [Member] | |
Other Commitments [Line Items] | |
Commitments and Contingent Liabilities | Commitments and Contingent Liabilities Guaranteed Obligations Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees as a form of collateral. Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to • support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and • obtain credit. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to • fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and • the net position of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. Current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules. In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations. The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2016 and 2015 . As of December 31, 2016 As of December 31, 2015 Millions Face Value of Outstanding Guarantees $ 1,806 $ 1,734 Exposure under Current Guarantees $ 139 $ 172 Letters of Credit Margin Posted $ 157 $ 122 Letters of Credit Margin Received $ 99 $ 192 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (1 ) $ (15 ) Net Broker Balance Deposited (Received) $ 57 $ (5 ) Additional Amounts Posted Other Letters of Credit $ 51 $ 51 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. Financial Risk Management Activities for further discussion. In accordance with PSEG’s accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power had posted letters of credit to support Power’s various other non-energy contractual and environmental obligations. See preceding table. PSEG also issued a $106 million guarantee to support Power’s payment obligations related to its equity interest in the PennEast natural gas pipeline and a $21 million guarantee to support Power’s payment obligations related to construction of a 755 MW gas-fired combined cycle generating station in Maryland. In the event that PSEG were to be downgraded to below investment grade and failed to meet minimum net worth requirements, these guarantees would each have to be replaced by a letter of credit. Environmental Matters Passaic River Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex in violation of various statutes as discussed as follows. Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) In 2002, the U.S. Environmental Protection Agency (EPA) determined that a 17 -mile stretch of the lower Passaic River from Newark to Clifton, New Jersey is a “Superfund” site under CERCLA. This designation allows the EPA to clean up such sites and to compel responsible parties to perform cleanups or reimburse the government for cleanups led by the EPA. The EPA determined that there was a need to perform a comprehensive study of the entire 17 miles of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area of the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. In early 2007, 73 Potentially Responsible Parties (PRPs), including PSE&G and Power, formed a Cooperating Parties Group (CPG) and agreed to assume responsibility for conducting a Remedial Investigation and Feasibility Study (RI/FS) of the 17 miles of the lower Passaic River. At such time, the CPG also agreed to allocate, on an interim basis, the associated costs of the RI/FS among its members on the basis of a mutually agreed upon formula. For the purpose of this interim allocation, which has been revised as parties have exited the CPG, approximately seven percent of the RI/FS costs are currently deemed attributable to PSE&G’s former MGP sites and approximately one percent is attributable to Power’s generating stations. These interim allocations are not binding on PSE&G or Power in terms of their respective shares of the costs that will be ultimately required to remediate the 17 miles of the lower Passaic River. PSEG has provided notice to insurers concerning this potential claim. In June 2008, the EPA and Tierra Solutions, Inc. (Tierra) and Maxus Energy Corporation (Maxus) entered into an early action agreement whereby Tierra/Maxus agreed to remove a portion of the heavily dioxin-contaminated sediment located in the lower Passaic River. The portion of the Passaic River identified in this agreement was located immediately adjacent to Tierra/Maxus’ predecessor company’s (Diamond Shamrock) facility. Pursuant to the agreement between the EPA and Tierra/Maxus, the estimated cost for the work to remove the sediment in this location was $80 million . Phase I of the removal work has been completed. Pursuant to this agreement, Tierra/Maxus have reserved their rights to seek contribution for these removal costs from the other PRPs, including Power and PSE&G. In 2012, Tierra/Maxus withdrew from the CPG and refused to participate as members going forward, other than with respect to their obligation to fund the EPA’s portion of its RI/FS oversight costs. At such time, the remaining members of the CPG, in agreement with the EPA, commenced the removal of certain contaminated sediments at Passaic River Mile 10.9 at an estimated cost of $25 million to $30 million . Construction is complete. The CPG is awaiting EPA approval of the construction report, long-term monitoring plan and confirmatory sampling plan. PSE&G’s and Power’s combined share of the cost of that effort is approximately three percent . The remaining CPG members, PSE&G and Power included, have reserved their rights to seek reimbursement from Tierra/Maxus for the costs of the River Mile 10.9 removal. On April 11, 2014, the EPA released its revised draft “Focused Feasibility Study” (FFS) which contemplates the removal of 4.3 million cubic yards of sediment from the bottom of the lower eight miles of the 17 -mile stretch of the Passaic River. The revised draft FFS sets forth various alternatives for remediating this portion of the Passaic River. The CPG, which consisted of 52 members as of December 31, 2016 , provided a draft RI and draft FS, both relating to the entire 17 miles of the lower Passaic River, to the EPA on February 18, 2015 and April 30, 2015, respectively. The estimated total cost of the RI/FS is approximately $190 million , which the CPG continues to incur. Of the estimated $190 million , as of December 31, 2016 , the CPG had spent approximately $158 million , of which PSEG’s total share was approximately $11 million . The CPG’s draft FS set forth various alternatives for remediating the lower Passaic River. It set forth the CPG’s estimated costs to remediate the lower 17 miles of the Passaic River which range from approximately $518 million to $3.2 billion on an undiscounted basis. The CPG identified a targeted remedy in the draft FS which would involve removal, treatment and disposal of contaminated sediments taken from targeted locations within the entire 17 miles of the lower Passaic River. The estimated cost in the draft FS for the targeted remedy ranged from approximately $518 million to $772 million . Based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G’s and Power’s estimated share of those costs, and (iii) the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued a $10 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued a $3 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2015. In March 2016, the EPA released its Record of Decision (ROD) for the FFS which requires the removal of 3.5 million cubic yards of sediment from the Passaic River’s lower 8.3 miles at an estimated cost of $2.3 billion on an undiscounted basis (ROD Remedy). The ROD Remedy requires a bank-to-bank dredge ranging from approximately 5 to 30 feet deep in the federal navigation channel from River Mile 0 to River Mile 1.7 and an approximately 2.5 foot deep dredge everywhere else in the lower 8.3 miles of the river. An engineered cap approximately two feet thick will be placed over the dredged areas. Dredged sediments will be transported to facilities and landfills out-of-state. The EPA estimates the total project length to be about 11 years, including a one year period of negotiation with the PRPs, three to four years to design the project and six years for implementation. Based upon the estimated cost of the ROD Remedy, PSEG’s estimate of PSE&G’s and Power’s shares of that cost, and the continued ability of PSE&G to recover such costs in its rates, PSE&G accrued an additional $36 million Environmental Costs Liability and a corresponding Regulatory Asset and Power accrued an additional $8 million Other Noncurrent Liability and a corresponding O&M Expense in the first quarter of 2016. As of December 31, 2016 , these accruals bring the total liability to approximately $57 million , $46 million applicable to PSE&G and $11 million applicable to Power. Also in March 2016, the EPA sent a notice letter to 105 PRPs, including PSE&G, all other past and present members of the CPG, including Occidental Chemical Corporation (OCC), and the towns of Newark, Kearny and Harrison and the Passaic Valley Sewerage Commission stating that the EPA wants to determine whether OCC, a successor company to Diamond Shamrock, would voluntarily perform the remedial design for the ROD Remedy. On September 30, 2016, OCC and the EPA executed an Administrative Settlement Agreement and Order on Consent for Remedial Design under which OCC agreed to conduct the remedial design for the ROD. With OCC’s commitment to perform the remedial design, it is anticipated that the EPA will begin negotiation of a remedial action consent decree, under which OCC and the other “major PRPs” will implement and/or pay for the EPA’s ROD Remedy for the lower 8.3 miles. The EPA has not defined “major PRPs.” On June 16, 2016, Tierra and Maxus, successors to Diamond Shamrock, filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Although PSEG does not currently anticipate that the filing for bankruptcy by Tierra and Maxus will affect its allocable share or total liability for the Passaic River matter, PSEG, through the CPG and independently, will monitor the bankruptcy proceedings to identify any potential impact on PSEG’s share of the costs. The EPA has broad authority to implement its selected remedy through the ROD and PSEG cannot at this time predict how the implementation of the ROD might impact PSE&G’s and Power’s ultimate liability. Until (i) the RI/FS, which covers the entire 17 miles of the lower Passaic River, is finalized either in whole or in part, (ii) an agreement by the PRPs to perform either the ROD Remedy as issued, or an amended ROD Remedy determined through negotiation or litigation, and an agreed upon remedy for the remaining 8.7 miles of the river, are reached, (iii) PSE&G’s and Power’s respective shares of the costs, both in the aggregate as well as individually, are determined, and (iv) PSE&G’s continued ability to recover the costs in its rates is determined, it is not possible to predict this matter’s ultimate impact on PSEG’s financial statements. It is possible that PSE&G and Power will record additional costs beyond what they have accrued, and that such costs could be material, but PSEG cannot at the current time estimate the amount or range of any additional costs. Natural Resource Damage Claims In 2003, the New Jersey Department of Environmental Protection (NJDEP) directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million . In 2007, agencies of the U.S. Department of Commerce and the U.S. Department of the Interior (the Passaic River federal trustees) sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but PSEG has not consented to fund the third phase. PSE&G and Power are unable to estimate their respective portions of the possible loss or range of loss related to this matter. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $403 million and $460 million through 2021, including its $46 million share for the Passaic River as discussed above. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $403 million as of December 31, 2016 . Of this amount, $81 million was recorded in Other Current Liabilities and $322 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $403 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly. NJDEP, PSEG and EPA representatives have had discussions regarding whether sampling in the Passaic River is required to delineate coal tar from MGP sites that abut the Passaic River Superfund site. PSEG cannot determine at this time whether this will have an impact on the Passaic River Superfund remedy. Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred. In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent the PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter. Clean Water Act Permit Renewals Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The NJDEP manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs. In May 2014, the EPA issued a final rule that establishes new requirements for the regulation of cooling water intake structures at existing power plants and industrial facilities with a design flow of more than two million gallons of water per day. The EPA has structured the rule so that each state Permitting Director will continue to consider renewal permits for existing power facilities on a case by case basis. In connection with the assessment of the best technology available for minimizing adverse environmental impacts of each facility that seeks a permit renewal, the rule requires that facilities conduct a wide range of studies related to impingement mortality and entrainment and submit the results with their permit applications. In September 2014, several environmental non-governmental groups and certain energy industry groups filed petitions for review of the rule and the case has been assigned to the U.S. Second Circuit Court of Appeals (Second Circuit). Environmental organizations, including but not limited to the environmental petitioners in the Second Circuit, have also filed suit under the Endangered Species Act. The cases were subsequently consolidated at the Second Circuit and a decision is expected by mid-2017. In June 2016, the NJDEP issued a final NJPDES permit for Salem with an effective date of August 1, 2016. The final permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The final permit does not mandate specific service water system modifications, but consistent with Section 316 (b) of the Clean Water Act, it requires additional studies and the selection of technology to address impingement for the service water system. In July 2016, the Delaware Riverkeeper Network (Riverkeeper) filed a request challenging the NJDEP’s issuance of the final permit for Salem. The Riverkeeper’s filing does not change the effective date of the permit. If the Riverkeeper’s challenge were successful, Power may be required to incur additional costs to comply with the Clean Water Act. Such service water system modification costs could be material and could adversely impact the economic competitiveness of this facility. State permitting decisions at Bridgeport and possibly New Haven could also have a material impact on Power’s ability to renew permits at its existing larger once-through cooled plants without making significant upgrades to existing intake structures and cooling systems. Power is unable to predict the outcome of these permitting decisions and the effect, if any, that they may have on Power’s future capital requirements, financial condition or results of operations. Power is actively engaged with the Connecticut Department of Energy and Environmental Protection (CTDEEP) regarding renewal of the current permit for the cooling water intake structure at Bridgeport Harbor Station Unit 3 (BH3). To address compliance with the EPA’s Clean Water Act Section 316(b) final rule, the current proposal under consideration is that, if a final permit is issued, Power would continue to operate BH3 without making the capital expenditures for modification to the existing intake structure and retire BH3 in 2021, which is four years earlier than the previously estimated useful life ending in 2025. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in 2017. See Note 3. Early Plant Retirements . Separately, Power has also negotiated a Community Environmental Benefit Agreement (CEBA) with the City of Bridgeport, Connecticut. That CEBA provides that Power would retire BH3 early if all its precedent conditions occur, which include receipt of all final permits to build and operate a proposed new combined cycle generating facility on the same site that BH3 currently operates. The receipt of permits to allow construction and operation of the new facility could occur in 2017. Absent those conditions being met, and the permit for the cooling water intake structure referred to above not being issued, Power may seek to operate BH3 through the previously estimated useful life. In February 2016, the proposed new generating facility at Bridgeport Harbor was awarded a capacity obligation. The Connecticut Siting Council issued an order to approve siting BH5. All major environmental permits have been obtained except for the New Source air permit that is currently in draft form for public comment. Operations are expected to begin in mid-2019. Bridgeport Harbor National Pollutant Discharge Elimination System (NPDES) Permit Compliance In April 2015, Power determined that monitoring and reporting practices related to certain permitted wastewater discharges at its Bridgeport Harbor station may have violated conditions of the station’s NPDES permit and applicable regulations and could subject it to fines and penalties. Power has notified the CTDEEP of the issues and has taken actions to investigate and resolve the potential non-compliance. Power cannot predict the impact of this matter. Jersey City, New Jersey Subsurface Feeder Cable Matter In early October 2016, a discharge of mineral oil dielectric fluid from subsurface feeder cables located in the Hudson River near Jersey City, New Jersey, was identified and reported to the NJDEP. The feeder cables are located within a subsurface easement granted to PSE&G by the property owners, Newport Associates Development Company (NADC) and Newport Associates Phase I Developer Limited Partnership. The feeder cables are subject to agreements between PSE&G and Consolidated Edison Company of New York, Inc. (Con Edison) and are jointly owned by PSE&G and Con Edison, with PSE&G owning the portion of the cables located in New Jersey and Con Edison owning the portion of the cables located in New York. The NJDEP has declared an emergency and an emergency response action has been undertaken to investigate, contain, remediate and stop the fluid discharge; to assess, repair and restore the cables to good working order; and to restore the property. The regulatory agencies overseeing the emergency response, including the U.S. Coast Guard, the NJDEP and the Army Corps of Engineers, have issued multiple notices, orders and directives to the various parties related to this matter. The investigation and response actions related to the fluid discharge are ongoing. The investigation of the discharge and its potential cause is in the preliminary stages, making it difficult to determine the timing and potential costs to resolve this matter, as well as responsibility for such costs between PSE&G, Con Edison and NADC. Based on currently available information and the potential scope of the necessary repair and remediation work, the costs will likely be material. In addition, the timeline for completing the repairs has been extended due to the presence of debris within PSE&G’s easement. In November 2016, PSE&G filed an action in New Jersey Federal Court seeking an order requiring NADC to remove its debris from PSE&G’s easement so that PSE&G and Con Edison may comply with NJDEP and U.S. Coast Guard directives and complete the necessary repairs. NADC subsequently informed PSE&G that it would comply with the U.S. Coast Guard’s order and undertake debris removal activities so that PSE&G and Con Edison can complete the necessary repairs. NADC’s debris removal activities are ongoing. Steam Electric Effluent Guidelines In September 2015, the EPA issued a new Effluent Guidelines Limitation Rule for steam electric generating units. The rule establishes new best available technology economically achievable (BAT) standards for fly ash transport water, bottom ash transport water, flue gas desulfurization and flue gas mercury control wastewater. The EPA provides an implementation period for currently existing discharges of three years or up to eight years if a facility needs more time to implement equipment upgrades and provide supporting information to its permitting authority. In the intervening time period, existing discharge standards continue to apply. Power’s Bridgeport Harbor station and the jointly-owned Keystone and Conemaugh stations, have bottom ash transport water discharges that are regulated under this rule. Power is unable to predict if this rule will have a material impact on its future capital requirements, financial condition and results of operations. Coal Combustion Residuals (CCRs) On December 19, 2014, the EPA issued a final rule that regulates CCRs as non-hazardous and requires that facility owners implement a series of actions to close or upgrade existing CCR surface impoundments and/or landfills. It also establishes new provisions for the construction of new surface impoundments and landfills. Power’s Hudson and Mercer generating stations, along with its co-owned Keystone and Conemaugh stations, are subject to the provisions of this rule. On April 17, 2015, the final rule was published with an effective date of October 19, 2015. Accordingly in June 2015, Power recorded an additional asset retirement obligation to comply with the final CCR rule which was not material to Power’s results of operations, financial condition or cash flows. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for two categories of customers who choose not to purchase electric supply from third-party suppliers. The first category, which represents about 80% of PSE&G’s load requirement, is residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category is larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial Energy Pricing (CIEP)). Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with winning BGS suppliers, including Power, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. The BGS-CIEP auction is for a one-year supply period from June 1 to May 31 with the BGS-CIEP auction price measured in dollars per MW-day for capacity. The final price for the BGS-CIEP auction year commencing June 1, 2017 is $276.83 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2017 of $335.33 per MW-day. Energy for BGS-CIEP is priced at hourly PJM locational marginal prices for the contract period. PSE&G contracts for its anticipated BGS-RSCP load on a three-year rolling basis, whereby each year one-third of the load is procured for a three-year period. The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2014 2015 2016 2017 36-Month Terms Ending May 2017 May 2018 May 2019 May 2020 (A) Load (MW) 2,800 2,900 2,800 2,800 $ per MWh $97.39 $99.54 $96.38 $90.78 (A) Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire. Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. PSE&G has a full-requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 24. Related-Party Transactions . Minimum Fuel Purchase Requirements Power’s nuclear fuel strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estima |
Schedule Of Consolidated Debt
Schedule Of Consolidated Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Instrument [Line Items] | |
Schedule Of Consolidated Debt | Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2016 2015 Millions PSEG Term Loan: Variable 2017 $ 500 $ 500 Total Term Loan 500 500 Senior Notes: 1.60% 2019 400 — 2.00% 2021 300 — Total Senior Notes 700 — Principal Amount Outstanding 1,200 500 Fair Value of Swaps (A) — 6 Amounts Due Within One Year (500 ) (6 ) Net Unamortized Discount and Debt Issuance Costs (5 ) — Total Long-Term Debt of PSEG $ 695 $ 500 ` As of December 31, Maturity 2016 2015 Millions PSE&G First and Refunding Mortgage Bonds (B): 6.75% 2016 $ — $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 320 Pollution Control Bonds (B): Floating Rate (C) 2033 — 50 Floating Rate (C) 2046 — 50 Total Pollution Control Bonds — 100 Medium-Term Notes (MTNs) (B): 5.30% 2018 400 400 2.30% 2018 350 350 1.80% 2019 250 250 2.00% 2019 250 250 7.04% 2020 9 9 3.50% 2020 250 250 1.90% 2021 300 — 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 — Total MTNs 7,734 6,459 Principal Amount Outstanding 7,883 6,879 Amounts Due Within One Year — (171 ) Net Unamortized Discount and Debt Issuance Costs (65 ) (58 ) Total Long-Term Debt of PSE&G $ 7,818 $ 6,650 As of December 31, Maturity 2016 2015 Millions Power Senior Notes: 5.32% 2016 $ — $ 303 2.75% 2016 — 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 3.00% 2021 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,356 2,209 Pollution Control Notes: Floating Rate (C) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,400 2,253 Amounts Due Within One Year — (553 ) Net Unamortized Discount and Debt Issuance Costs (18 ) (16 ) Total Long-Term Debt of Power $ 2,382 $ 1,684 (A) PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities . (B) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (C) The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2016 are as Year PSEG PSE&G Power Total 2017 $ 500 $ — $ — $ 500 2018 — 750 250 1,000 2019 400 500 44 944 2020 — 259 406 665 2021 300 434 950 1,684 Thereafter — 5,940 750 6,690 Total $ 1,200 $ 7,883 $ 2,400 $ 11,483 Long-Term Debt Financing Transactions During 2016 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • issued $400 million of 1.60% Senior Notes due November 2019 , and • issued $300 million of 2.00% Senior Notes due November 2021 PSE&G • issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021 , • issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046 , • issued $425 million of 2.25% Secured Medium-Term Notes, Series L due September 2026 , • retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds Series VV at maturity, and • repurchased at par $100 million of Salem Bonds and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds. Power • issued $700 million of 3.00% Senior Notes due June 2021 , • retired $303 million of 5.32% Senior Notes due September 2016 , and • retired $250 million of 2.75% Senior Notes due September 2016 . Short-Term Liquidity PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2016 , the total available credit capacity was $3.5 billion . As of December 31, 2016 , no single institution represented more than 7% of the total commitments in the credit facilities. As of December 31, 2016 , the total credit capacity was in excess of the anticipated maximum liquidity requirements. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2016 were as follows: As of December 31, 2016 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Mar 2019 Commercial Paper Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 388 112 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 398 $ 602 PSE&G 5-year Credit Facility (B) $ 600 $ 14 $ 586 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 14 $ 586 Power 5-year Credit Facility $ 1,600 $ 195 $ 1,405 Mar 2019 Funding/Letters of Credit 5-year Credit Facility (C) 953 3 950 Apr 2020 Funding/Letters of Credit Total Power $ 2,553 $ 198 $ 2,355 Total $ 4,153 $ 610 $ 3,543 (A) PSEG facility will be reduced by $12 million in March 2018. (B) PSE&G facility will be reduced by $14 million in March 2018. (C) Power facility will be reduced by $24 million in March 2018. (D) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2016 , PSEG had $388 million outstanding at a weighted average interest rate of 1.03% . PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2016 and 2015 are included in the following table and accompanying notes as of December 31, 2016 and 2015 . See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 1,195 $ 1,185 $ 503 $ 506 PSE&G (B) 7,818 8,240 6,821 7,235 Power - Recourse Debt (B) 2,382 2,578 2,237 2,508 Energy Holdings: Project Level, Non-Recourse Debt (C) — — 7 7 $ 11,395 $ 12,003 $ 9,568 $ 10,256 (A) Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. (B) Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. (C) Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
PSE&G [Member] | |
Debt Instrument [Line Items] | |
Schedule Of Consolidated Debt | Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2016 2015 Millions PSEG Term Loan: Variable 2017 $ 500 $ 500 Total Term Loan 500 500 Senior Notes: 1.60% 2019 400 — 2.00% 2021 300 — Total Senior Notes 700 — Principal Amount Outstanding 1,200 500 Fair Value of Swaps (A) — 6 Amounts Due Within One Year (500 ) (6 ) Net Unamortized Discount and Debt Issuance Costs (5 ) — Total Long-Term Debt of PSEG $ 695 $ 500 ` As of December 31, Maturity 2016 2015 Millions PSE&G First and Refunding Mortgage Bonds (B): 6.75% 2016 $ — $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 320 Pollution Control Bonds (B): Floating Rate (C) 2033 — 50 Floating Rate (C) 2046 — 50 Total Pollution Control Bonds — 100 Medium-Term Notes (MTNs) (B): 5.30% 2018 400 400 2.30% 2018 350 350 1.80% 2019 250 250 2.00% 2019 250 250 7.04% 2020 9 9 3.50% 2020 250 250 1.90% 2021 300 — 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 — Total MTNs 7,734 6,459 Principal Amount Outstanding 7,883 6,879 Amounts Due Within One Year — (171 ) Net Unamortized Discount and Debt Issuance Costs (65 ) (58 ) Total Long-Term Debt of PSE&G $ 7,818 $ 6,650 As of December 31, Maturity 2016 2015 Millions Power Senior Notes: 5.32% 2016 $ — $ 303 2.75% 2016 — 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 3.00% 2021 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,356 2,209 Pollution Control Notes: Floating Rate (C) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,400 2,253 Amounts Due Within One Year — (553 ) Net Unamortized Discount and Debt Issuance Costs (18 ) (16 ) Total Long-Term Debt of Power $ 2,382 $ 1,684 (A) PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities . (B) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (C) The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2016 are as Year PSEG PSE&G Power Total 2017 $ 500 $ — $ — $ 500 2018 — 750 250 1,000 2019 400 500 44 944 2020 — 259 406 665 2021 300 434 950 1,684 Thereafter — 5,940 750 6,690 Total $ 1,200 $ 7,883 $ 2,400 $ 11,483 Long-Term Debt Financing Transactions During 2016 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • issued $400 million of 1.60% Senior Notes due November 2019 , and • issued $300 million of 2.00% Senior Notes due November 2021 PSE&G • issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021 , • issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046 , • issued $425 million of 2.25% Secured Medium-Term Notes, Series L due September 2026 , • retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds Series VV at maturity, and • repurchased at par $100 million of Salem Bonds and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds. Power • issued $700 million of 3.00% Senior Notes due June 2021 , • retired $303 million of 5.32% Senior Notes due September 2016 , and • retired $250 million of 2.75% Senior Notes due September 2016 . Short-Term Liquidity PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2016 , the total available credit capacity was $3.5 billion . As of December 31, 2016 , no single institution represented more than 7% of the total commitments in the credit facilities. As of December 31, 2016 , the total credit capacity was in excess of the anticipated maximum liquidity requirements. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2016 were as follows: As of December 31, 2016 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Mar 2019 Commercial Paper Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 388 112 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 398 $ 602 PSE&G 5-year Credit Facility (B) $ 600 $ 14 $ 586 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 14 $ 586 Power 5-year Credit Facility $ 1,600 $ 195 $ 1,405 Mar 2019 Funding/Letters of Credit 5-year Credit Facility (C) 953 3 950 Apr 2020 Funding/Letters of Credit Total Power $ 2,553 $ 198 $ 2,355 Total $ 4,153 $ 610 $ 3,543 (A) PSEG facility will be reduced by $12 million in March 2018. (B) PSE&G facility will be reduced by $14 million in March 2018. (C) Power facility will be reduced by $24 million in March 2018. (D) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2016 , PSEG had $388 million outstanding at a weighted average interest rate of 1.03% . PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2016 and 2015 are included in the following table and accompanying notes as of December 31, 2016 and 2015 . See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 1,195 $ 1,185 $ 503 $ 506 PSE&G (B) 7,818 8,240 6,821 7,235 Power - Recourse Debt (B) 2,382 2,578 2,237 2,508 Energy Holdings: Project Level, Non-Recourse Debt (C) — — 7 7 $ 11,395 $ 12,003 $ 9,568 $ 10,256 (A) Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. (B) Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. (C) Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Power [Member] | |
Debt Instrument [Line Items] | |
Schedule Of Consolidated Debt | Debt and Credit Facilities Long-Term Debt As of December 31, Maturity 2016 2015 Millions PSEG Term Loan: Variable 2017 $ 500 $ 500 Total Term Loan 500 500 Senior Notes: 1.60% 2019 400 — 2.00% 2021 300 — Total Senior Notes 700 — Principal Amount Outstanding 1,200 500 Fair Value of Swaps (A) — 6 Amounts Due Within One Year (500 ) (6 ) Net Unamortized Discount and Debt Issuance Costs (5 ) — Total Long-Term Debt of PSEG $ 695 $ 500 ` As of December 31, Maturity 2016 2015 Millions PSE&G First and Refunding Mortgage Bonds (B): 6.75% 2016 $ — $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 320 Pollution Control Bonds (B): Floating Rate (C) 2033 — 50 Floating Rate (C) 2046 — 50 Total Pollution Control Bonds — 100 Medium-Term Notes (MTNs) (B): 5.30% 2018 400 400 2.30% 2018 350 350 1.80% 2019 250 250 2.00% 2019 250 250 7.04% 2020 9 9 3.50% 2020 250 250 1.90% 2021 300 — 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 — Total MTNs 7,734 6,459 Principal Amount Outstanding 7,883 6,879 Amounts Due Within One Year — (171 ) Net Unamortized Discount and Debt Issuance Costs (65 ) (58 ) Total Long-Term Debt of PSE&G $ 7,818 $ 6,650 As of December 31, Maturity 2016 2015 Millions Power Senior Notes: 5.32% 2016 $ — $ 303 2.75% 2016 — 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 3.00% 2021 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,356 2,209 Pollution Control Notes: Floating Rate (C) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,400 2,253 Amounts Due Within One Year — (553 ) Net Unamortized Discount and Debt Issuance Costs (18 ) (16 ) Total Long-Term Debt of Power $ 2,382 $ 1,684 (A) PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities . (B) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (C) The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2016 are as Year PSEG PSE&G Power Total 2017 $ 500 $ — $ — $ 500 2018 — 750 250 1,000 2019 400 500 44 944 2020 — 259 406 665 2021 300 434 950 1,684 Thereafter — 5,940 750 6,690 Total $ 1,200 $ 7,883 $ 2,400 $ 11,483 Long-Term Debt Financing Transactions During 2016 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG • issued $400 million of 1.60% Senior Notes due November 2019 , and • issued $300 million of 2.00% Senior Notes due November 2021 PSE&G • issued $300 million of 1.90% Secured Medium-Term Notes, Series K due March 2021 , • issued $550 million of 3.80% Secured Medium-Term Notes, Series K due March 2046 , • issued $425 million of 2.25% Secured Medium-Term Notes, Series L due September 2026 , • retired $171 million of 6.75% Secured First and Refunding Mortgage Bonds Series VV at maturity, and • repurchased at par $100 million of Salem Bonds and retired a like aggregate principal amount of its First and Refunding Mortgage Bonds which serviced and secured the Salem Bonds. Power • issued $700 million of 3.00% Senior Notes due June 2021 , • retired $303 million of 5.32% Senior Notes due September 2016 , and • retired $250 million of 2.75% Senior Notes due September 2016 . Short-Term Liquidity PSEG meets its short-term liquidity requirements, as well as those of Power, primarily with cash and through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Each commercial paper program is fully back-stopped by its own separate credit facilities. The commitments under the $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2016 , the total available credit capacity was $3.5 billion . As of December 31, 2016 , no single institution represented more than 7% of the total commitments in the credit facilities. As of December 31, 2016 , the total credit capacity was in excess of the anticipated maximum liquidity requirements. Each of the credit facilities is restricted as to availability and use to the specific companies as listed in the following table; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. The total credit facilities and available liquidity as of December 31, 2016 were as follows: As of December 31, 2016 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Mar 2019 Commercial Paper Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 388 112 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 398 $ 602 PSE&G 5-year Credit Facility (B) $ 600 $ 14 $ 586 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 14 $ 586 Power 5-year Credit Facility $ 1,600 $ 195 $ 1,405 Mar 2019 Funding/Letters of Credit 5-year Credit Facility (C) 953 3 950 Apr 2020 Funding/Letters of Credit Total Power $ 2,553 $ 198 $ 2,355 Total $ 4,153 $ 610 $ 3,543 (A) PSEG facility will be reduced by $12 million in March 2018. (B) PSE&G facility will be reduced by $14 million in March 2018. (C) Power facility will be reduced by $24 million in March 2018. (D) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2016 , PSEG had $388 million outstanding at a weighted average interest rate of 1.03% . PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016 . Fair Value of Debt The estimated fair values, carrying amounts and methods used to determine fair value of long-term debt as of December 31, 2016 and 2015 are included in the following table and accompanying notes as of December 31, 2016 and 2015 . See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels. December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 1,195 $ 1,185 $ 503 $ 506 PSE&G (B) 7,818 8,240 6,821 7,235 Power - Recourse Debt (B) 2,382 2,578 2,237 2,508 Energy Holdings: Project Level, Non-Recourse Debt (C) — — 7 7 $ 11,395 $ 12,003 $ 9,568 $ 10,256 (A) Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. (B) Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. (C) Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Schedule Of Consolidated Capita
Schedule Of Consolidated Capital Stock | 12 Months Ended |
Dec. 31, 2016 | |
Class of Stock [Line Items] | |
Schedule of Consolidated Capital Stock | Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2016 2015 2016 2015 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 504,866,212 505,282,421 $ 4,219 $ 4,244 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2016 or 2015 . Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016 . As of December 31, 2016 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. |
PSE&G [Member] | |
Class of Stock [Line Items] | |
Schedule of Consolidated Capital Stock | Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2016 2015 2016 2015 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 504,866,212 505,282,421 $ 4,219 $ 4,244 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2016 or 2015 . Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016 . As of December 31, 2016 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. |
Power [Member] | |
Class of Stock [Line Items] | |
Schedule of Consolidated Capital Stock | Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2016 2015 2016 2015 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 504,866,212 505,282,421 $ 4,219 $ 4,244 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2016 or 2015 . Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016 . As of December 31, 2016 , PSE&G had an aggregate of 7.5 million shares of $100 par value and 10 million shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. |
Financial Risk Management Activ
Financial Risk Management Activities | 12 Months Ended |
Dec. 31, 2016 | |
Derivative [Line Items] | |
Financial Risk Management Activities | Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. Interest rate swaps totaling $550 million that converted Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter of 2016 . There were no outstanding interest rate swaps as of December 31, 2016 . As of December 31, 2015 , the fair value of all the underlying hedges was $6 million . The fair value hedges reduced interest expense by $6 million , $19 million and $20 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of December 31, 2016 , PSEG had interest rate hedges outstanding totaling $500 million . These hedges were executed during the first quarter of 2016 and convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. The fair value of these hedges was $1 million and there was no ineffectiveness as of December 31, 2016 . There were no outstanding interest rate hedges as of December 31, 2015 . PSEG executed forward starting swaps totaling $400 million during the first quarter of 2016 which were terminated upon the issuance of Power’s $700 million of 3.00% Senior Notes due June 2021. In the fourth quarter of 2016, PSEG executed $500 million of forward starting swaps which were terminated upon the issuance of PSEG’s $400 million of 1.6% Senior Notes due November 2019 and $300 million of 2.0% Senior Notes due November 2021. For additional information see Note 14. Debt and Credit Facilities . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of December 31, 2016 and immaterial as of December 31, 2015 . The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million . Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2016 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Cash Flow Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 435 $ (273 ) $ 162 $ — $ 1 $ 163 Noncurrent Assets 122 (98 ) 24 — — 24 Total Mark-to-Market Derivative Assets $ 557 $ (371 ) $ 186 $ — $ 1 $ 187 Derivative Contracts Current Liabilities $ (285 ) $ 277 $ (8 ) $ (5 ) $ — $ (13 ) Noncurrent Liabilities (98 ) 95 (3 ) — — (3 ) Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372 $ (11 ) $ (5 ) $ — $ (16 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174 $ 1 $ 175 $ (5 ) $ 1 $ 171 As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 700 $ (477 ) $ 223 $ 13 $ 6 $ 242 Noncurrent Assets 208 (131 ) 77 — — 77 Total Mark-to-Market Derivative Assets $ 908 $ (608 ) $ 300 $ 13 $ 6 $ 319 Derivative Contracts Current Liabilities $ (513 ) $ 437 $ (76 ) $ — $ — $ (76 ) Noncurrent Liabilities (132 ) 116 (16 ) (11 ) — (27 ) Total Mark-to-Market Derivative (Liabilities) $ (645 ) $ 553 $ (92 ) $ (11 ) $ — $ (103 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 263 $ (55 ) $ 208 $ 2 $ 6 $ 216 (A) Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (B) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2016 and 2015 , net cash collateral (received) paid of $1 million and $(55) million , respectively, were netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016 , $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015 , cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements. The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $19 million and $78 million as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 and 2015 , Power had the contractual right of offset of $9 million and $12 million , respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $10 million and $66 million as of December 31, 2016 and 2015 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2016 , 2015 and 2014 . Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Millions PSEG Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Interest Rate Swaps 3 — — Interest Expense — — — Total PSEG $ 3 $ 3 $ 12 $ — $ 20 $ (9 ) Power Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Total Power $ — $ 3 $ 12 $ — $ 20 $ (9 ) There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2016 , 2015 and 2014 . The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2014 $ 17 $ 10 Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income (20 ) (12 ) Balance as of December 31, 2015 $ — $ — Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income — — Balance as of December 31, 2016 $ 3 $ 2 The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2016 , 2015 and 2014 . Derivatives Not Designated as Hedges Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives Pre-Tax Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 230 $ 412 $ (348 ) Energy-Related Contracts Energy Costs (8 ) (8 ) 32 Total PSEG and Power $ 222 $ 404 $ (316 ) Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. The tables above do not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2016 and 2015 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2016 Natural Gas Dth 357 — 348 9 Electricity MWh 323 — 323 — Financial Transmission Rights (FTRs) MWh 9 — 9 — Interest Rate Swaps U.S. Dollars 500 500 — — As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — FTRs MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — Credit Risk Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows. As of December 31, 2016 , 93% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives). The following table provides information on Power’s credit risk from others, net of collateral, as of December 31, 2016 . It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties. Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 423 $ 94 $ 329 1 $ 219 (A) Non-Investment Grade 26 1 25 — — Total $ 449 $ 95 $ 354 1 $ 219 (A) Represents net exposure with PSE&G. As of December 31, 2016 , collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94 million in letters of credit. As of December 31, 2016 , Power had 149 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2016 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2016 , PSE&G had no net credit exposure with suppliers, including Power. PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. |
PSE&G [Member] | |
Derivative [Line Items] | |
Financial Risk Management Activities | Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. Interest rate swaps totaling $550 million that converted Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter of 2016 . There were no outstanding interest rate swaps as of December 31, 2016 . As of December 31, 2015 , the fair value of all the underlying hedges was $6 million . The fair value hedges reduced interest expense by $6 million , $19 million and $20 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of December 31, 2016 , PSEG had interest rate hedges outstanding totaling $500 million . These hedges were executed during the first quarter of 2016 and convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. The fair value of these hedges was $1 million and there was no ineffectiveness as of December 31, 2016 . There were no outstanding interest rate hedges as of December 31, 2015 . PSEG executed forward starting swaps totaling $400 million during the first quarter of 2016 which were terminated upon the issuance of Power’s $700 million of 3.00% Senior Notes due June 2021. In the fourth quarter of 2016, PSEG executed $500 million of forward starting swaps which were terminated upon the issuance of PSEG’s $400 million of 1.6% Senior Notes due November 2019 and $300 million of 2.0% Senior Notes due November 2021. For additional information see Note 14. Debt and Credit Facilities . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of December 31, 2016 and immaterial as of December 31, 2015 . The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million . Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2016 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Cash Flow Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 435 $ (273 ) $ 162 $ — $ 1 $ 163 Noncurrent Assets 122 (98 ) 24 — — 24 Total Mark-to-Market Derivative Assets $ 557 $ (371 ) $ 186 $ — $ 1 $ 187 Derivative Contracts Current Liabilities $ (285 ) $ 277 $ (8 ) $ (5 ) $ — $ (13 ) Noncurrent Liabilities (98 ) 95 (3 ) — — (3 ) Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372 $ (11 ) $ (5 ) $ — $ (16 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174 $ 1 $ 175 $ (5 ) $ 1 $ 171 As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 700 $ (477 ) $ 223 $ 13 $ 6 $ 242 Noncurrent Assets 208 (131 ) 77 — — 77 Total Mark-to-Market Derivative Assets $ 908 $ (608 ) $ 300 $ 13 $ 6 $ 319 Derivative Contracts Current Liabilities $ (513 ) $ 437 $ (76 ) $ — $ — $ (76 ) Noncurrent Liabilities (132 ) 116 (16 ) (11 ) — (27 ) Total Mark-to-Market Derivative (Liabilities) $ (645 ) $ 553 $ (92 ) $ (11 ) $ — $ (103 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 263 $ (55 ) $ 208 $ 2 $ 6 $ 216 (A) Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (B) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2016 and 2015 , net cash collateral (received) paid of $1 million and $(55) million , respectively, were netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016 , $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015 , cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements. The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $19 million and $78 million as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 and 2015 , Power had the contractual right of offset of $9 million and $12 million , respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $10 million and $66 million as of December 31, 2016 and 2015 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2016 , 2015 and 2014 . Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Millions PSEG Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Interest Rate Swaps 3 — — Interest Expense — — — Total PSEG $ 3 $ 3 $ 12 $ — $ 20 $ (9 ) Power Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Total Power $ — $ 3 $ 12 $ — $ 20 $ (9 ) There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2016 , 2015 and 2014 . The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2014 $ 17 $ 10 Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income (20 ) (12 ) Balance as of December 31, 2015 $ — $ — Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income — — Balance as of December 31, 2016 $ 3 $ 2 The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2016 , 2015 and 2014 . Derivatives Not Designated as Hedges Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives Pre-Tax Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 230 $ 412 $ (348 ) Energy-Related Contracts Energy Costs (8 ) (8 ) 32 Total PSEG and Power $ 222 $ 404 $ (316 ) Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. The tables above do not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2016 and 2015 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2016 Natural Gas Dth 357 — 348 9 Electricity MWh 323 — 323 — Financial Transmission Rights (FTRs) MWh 9 — 9 — Interest Rate Swaps U.S. Dollars 500 500 — — As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — FTRs MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — Credit Risk Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows. As of December 31, 2016 , 93% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives). The following table provides information on Power’s credit risk from others, net of collateral, as of December 31, 2016 . It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties. Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 423 $ 94 $ 329 1 $ 219 (A) Non-Investment Grade 26 1 25 — — Total $ 449 $ 95 $ 354 1 $ 219 (A) Represents net exposure with PSE&G. As of December 31, 2016 , collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94 million in letters of credit. As of December 31, 2016 , Power had 149 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2016 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2016 , PSE&G had no net credit exposure with suppliers, including Power. PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. |
Power [Member] | |
Derivative [Line Items] | |
Financial Risk Management Activities | Financial Risk Management Activities Derivative accounting guidance requires that a derivative instrument be recognized as either an asset or a liability at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation provided that the derivative instrument meets specific, restrictive criteria, both at the time of designation and on an ongoing basis. These alternative permissible treatments include NPNS, cash flow hedge and fair value hedge accounting. PSEG, Power and PSE&G have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and fuel agreements. PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow or fair value hedges. Power and PSE&G enter into additional contracts that are derivatives, but are not designated as either cash flow hedges or fair value hedges. These transactions are economic hedges and are recorded at fair market value. Commodity Prices Within PSEG and its affiliate companies, Power has the most exposure to commodity price risk. Power is exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities. Fluctuations in market prices result from changes in supply and demand, fuel costs, market conditions, weather, state and federal regulatory policies, environmental policies, transmission availability and other factors. Power uses a variety of derivative and non-derivative instruments, such as financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity, to manage the exposure to fluctuations in commodity prices and optimize the value of Power’s expected generation. Changes in the fair market value of the derivative contracts are recorded in earnings. Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt and interest rate swaps. Fair Value Hedges PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. The changes in fair value of the interest rate swaps are fully offset by changes in the fair value of the underlying forecasted interest payments of the debt. Interest rate swaps totaling $550 million that converted Power’s Senior Notes due September 2016 into variable-rate debt matured in the third quarter of 2016 . There were no outstanding interest rate swaps as of December 31, 2016 . As of December 31, 2015 , the fair value of all the underlying hedges was $6 million . The fair value hedges reduced interest expense by $6 million , $19 million and $20 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Cash Flow Hedges PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of December 31, 2016 , PSEG had interest rate hedges outstanding totaling $500 million . These hedges were executed during the first quarter of 2016 and convert PSEG’s $500 million variable rate term loan due November 2017 into a fixed rate loan. The fair value of these hedges was $1 million and there was no ineffectiveness as of December 31, 2016 . There were no outstanding interest rate hedges as of December 31, 2015 . PSEG executed forward starting swaps totaling $400 million during the first quarter of 2016 which were terminated upon the issuance of Power’s $700 million of 3.00% Senior Notes due June 2021. In the fourth quarter of 2016, PSEG executed $500 million of forward starting swaps which were terminated upon the issuance of PSEG’s $400 million of 1.6% Senior Notes due November 2019 and $300 million of 2.0% Senior Notes due November 2021. For additional information see Note 14. Debt and Credit Facilities . The Accumulated Other Comprehensive Income (Loss) (after tax) related to existing and terminated interest rate derivatives designated as cash flow hedges was $2 million as of December 31, 2016 and immaterial as of December 31, 2015 . The after-tax unrealized gains on these hedges expected to be reclassified to earnings during the next 12 months is $1 million . Fair Values of Derivative Instruments The following are the fair values of derivative instruments on the Consolidated Balance Sheets. The following tables also include disclosures for offsetting derivative assets and liabilities which are subject to a master netting or similar agreement. In general, the terms of the agreements provide that in the event of an early termination the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. Accordingly, and in accordance with PSEG’s accounting policy, these positions are offset on the Consolidated Balance Sheets of Power and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2016 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Cash Flow Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 435 $ (273 ) $ 162 $ — $ 1 $ 163 Noncurrent Assets 122 (98 ) 24 — — 24 Total Mark-to-Market Derivative Assets $ 557 $ (371 ) $ 186 $ — $ 1 $ 187 Derivative Contracts Current Liabilities $ (285 ) $ 277 $ (8 ) $ (5 ) $ — $ (13 ) Noncurrent Liabilities (98 ) 95 (3 ) — — (3 ) Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372 $ (11 ) $ (5 ) $ — $ (16 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174 $ 1 $ 175 $ (5 ) $ 1 $ 171 As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 700 $ (477 ) $ 223 $ 13 $ 6 $ 242 Noncurrent Assets 208 (131 ) 77 — — 77 Total Mark-to-Market Derivative Assets $ 908 $ (608 ) $ 300 $ 13 $ 6 $ 319 Derivative Contracts Current Liabilities $ (513 ) $ 437 $ (76 ) $ — $ — $ (76 ) Noncurrent Liabilities (132 ) 116 (16 ) (11 ) — (27 ) Total Mark-to-Market Derivative (Liabilities) $ (645 ) $ 553 $ (92 ) $ (11 ) $ — $ (103 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 263 $ (55 ) $ 208 $ 2 $ 6 $ 216 (A) Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (B) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2016 and 2015 , net cash collateral (received) paid of $1 million and $(55) million , respectively, were netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016 , $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015 , cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded to a below investment grade rating by S&P or Moody’s, it would be required to provide additional collateral. A below investment grade credit rating for Power would represent a three level downgrade from its current S&P or Moody’s ratings. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements. The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $19 million and $78 million as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 and 2015 , Power had the contractual right of offset of $9 million and $12 million , respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded to a below investment grade rating, it would have had additional collateral obligations of $10 million and $66 million as of December 31, 2016 and 2015 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2016 , 2015 and 2014 . Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Millions PSEG Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Interest Rate Swaps 3 — — Interest Expense — — — Total PSEG $ 3 $ 3 $ 12 $ — $ 20 $ (9 ) Power Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Total Power $ — $ 3 $ 12 $ — $ 20 $ (9 ) There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2016 , 2015 and 2014 . The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2014 $ 17 $ 10 Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income (20 ) (12 ) Balance as of December 31, 2015 $ — $ — Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income — — Balance as of December 31, 2016 $ 3 $ 2 The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2016 , 2015 and 2014 . Derivatives Not Designated as Hedges Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives Pre-Tax Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 230 $ 412 $ (348 ) Energy-Related Contracts Energy Costs (8 ) (8 ) 32 Total PSEG and Power $ 222 $ 404 $ (316 ) Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. The tables above do not include contracts for which Power has designated as NPNS, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2016 and 2015 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2016 Natural Gas Dth 357 — 348 9 Electricity MWh 323 — 323 — Financial Transmission Rights (FTRs) MWh 9 — 9 — Interest Rate Swaps U.S. Dollars 500 500 — — As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — FTRs MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — Credit Risk Credit risk relates to the risk of loss that Power would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows. As of December 31, 2016 , 93% of the net credit exposure for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives, NPNS and non-derivatives). The following table provides information on Power’s credit risk from others, net of collateral, as of December 31, 2016 . It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties. Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 423 $ 94 $ 329 1 $ 219 (A) Non-Investment Grade 26 1 25 — — Total $ 449 $ 95 $ 354 1 $ 219 (A) Represents net exposure with PSE&G. As of December 31, 2016 , collateral held from counterparties where Power had credit exposure included $1 million in cash collateral and $94 million in letters of credit. As of December 31, 2016 , Power had 149 active counterparties. PSE&G’s supplier master agreements are approved by the BPU and govern the terms of its electric supply procurement contracts. These agreements define a supplier’s performance assurance requirements and allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s credit ratings from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day the procurement transaction is executed, compared to the forward price curve for energy on the valuation day. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post a parental guaranty or other security instrument such as a letter of credit or cash, as collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. As of December 31, 2016 , primarily all of the posted collateral was in the form of parental guarantees. The unsecured credit used by the suppliers represents PSE&G’s net credit exposure. PSE&G’s BGS suppliers’ credit exposure is calculated each business day. As of December 31, 2016 , PSE&G had no net credit exposure with suppliers, including Power. PSE&G is permitted to recover its costs of procuring energy through the BPU-approved BGS tariffs. PSE&G’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Fair Value Measurements | Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2016 , these consisted primarily of gas supply contracts and certain electric load contracts. The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power. Recurring Fair Value Measurements as of December 31, 2016 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 Interest Rate Swaps (C) $ 1 $ — $ — $ 1 $ — NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 37 $ — $ — $ 37 $ — Debt Securities—Govt Other $ 66 $ — $ — $ 66 $ — Debt Securities—Corporate $ 91 $ — $ — $ 91 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (16 ) $ 372 $ (18 ) $ (364 ) $ (6 ) PSE&G Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ — $ — $ — $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 7 $ — $ — $ 7 $ — Debt Securities—Govt Other $ 13 $ — $ — $ 13 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (5 ) $ — $ — $ — $ (5 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 16 $ — $ — $ 16 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ 372 $ (18 ) $ (364 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2015 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 326 $ — $ 326 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 313 $ (608 ) $ — $ 896 $ 25 Interest Rate Swaps (C) $ 6 $ — $ — $ 6 $ — NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 48 $ — $ — $ 48 $ — Debt Securities—Govt Other $ 60 $ — $ — $ 60 $ — Debt Securities—Corporate $ 81 $ — $ — $ 81 $ — Other Securities $ 2 $ — $ 2 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (103 ) $ 553 $ — $ (644 ) $ (12 ) PSE&G Assets: Cash Equivalents (A) $ 160 $ — $ 160 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 13 $ — $ — $ — $ 13 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 12 $ — $ — $ 12 $ — Debt Securities—Corporate $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ — $ — $ — $ (11 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 300 $ (608 ) $ — $ 896 $ 12 NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 12 $ — $ — $ 12 $ — Debt Securities—Govt Other $ 14 $ — $ — $ 14 $ — Debt Securities—Corporate $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) (A) Represents money market mutual funds. (B) Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange. Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. (C) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (D) The fair value measurement table excludes cash of $1 million which is part of the NDT Fund, The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market. Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016 , net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016 , $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015 , net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015 , $(69) million was netted against assets and $14 million was netted against liabilities. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2016 and 2015 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2016 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ — $ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ — $ (5 ) Power Electricity Electric Load Contracts $ 7 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Gas (A) Other — — Total Power $ 7 $ (1 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2015 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 13 $ (11 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Electricity Other 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) (A) Includes gas supply positions which were immaterial as of December 31, 2016 . Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2016 and 2015 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2016 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2016 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2016 Millions PSEG Net Derivative Assets (Liabilities) $ 13 $ 13 $ (7 ) $ 3 $ (21 ) $ — $ 1 PSE&G Net Derivative Assets (Liabilities) $ 2 $ — $ (7 ) $ — $ — $ — $ (5 ) Power Net Derivative Assets (Liabilities) $ 11 $ 13 $ — $ 3 $ (21 ) $ — $ 6 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2015 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2015 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2015 Millions PSEG Net Derivative Assets (Liabilities) $ 37 $ 20 $ (24 ) $ — $ (20 ) $ — $ 13 PSE&G Net Derivative Assets (Liabilities) $ 26 $ — $ (24 ) $ — $ — $ — $ 2 Power Net Derivative Assets (Liabilities) $ 11 $ 20 $ — $ — $ (20 ) $ — $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015 , respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 is realized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015 , respectively. As of December 31, 2016 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2015 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $13 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. |
PSE&G [Member] | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Fair Value Measurements | Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2016 , these consisted primarily of gas supply contracts and certain electric load contracts. The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power. Recurring Fair Value Measurements as of December 31, 2016 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 Interest Rate Swaps (C) $ 1 $ — $ — $ 1 $ — NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 37 $ — $ — $ 37 $ — Debt Securities—Govt Other $ 66 $ — $ — $ 66 $ — Debt Securities—Corporate $ 91 $ — $ — $ 91 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (16 ) $ 372 $ (18 ) $ (364 ) $ (6 ) PSE&G Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ — $ — $ — $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 7 $ — $ — $ 7 $ — Debt Securities—Govt Other $ 13 $ — $ — $ 13 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (5 ) $ — $ — $ — $ (5 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 16 $ — $ — $ 16 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ 372 $ (18 ) $ (364 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2015 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 326 $ — $ 326 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 313 $ (608 ) $ — $ 896 $ 25 Interest Rate Swaps (C) $ 6 $ — $ — $ 6 $ — NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 48 $ — $ — $ 48 $ — Debt Securities—Govt Other $ 60 $ — $ — $ 60 $ — Debt Securities—Corporate $ 81 $ — $ — $ 81 $ — Other Securities $ 2 $ — $ 2 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (103 ) $ 553 $ — $ (644 ) $ (12 ) PSE&G Assets: Cash Equivalents (A) $ 160 $ — $ 160 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 13 $ — $ — $ — $ 13 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 12 $ — $ — $ 12 $ — Debt Securities—Corporate $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ — $ — $ — $ (11 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 300 $ (608 ) $ — $ 896 $ 12 NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 12 $ — $ — $ 12 $ — Debt Securities—Govt Other $ 14 $ — $ — $ 14 $ — Debt Securities—Corporate $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) (A) Represents money market mutual funds. (B) Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange. Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. (C) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (D) The fair value measurement table excludes cash of $1 million which is part of the NDT Fund, The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market. Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016 , net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016 , $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015 , net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015 , $(69) million was netted against assets and $14 million was netted against liabilities. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2016 and 2015 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2016 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ — $ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ — $ (5 ) Power Electricity Electric Load Contracts $ 7 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Gas (A) Other — — Total Power $ 7 $ (1 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2015 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 13 $ (11 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Electricity Other 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) (A) Includes gas supply positions which were immaterial as of December 31, 2016 . Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2016 and 2015 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2016 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2016 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2016 Millions PSEG Net Derivative Assets (Liabilities) $ 13 $ 13 $ (7 ) $ 3 $ (21 ) $ — $ 1 PSE&G Net Derivative Assets (Liabilities) $ 2 $ — $ (7 ) $ — $ — $ — $ (5 ) Power Net Derivative Assets (Liabilities) $ 11 $ 13 $ — $ 3 $ (21 ) $ — $ 6 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2015 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2015 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2015 Millions PSEG Net Derivative Assets (Liabilities) $ 37 $ 20 $ (24 ) $ — $ (20 ) $ — $ 13 PSE&G Net Derivative Assets (Liabilities) $ 26 $ — $ (24 ) $ — $ — $ — $ 2 Power Net Derivative Assets (Liabilities) $ 11 $ 20 $ — $ — $ (20 ) $ — $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015 , respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 is realized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015 , respectively. As of December 31, 2016 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2015 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $13 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. |
Power [Member] | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Fair Value Measurements | Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, PSE&G and Power have the ability to access. These consist primarily of listed equity securities and money market mutual funds, as well as natural gas futures contracts executed on NYMEX. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2016 , these consisted primarily of gas supply contracts and certain electric load contracts. The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power. Recurring Fair Value Measurements as of December 31, 2016 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 Interest Rate Swaps (C) $ 1 $ — $ — $ 1 $ — NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 37 $ — $ — $ 37 $ — Debt Securities—Govt Other $ 66 $ — $ — $ 66 $ — Debt Securities—Corporate $ 91 $ — $ — $ 91 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (16 ) $ 372 $ (18 ) $ (364 ) $ (6 ) PSE&G Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ — $ — $ — $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 7 $ — $ — $ 7 $ — Debt Securities—Govt Other $ 13 $ — $ — $ 13 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (5 ) $ — $ — $ — $ (5 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 16 $ — $ — $ 16 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ 372 $ (18 ) $ (364 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2015 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 326 $ — $ 326 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 313 $ (608 ) $ — $ 896 $ 25 Interest Rate Swaps (C) $ 6 $ — $ — $ 6 $ — NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 48 $ — $ — $ 48 $ — Debt Securities—Govt Other $ 60 $ — $ — $ 60 $ — Debt Securities—Corporate $ 81 $ — $ — $ 81 $ — Other Securities $ 2 $ — $ 2 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (103 ) $ 553 $ — $ (644 ) $ (12 ) PSE&G Assets: Cash Equivalents (A) $ 160 $ — $ 160 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 13 $ — $ — $ — $ 13 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 12 $ — $ — $ 12 $ — Debt Securities—Corporate $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ — $ — $ — $ (11 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 300 $ (608 ) $ — $ 896 $ 12 NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 12 $ — $ — $ 12 $ — Debt Securities—Govt Other $ 14 $ — $ — $ 14 $ — Debt Securities—Corporate $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) (A) Represents money market mutual funds. (B) Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange. Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. (C) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (D) The fair value measurement table excludes cash of $1 million which is part of the NDT Fund, The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market. Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016 , net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016 , $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015 , net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015 , $(69) million was netted against assets and $14 million was netted against liabilities. Additional Information Regarding Level 3 Measurements For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. For PSE&G, the natural gas supply contract is measured at fair value using modeling techniques taking into account the current price of natural gas adjusted for appropriate risk factors, as applicable, and internal assumptions about transportation costs, and accordingly, the fair value measurements are classified in Level 3. The fair value of Power’s electric load contracts in which load consumption may change hourly based on demand are measured using certain unobservable inputs, such as historic load variability and, accordingly, are categorized as Level 3. The following tables provide details surrounding significant Level 3 valuations as of December 31, 2016 and 2015 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2016 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ — $ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ — $ (5 ) Power Electricity Electric Load Contracts $ 7 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Gas (A) Other — — Total Power $ 7 $ (1 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2015 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 13 $ (11 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Electricity Other 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) (A) Includes gas supply positions which were immaterial as of December 31, 2016 . Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For gas supply contracts where PSE&G is a seller, an increase in gas transportation cost would increase the fair value. For energy-related contracts in cases where Power is a seller, an increase in the load variability would decrease the fair value. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2016 and 2015 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2016 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2016 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2016 Millions PSEG Net Derivative Assets (Liabilities) $ 13 $ 13 $ (7 ) $ 3 $ (21 ) $ — $ 1 PSE&G Net Derivative Assets (Liabilities) $ 2 $ — $ (7 ) $ — $ — $ — $ (5 ) Power Net Derivative Assets (Liabilities) $ 11 $ 13 $ — $ 3 $ (21 ) $ — $ 6 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2015 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2015 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2015 Millions PSEG Net Derivative Assets (Liabilities) $ 37 $ 20 $ (24 ) $ — $ (20 ) $ — $ 13 PSE&G Net Derivative Assets (Liabilities) $ 26 $ — $ (24 ) $ — $ — $ — $ 2 Power Net Derivative Assets (Liabilities) $ 11 $ 20 $ — $ — $ (20 ) $ — $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015 , respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 is realized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015 , respectively. As of December 31, 2016 , PSEG carried $2.6 billion of net assets that are measured at fair value on a recurring basis, of which $1 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. As of December 31, 2015 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $13 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock Based Compensation | Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2016 , there were approximately 15 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issued since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2016 and 2015 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as retirement, disability, change-in-control or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2016 2015 2014 Millions Compensation Cost included in Operation and Maintenance Expense $ 29 $ 34 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 12 $ 14 $ 13 For 2016 and 2015 the excess tax benefit was $4 million and $3 million , respectively. There was no excess tax benefit for 2014 . PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2016 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2016 1,707,250 $ 36.00 Exercised 677,350 $ 33.06 Canceled/Forfeited — $ — Outstanding as of December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 Exercisable at December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2016 , 2015 and 2014 . Activity for options exercised for the years ended December 31, 2016 , 2015 and 2014 is shown below: 2016 2015 2014 Millions Total Intrinsic Value of Options Exercised $ 7 $ 3 $ 4 Cash Received from Options Exercised $ 22 $ 12 $ 16 Tax Benefit Realized from Options Exercised $ 1 $ — $ — No options were vested during the years ended December 31, 2016 , 2015 and 2014 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 408,507 $ 34.95 Granted 285,258 $ 42.28 Vested 362,098 $ 37.23 Canceled/Forfeited 9,471 $ 39.67 Non-vested as of December 31, 2016 322,196 $ 38.75 1.0 $ 14,137,960 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2016 , 2015 and 2014 was $42.28 , $39.65 and $35.16 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $11 million and $12 million , respectively. As of December 31, 2016 , there was approximately $4 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units of 35,537 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 403,961 $ 40.42 Granted 319,718 $ 45.97 Vested 301,554 $ 41.22 Canceled/Forfeited 28,313 $ 42.04 Non-vested as of December 31, 2016 393,812 $ 44.20 1.6 $ 17,280,471 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2016 , 2015 and 2014 was $45.97 , $41.32 and $38.94 per share, respectively. The total intrinsic value of performance share units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $13 million and $6 million , respectively. As of December 31, 2016 , there was approximately $13 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 36,856 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan for each of the years ended December 31, 2016 , 2015 and 2014 was approximately $1 million . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for the years ended December 31, 2016 , 2015 and 2014 . During the years ended December 31, 2016 , 2015 and 2014 , employees purchased 262,763 shares, 250,499 shares and 207,248 shares at an average price of $40.70 , $36.66 and $36.07 per share, respectively. As of December 31, 2016 , 3.5 million shares were available for future issuance under this plan. |
PSE&G [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock Based Compensation | Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2016 , there were approximately 15 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issued since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2016 and 2015 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as retirement, disability, change-in-control or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2016 2015 2014 Millions Compensation Cost included in Operation and Maintenance Expense $ 29 $ 34 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 12 $ 14 $ 13 For 2016 and 2015 the excess tax benefit was $4 million and $3 million , respectively. There was no excess tax benefit for 2014 . PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2016 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2016 1,707,250 $ 36.00 Exercised 677,350 $ 33.06 Canceled/Forfeited — $ — Outstanding as of December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 Exercisable at December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2016 , 2015 and 2014 . Activity for options exercised for the years ended December 31, 2016 , 2015 and 2014 is shown below: 2016 2015 2014 Millions Total Intrinsic Value of Options Exercised $ 7 $ 3 $ 4 Cash Received from Options Exercised $ 22 $ 12 $ 16 Tax Benefit Realized from Options Exercised $ 1 $ — $ — No options were vested during the years ended December 31, 2016 , 2015 and 2014 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 408,507 $ 34.95 Granted 285,258 $ 42.28 Vested 362,098 $ 37.23 Canceled/Forfeited 9,471 $ 39.67 Non-vested as of December 31, 2016 322,196 $ 38.75 1.0 $ 14,137,960 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2016 , 2015 and 2014 was $42.28 , $39.65 and $35.16 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $11 million and $12 million , respectively. As of December 31, 2016 , there was approximately $4 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units of 35,537 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 403,961 $ 40.42 Granted 319,718 $ 45.97 Vested 301,554 $ 41.22 Canceled/Forfeited 28,313 $ 42.04 Non-vested as of December 31, 2016 393,812 $ 44.20 1.6 $ 17,280,471 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2016 , 2015 and 2014 was $45.97 , $41.32 and $38.94 per share, respectively. The total intrinsic value of performance share units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $13 million and $6 million , respectively. As of December 31, 2016 , there was approximately $13 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 36,856 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan for each of the years ended December 31, 2016 , 2015 and 2014 was approximately $1 million . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for the years ended December 31, 2016 , 2015 and 2014 . During the years ended December 31, 2016 , 2015 and 2014 , employees purchased 262,763 shares, 250,499 shares and 207,248 shares at an average price of $40.70 , $36.66 and $36.07 per share, respectively. As of December 31, 2016 , 3.5 million shares were available for future issuance under this plan. |
Power [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Stock Based Compensation | Stock Based Compensation PSEG’s Amended and Restated 2004 Long-Term Incentive Plan (LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance share units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIP are non-qualified options to purchase shares of PSEG’s common stock, restricted stock unit awards and performance share unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG’s Board of Directors (O&CC), the LTIP’s administrative committee. The LTIP currently provides for the issuance of equity awards with respect to approximately 16 million shares of common stock. As of December 31, 2016 , there were approximately 15 million shares available for future awards under the LTIP. Stock Options Under the LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the O&CC. Option awards are granted with an exercise price equal to the market price of PSEG’s common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the O&CC (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the O&CC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the O&CC, by delivering previously acquired shares of PSEG common stock. No options have been issued since 2009. Restricted Stock Units Under the LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until distributed, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2016 and 2015 generally vest at the end of three years. Vesting may be accelerated (pro-rated basis or full vesting) upon certain events such as retirement, disability, change-in-control or death. Performance Share Units Under the LTIP, PSEG has granted performance share units to officers and other key employees. These provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three -year performance period. Following the end of the performance period, the payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance share units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. Vesting may be accelerated on a pro-rated basis for the period of the employee’s service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Stock-Based Compensation PSEG recognizes compensation expense for stock options based on their grant date fair values, which are determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. PSEG recognizes compensation expense for restricted stock units over the vesting period based on the grant date fair value of the shares, which is equal to the market price of PSEG’s common stock on the date of the grant. PSEG recognizes compensation expense for the total shareholder return target for its performance share unit awards based on the grant date fair values of the award, which are determined using the Monte Carlo model. The accrual of compensation cost is based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. PSEG recognizes compensation expense for the return on invested capital target for its performance share units based on the grant date fair value of the awards, which is equal to the market price of PSEG’s common stock on the date of the grant. The accrual during the year of grant is estimated at 100% of the original grant. Such accrual may be adjusted to reflect the actual outcome. 2016 2015 2014 Millions Compensation Cost included in Operation and Maintenance Expense $ 29 $ 34 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 12 $ 14 $ 13 For 2016 and 2015 the excess tax benefit was $4 million and $3 million , respectively. There was no excess tax benefit for 2014 . PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. Stock Options Changes in stock options for 2016 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2016 1,707,250 $ 36.00 Exercised 677,350 $ 33.06 Canceled/Forfeited — $ — Outstanding as of December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 Exercisable at December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2016 , 2015 and 2014 . Activity for options exercised for the years ended December 31, 2016 , 2015 and 2014 is shown below: 2016 2015 2014 Millions Total Intrinsic Value of Options Exercised $ 7 $ 3 $ 4 Cash Received from Options Exercised $ 22 $ 12 $ 16 Tax Benefit Realized from Options Exercised $ 1 $ — $ — No options were vested during the years ended December 31, 2016 , 2015 and 2014 . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 408,507 $ 34.95 Granted 285,258 $ 42.28 Vested 362,098 $ 37.23 Canceled/Forfeited 9,471 $ 39.67 Non-vested as of December 31, 2016 322,196 $ 38.75 1.0 $ 14,137,960 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2016 , 2015 and 2014 was $42.28 , $39.65 and $35.16 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $11 million and $12 million , respectively. As of December 31, 2016 , there was approximately $4 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of ten months. Dividend equivalents units of 35,537 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 403,961 $ 40.42 Granted 319,718 $ 45.97 Vested 301,554 $ 41.22 Canceled/Forfeited 28,313 $ 42.04 Non-vested as of December 31, 2016 393,812 $ 44.20 1.6 $ 17,280,471 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2016 , 2015 and 2014 was $45.97 , $41.32 and $38.94 per share, respectively. The total intrinsic value of performance share units vested during the years ended December 31, 2016 , 2015 and 2014 was $17 million , $13 million and $6 million , respectively. As of December 31, 2016 , there was approximately $13 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 36,856 accrued on the performance share units during the year. Outside Directors Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on the amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board as specified by him/her in accordance with the provisions of the Directors Equity Plan. The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan for each of the years ended December 31, 2016 , 2015 and 2014 was approximately $1 million . Employee Stock Purchase Plan (ESPP) PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value for represented employees and 90% for non-represented employees through payroll deductions. Dividends will be reinvested for all employees at 95% of the fair market price unless the participant elects to receive a cash dividend. All employees are required to hold the shares purchased under the ESPP for at least three months from the purchase date. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. Compensation expense recognized under this program was immaterial for the years ended December 31, 2016 , 2015 and 2014 . During the years ended December 31, 2016 , 2015 and 2014 , employees purchased 262,763 shares, 250,499 shares and 207,248 shares at an average price of $40.70 , $36.66 and $36.07 per share, respectively. As of December 31, 2016 , 3.5 million shares were available for future issuance under this plan. |
Other Income and Deductions
Other Income and Deductions | 12 Months Ended |
Dec. 31, 2016 | |
Component of Other Income [Line Items] | |
Other Income and Deductions | Other Income and Deductions Other Income PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 96 $ — $ 96 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Other 12 6 6 24 Total Other Income $ 83 $ 102 $ 6 $ 191 Year Ended December 31, 2015 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 138 $ — $ 138 Allowance for Funds Used During Construction 48 — — 48 Solar Loan Interest 23 — — 23 Gain on Insurance Recovery — 28 — 28 Other 8 3 6 17 Total Other Income $ 79 $ 169 $ 6 $ 254 Year Ended December 31, 2014 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 219 $ — $ 219 Allowance for Funds Used During Construction 31 — — 31 Solar Loan Interest 24 — — 24 Other 6 3 7 16 Total Other Income $ 61 $ 222 $ 7 $ 290 Other Deductions PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Realized Losses and Expenses $ — $ 40 $ — $ 40 Other 4 17 6 27 Total Other Deductions $ 4 $ 57 $ 6 $ 67 Year Ended December 31, 2015 NDT Fund Realized Losses and Expenses $ — $ 45 $ — $ 45 Other 4 27 26 57 Total Other Deductions $ 4 $ 72 $ 26 $ 102 Year Ended December 31, 2014 NDT Fund Realized Losses and Expenses $ — $ 31 $ — $ 31 Other 3 21 6 30 Total Other Deductions $ 3 $ 52 $ 6 $ 61 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
PSE&G [Member] | |
Component of Other Income [Line Items] | |
Other Income and Deductions | Other Income and Deductions Other Income PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 96 $ — $ 96 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Other 12 6 6 24 Total Other Income $ 83 $ 102 $ 6 $ 191 Year Ended December 31, 2015 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 138 $ — $ 138 Allowance for Funds Used During Construction 48 — — 48 Solar Loan Interest 23 — — 23 Gain on Insurance Recovery — 28 — 28 Other 8 3 6 17 Total Other Income $ 79 $ 169 $ 6 $ 254 Year Ended December 31, 2014 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 219 $ — $ 219 Allowance for Funds Used During Construction 31 — — 31 Solar Loan Interest 24 — — 24 Other 6 3 7 16 Total Other Income $ 61 $ 222 $ 7 $ 290 Other Deductions PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Realized Losses and Expenses $ — $ 40 $ — $ 40 Other 4 17 6 27 Total Other Deductions $ 4 $ 57 $ 6 $ 67 Year Ended December 31, 2015 NDT Fund Realized Losses and Expenses $ — $ 45 $ — $ 45 Other 4 27 26 57 Total Other Deductions $ 4 $ 72 $ 26 $ 102 Year Ended December 31, 2014 NDT Fund Realized Losses and Expenses $ — $ 31 $ — $ 31 Other 3 21 6 30 Total Other Deductions $ 3 $ 52 $ 6 $ 61 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Power [Member] | |
Component of Other Income [Line Items] | |
Other Income and Deductions | Other Income and Deductions Other Income PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 96 $ — $ 96 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Other 12 6 6 24 Total Other Income $ 83 $ 102 $ 6 $ 191 Year Ended December 31, 2015 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 138 $ — $ 138 Allowance for Funds Used During Construction 48 — — 48 Solar Loan Interest 23 — — 23 Gain on Insurance Recovery — 28 — 28 Other 8 3 6 17 Total Other Income $ 79 $ 169 $ 6 $ 254 Year Ended December 31, 2014 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 219 $ — $ 219 Allowance for Funds Used During Construction 31 — — 31 Solar Loan Interest 24 — — 24 Other 6 3 7 16 Total Other Income $ 61 $ 222 $ 7 $ 290 Other Deductions PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Realized Losses and Expenses $ — $ 40 $ — $ 40 Other 4 17 6 27 Total Other Deductions $ 4 $ 57 $ 6 $ 67 Year Ended December 31, 2015 NDT Fund Realized Losses and Expenses $ — $ 45 $ — $ 45 Other 4 27 26 57 Total Other Deductions $ 4 $ 72 $ 26 $ 102 Year Ended December 31, 2014 NDT Fund Realized Losses and Expenses $ — $ 31 $ — $ 31 Other 3 21 6 30 Total Other Deductions $ 3 $ 52 $ 6 $ 61 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSEG 2016 2015 2014 Millions Net Income $ 887 $ 1,679 $ 1,518 Income Taxes: Operating Income: Current Expense: Federal $ (74 ) $ 243 $ 335 State 61 85 58 Total Current (13 ) 328 393 Deferred Expense: Federal 311 540 262 State 28 104 260 Total Deferred 339 644 522 Investment Tax Credit (ITC) 85 29 23 Total Income Taxes $ 411 $ 1,001 $ 938 Pre-Tax Income $ 1,298 $ 2,680 $ 2,456 Tax Computed at Statutory Rate 35% $ 454 $ 938 $ 860 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 56 129 145 Uncertain Tax Positions (31 ) 7 (9 ) Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 14 Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (25 ) (13 ) (14 ) Audit Settlement — — (12 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (9 ) (4 ) (17 ) Sub-Total (43 ) 63 78 Total Income Tax Provision $ 411 $ 1,001 $ 938 Effective Income Tax Rate 31.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent OPEB $ 283 $ 256 Related to Uncertain Tax Position 155 160 Securitization-Overcollection — 27 Total Noncurrent Assets $ 438 $ 443 Liabilities: Noncurrent: Plant-Related Items $ 6,593 $ 6,174 New Jersey Corporate Business Tax 674 615 Leasing Activities 565 612 Pension Costs 197 218 AROs and NDT Fund 398 393 Taxes Recoverable Through Future Rate (net) 208 191 Other 212 244 Total Noncurrent Liabilities $ 8,847 $ 8,447 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 8,409 $ 8,004 ITC 249 162 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,658 $ 8,166 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSE&G 2016 2015 2014 Millions Net Income $ 889 $ 787 $ 725 Income Taxes: Operating Income: Current Expense: Federal $ (153 ) $ 32 $ 124 State 10 52 16 Total Current (143 ) 84 140 Deferred Expense: Federal 551 325 214 State 102 52 84 Total Deferred 653 377 298 ITC 5 9 11 Total Income Taxes $ 515 $ 470 $ 449 Pre-Tax Income $ 1,404 $ 1,257 $ 1,174 Tax Computed at Statutory Rate 35% $ 491 $ 440 $ 411 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 72 67 65 Uncertain Tax Positions (18 ) (14 ) — Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (7 ) (6 ) (7 ) Audit Settlement — — 1 Other (3 ) 3 (8 ) Sub-Total 24 30 38 Total Income Tax Provision $ 515 $ 470 $ 449 Effective Income Tax Rate 36.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: OPEB $ 189 $ 164 Securitization-Overcollection — 27 Total Noncurrent Assets $ 189 $ 191 Liabilities: Noncurrent: Plant-Related Items $ 4,983 $ 4,435 New Jersey Corporate Business Tax 385 312 Conservation Costs 33 40 Pension Costs 252 262 Taxes Recoverable Through Future Rate (net) 208 191 Other 118 54 Total Noncurrent Liabilities $ 5,979 $ 5,294 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,790 $ 5,103 ITC 83 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,873 $ 5,181 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, Power 2016 2015 2014 Millions Net Income $ 18 $ 856 $ 760 Income Taxes: Operating Income: Current Expense: Federal $ 107 $ 220 $ 231 State 40 30 39 Total Current 147 250 270 Deferred Expense: Federal (222 ) 189 163 State (68 ) 52 48 Total Deferred (290 ) 241 211 ITC 82 20 10 Total Income Taxes $ (61 ) $ 511 $ 491 Pre-Tax Income $ (43 ) $ 1,367 $ 1,251 Tax Computed at Statutory Rate 35% $ (15 ) $ 478 $ 438 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) (18 ) 59 58 Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 15 Tax Credits (18 ) (7 ) (6 ) Uncertain Tax Positions 9 22 (8 ) Audit Settlement — — (4 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (5 ) (5 ) 14 Sub-Total (46 ) 33 53 Total Income Tax Provision $ (61 ) $ 511 $ 491 Effective Income Tax Rate 141.9 % 37.4 % 39.2 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: Pension Costs $ 68 $ 56 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 53 47 Other 76 — Total Noncurrent Assets $ 215 $ 121 Liabilities: Noncurrent: Plant-Related Items $ 1,605 $ 1,736 New Jersey Corporate Business Tax 214 243 AROs and NDT Fund 400 395 Other — 10 Total Noncurrent Liabilities $ 2,219 $ 2,384 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 2,004 $ 2,263 ITC 166 84 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,170 $ 2,347 In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations. PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9% . For additional information, see Note 6. Regulatory Assets and Liabilities . In December 2014, the Tax Increase Prevention Act of 2014 was enacted, which extended the 50% bonus depreciation rules for qualified property that was placed into service before January 1, 2015 and for long production property that was placed into service in 2015. In December 2015, Congress passed the Protecting Americans from Tax Hikes Act of 2015 (Tax Act). Among other provisions, the Tax Act includes an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified property that is placed in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The ITC rate has been extended through December 31, 2019 but is reduced to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions. These provisions have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 2015 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2015 $ 332 $ 165 $ 70 $ 95 Increases as a Result of Positions Taken in a Prior Period 87 55 28 4 Decreases as a Result of Positions Taken in a Prior Period (50 ) (43 ) (6 ) (1 ) Increases as a Result of Positions Taken during the Current Period 28 5 23 — Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities (10 ) — (4 ) (5 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2015 $ 386 $ 181 $ 111 $ 93 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (264 ) (162 ) (68 ) (34 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 95 $ (8 ) $ 43 $ 59 2014 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2014 $ 478 $ 208 $ 156 $ 110 Increases as a Result of Positions Taken in a Prior Period 82 65 17 — Decreases as a Result of Positions Taken in a Prior Period (190 ) (92 ) (80 ) (18 ) Increases as a Result of Positions Taken during the Current Period 30 16 9 5 Decreases as a Result of Positions Taken during the Current Period (8 ) — (8 ) — Decreases as a Result of Settlements with Taxing Authorities (60 ) (32 ) (24 ) (2 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2014 $ 332 $ 165 $ 70 $ 95 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (225 ) (138 ) (52 ) (35 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 80 $ — $ 18 $ 60 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2016 2015 2014 Millions PSE&G $ 22 $ 20 $ 15 Power 17 6 9 Energy Holdings 20 40 45 Total $ 59 $ 66 $ 69 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 14 PSE&G $ 3 Power $ 7 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2015 N/A N/A New Jersey 2006-2015 2011-2015 N/A Pennsylvania 2006-2015 2007-2015 N/A Connecticut 2007-2015 N/A N/A Texas 2008-2015 N/A N/A California 2006-2015 N/A N/A New York 2014-2015 N/A 2014-2015 |
PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSEG 2016 2015 2014 Millions Net Income $ 887 $ 1,679 $ 1,518 Income Taxes: Operating Income: Current Expense: Federal $ (74 ) $ 243 $ 335 State 61 85 58 Total Current (13 ) 328 393 Deferred Expense: Federal 311 540 262 State 28 104 260 Total Deferred 339 644 522 Investment Tax Credit (ITC) 85 29 23 Total Income Taxes $ 411 $ 1,001 $ 938 Pre-Tax Income $ 1,298 $ 2,680 $ 2,456 Tax Computed at Statutory Rate 35% $ 454 $ 938 $ 860 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 56 129 145 Uncertain Tax Positions (31 ) 7 (9 ) Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 14 Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (25 ) (13 ) (14 ) Audit Settlement — — (12 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (9 ) (4 ) (17 ) Sub-Total (43 ) 63 78 Total Income Tax Provision $ 411 $ 1,001 $ 938 Effective Income Tax Rate 31.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent OPEB $ 283 $ 256 Related to Uncertain Tax Position 155 160 Securitization-Overcollection — 27 Total Noncurrent Assets $ 438 $ 443 Liabilities: Noncurrent: Plant-Related Items $ 6,593 $ 6,174 New Jersey Corporate Business Tax 674 615 Leasing Activities 565 612 Pension Costs 197 218 AROs and NDT Fund 398 393 Taxes Recoverable Through Future Rate (net) 208 191 Other 212 244 Total Noncurrent Liabilities $ 8,847 $ 8,447 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 8,409 $ 8,004 ITC 249 162 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,658 $ 8,166 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSE&G 2016 2015 2014 Millions Net Income $ 889 $ 787 $ 725 Income Taxes: Operating Income: Current Expense: Federal $ (153 ) $ 32 $ 124 State 10 52 16 Total Current (143 ) 84 140 Deferred Expense: Federal 551 325 214 State 102 52 84 Total Deferred 653 377 298 ITC 5 9 11 Total Income Taxes $ 515 $ 470 $ 449 Pre-Tax Income $ 1,404 $ 1,257 $ 1,174 Tax Computed at Statutory Rate 35% $ 491 $ 440 $ 411 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 72 67 65 Uncertain Tax Positions (18 ) (14 ) — Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (7 ) (6 ) (7 ) Audit Settlement — — 1 Other (3 ) 3 (8 ) Sub-Total 24 30 38 Total Income Tax Provision $ 515 $ 470 $ 449 Effective Income Tax Rate 36.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: OPEB $ 189 $ 164 Securitization-Overcollection — 27 Total Noncurrent Assets $ 189 $ 191 Liabilities: Noncurrent: Plant-Related Items $ 4,983 $ 4,435 New Jersey Corporate Business Tax 385 312 Conservation Costs 33 40 Pension Costs 252 262 Taxes Recoverable Through Future Rate (net) 208 191 Other 118 54 Total Noncurrent Liabilities $ 5,979 $ 5,294 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,790 $ 5,103 ITC 83 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,873 $ 5,181 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, Power 2016 2015 2014 Millions Net Income $ 18 $ 856 $ 760 Income Taxes: Operating Income: Current Expense: Federal $ 107 $ 220 $ 231 State 40 30 39 Total Current 147 250 270 Deferred Expense: Federal (222 ) 189 163 State (68 ) 52 48 Total Deferred (290 ) 241 211 ITC 82 20 10 Total Income Taxes $ (61 ) $ 511 $ 491 Pre-Tax Income $ (43 ) $ 1,367 $ 1,251 Tax Computed at Statutory Rate 35% $ (15 ) $ 478 $ 438 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) (18 ) 59 58 Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 15 Tax Credits (18 ) (7 ) (6 ) Uncertain Tax Positions 9 22 (8 ) Audit Settlement — — (4 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (5 ) (5 ) 14 Sub-Total (46 ) 33 53 Total Income Tax Provision $ (61 ) $ 511 $ 491 Effective Income Tax Rate 141.9 % 37.4 % 39.2 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: Pension Costs $ 68 $ 56 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 53 47 Other 76 — Total Noncurrent Assets $ 215 $ 121 Liabilities: Noncurrent: Plant-Related Items $ 1,605 $ 1,736 New Jersey Corporate Business Tax 214 243 AROs and NDT Fund 400 395 Other — 10 Total Noncurrent Liabilities $ 2,219 $ 2,384 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 2,004 $ 2,263 ITC 166 84 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,170 $ 2,347 In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations. PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9% . For additional information, see Note 6. Regulatory Assets and Liabilities . In December 2014, the Tax Increase Prevention Act of 2014 was enacted, which extended the 50% bonus depreciation rules for qualified property that was placed into service before January 1, 2015 and for long production property that was placed into service in 2015. In December 2015, Congress passed the Protecting Americans from Tax Hikes Act of 2015 (Tax Act). Among other provisions, the Tax Act includes an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified property that is placed in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The ITC rate has been extended through December 31, 2019 but is reduced to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions. These provisions have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 2015 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2015 $ 332 $ 165 $ 70 $ 95 Increases as a Result of Positions Taken in a Prior Period 87 55 28 4 Decreases as a Result of Positions Taken in a Prior Period (50 ) (43 ) (6 ) (1 ) Increases as a Result of Positions Taken during the Current Period 28 5 23 — Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities (10 ) — (4 ) (5 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2015 $ 386 $ 181 $ 111 $ 93 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (264 ) (162 ) (68 ) (34 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 95 $ (8 ) $ 43 $ 59 2014 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2014 $ 478 $ 208 $ 156 $ 110 Increases as a Result of Positions Taken in a Prior Period 82 65 17 — Decreases as a Result of Positions Taken in a Prior Period (190 ) (92 ) (80 ) (18 ) Increases as a Result of Positions Taken during the Current Period 30 16 9 5 Decreases as a Result of Positions Taken during the Current Period (8 ) — (8 ) — Decreases as a Result of Settlements with Taxing Authorities (60 ) (32 ) (24 ) (2 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2014 $ 332 $ 165 $ 70 $ 95 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (225 ) (138 ) (52 ) (35 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 80 $ — $ 18 $ 60 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2016 2015 2014 Millions PSE&G $ 22 $ 20 $ 15 Power 17 6 9 Energy Holdings 20 40 45 Total $ 59 $ 66 $ 69 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 14 PSE&G $ 3 Power $ 7 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2015 N/A N/A New Jersey 2006-2015 2011-2015 N/A Pennsylvania 2006-2015 2007-2015 N/A Connecticut 2007-2015 N/A N/A Texas 2008-2015 N/A N/A California 2006-2015 N/A N/A New York 2014-2015 N/A 2014-2015 |
Power [Member] | |
Income Taxes [Line Items] | |
Income Taxes | Income Taxes A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSEG 2016 2015 2014 Millions Net Income $ 887 $ 1,679 $ 1,518 Income Taxes: Operating Income: Current Expense: Federal $ (74 ) $ 243 $ 335 State 61 85 58 Total Current (13 ) 328 393 Deferred Expense: Federal 311 540 262 State 28 104 260 Total Deferred 339 644 522 Investment Tax Credit (ITC) 85 29 23 Total Income Taxes $ 411 $ 1,001 $ 938 Pre-Tax Income $ 1,298 $ 2,680 $ 2,456 Tax Computed at Statutory Rate 35% $ 454 $ 938 $ 860 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 56 129 145 Uncertain Tax Positions (31 ) 7 (9 ) Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 14 Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (25 ) (13 ) (14 ) Audit Settlement — — (12 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (9 ) (4 ) (17 ) Sub-Total (43 ) 63 78 Total Income Tax Provision $ 411 $ 1,001 $ 938 Effective Income Tax Rate 31.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent OPEB $ 283 $ 256 Related to Uncertain Tax Position 155 160 Securitization-Overcollection — 27 Total Noncurrent Assets $ 438 $ 443 Liabilities: Noncurrent: Plant-Related Items $ 6,593 $ 6,174 New Jersey Corporate Business Tax 674 615 Leasing Activities 565 612 Pension Costs 197 218 AROs and NDT Fund 398 393 Taxes Recoverable Through Future Rate (net) 208 191 Other 212 244 Total Noncurrent Liabilities $ 8,847 $ 8,447 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 8,409 $ 8,004 ITC 249 162 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,658 $ 8,166 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations. A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSE&G 2016 2015 2014 Millions Net Income $ 889 $ 787 $ 725 Income Taxes: Operating Income: Current Expense: Federal $ (153 ) $ 32 $ 124 State 10 52 16 Total Current (143 ) 84 140 Deferred Expense: Federal 551 325 214 State 102 52 84 Total Deferred 653 377 298 ITC 5 9 11 Total Income Taxes $ 515 $ 470 $ 449 Pre-Tax Income $ 1,404 $ 1,257 $ 1,174 Tax Computed at Statutory Rate 35% $ 491 $ 440 $ 411 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 72 67 65 Uncertain Tax Positions (18 ) (14 ) — Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (7 ) (6 ) (7 ) Audit Settlement — — 1 Other (3 ) 3 (8 ) Sub-Total 24 30 38 Total Income Tax Provision $ 515 $ 470 $ 449 Effective Income Tax Rate 36.7 % 37.4 % 38.2 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: OPEB $ 189 $ 164 Securitization-Overcollection — 27 Total Noncurrent Assets $ 189 $ 191 Liabilities: Noncurrent: Plant-Related Items $ 4,983 $ 4,435 New Jersey Corporate Business Tax 385 312 Conservation Costs 33 40 Pension Costs 252 262 Taxes Recoverable Through Future Rate (net) 208 191 Other 118 54 Total Noncurrent Liabilities $ 5,979 $ 5,294 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,790 $ 5,103 ITC 83 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,873 $ 5,181 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, Power 2016 2015 2014 Millions Net Income $ 18 $ 856 $ 760 Income Taxes: Operating Income: Current Expense: Federal $ 107 $ 220 $ 231 State 40 30 39 Total Current 147 250 270 Deferred Expense: Federal (222 ) 189 163 State (68 ) 52 48 Total Deferred (290 ) 241 211 ITC 82 20 10 Total Income Taxes $ (61 ) $ 511 $ 491 Pre-Tax Income $ (43 ) $ 1,367 $ 1,251 Tax Computed at Statutory Rate 35% $ (15 ) $ 478 $ 438 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) (18 ) 59 58 Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 15 Tax Credits (18 ) (7 ) (6 ) Uncertain Tax Positions 9 22 (8 ) Audit Settlement — — (4 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (5 ) (5 ) 14 Sub-Total (46 ) 33 53 Total Income Tax Provision $ (61 ) $ 511 $ 491 Effective Income Tax Rate 141.9 % 37.4 % 39.2 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: Pension Costs $ 68 $ 56 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 53 47 Other 76 — Total Noncurrent Assets $ 215 $ 121 Liabilities: Noncurrent: Plant-Related Items $ 1,605 $ 1,736 New Jersey Corporate Business Tax 214 243 AROs and NDT Fund 400 395 Other — 10 Total Noncurrent Liabilities $ 2,219 $ 2,384 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 2,004 $ 2,263 ITC 166 84 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,170 $ 2,347 In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations. PSEG, PSE&G and Power each provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from or refunded to PSE&G’s customers in the future. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9% . For additional information, see Note 6. Regulatory Assets and Liabilities . In December 2014, the Tax Increase Prevention Act of 2014 was enacted, which extended the 50% bonus depreciation rules for qualified property that was placed into service before January 1, 2015 and for long production property that was placed into service in 2015. In December 2015, Congress passed the Protecting Americans from Tax Hikes Act of 2015 (Tax Act). Among other provisions, the Tax Act includes an extension of the bonus depreciation rules and the 30% ITC for qualified property placed into service after 2016. Qualified property that is placed in service from January 1, 2015 through December 31, 2017 is eligible for 50% bonus depreciation. The rate is reduced to 40% and 30% for eligible property placed in service in 2018 and 2019, respectively. In addition, long production property placed in service in 2020 will also qualify for 30% bonus depreciation. The ITC rate has been extended through December 31, 2019 but is reduced to 26% and 22% for projects commenced in 2020 and 2021, respectively. The financial impact of the extensions of the ITC rate will depend upon future transactions. These provisions have generated significant cash tax benefits for PSEG, PSE&G and Power through tax benefits related to the accelerated depreciation. These tax benefits would have otherwise been received over an estimated average 20 year period. However, these tax benefits will have a negative impact on the rate base of several of PSE&G’s programs. PSEG recorded the following amounts related to its unrecognized tax benefits, which were primarily comprised of amounts recorded for PSE&G, Power and Energy Holdings: 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 2015 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2015 $ 332 $ 165 $ 70 $ 95 Increases as a Result of Positions Taken in a Prior Period 87 55 28 4 Decreases as a Result of Positions Taken in a Prior Period (50 ) (43 ) (6 ) (1 ) Increases as a Result of Positions Taken during the Current Period 28 5 23 — Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities (10 ) — (4 ) (5 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2015 $ 386 $ 181 $ 111 $ 93 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (264 ) (162 ) (68 ) (34 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 95 $ (8 ) $ 43 $ 59 2014 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2014 $ 478 $ 208 $ 156 $ 110 Increases as a Result of Positions Taken in a Prior Period 82 65 17 — Decreases as a Result of Positions Taken in a Prior Period (190 ) (92 ) (80 ) (18 ) Increases as a Result of Positions Taken during the Current Period 30 16 9 5 Decreases as a Result of Positions Taken during the Current Period (8 ) — (8 ) — Decreases as a Result of Settlements with Taxing Authorities (60 ) (32 ) (24 ) (2 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2014 $ 332 $ 165 $ 70 $ 95 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (225 ) (138 ) (52 ) (35 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 80 $ — $ 18 $ 60 PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2016 2015 2014 Millions PSE&G $ 22 $ 20 $ 15 Power 17 6 9 Energy Holdings 20 40 45 Total $ 59 $ 66 $ 69 It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 14 PSE&G $ 3 Power $ 7 A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2015 N/A N/A New Jersey 2006-2015 2011-2015 N/A Pennsylvania 2006-2015 2007-2015 N/A Connecticut 2007-2015 N/A N/A Texas 2008-2015 N/A N/A California 2006-2015 N/A N/A New York 2014-2015 N/A 2014-2015 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax | 12 Months Ended |
Dec. 31, 2016 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Accumulated Other Comprehensive Income (Loss), Net of Tax | Accumulated Other Comprehensive Income (Loss), Net of Tax PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (2 ) $ (238 ) $ 145 $ (95 ) Other Comprehensive Income before Reclassifications 7 (184 ) 42 (135 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 11 (69 ) (53 ) Net Current Period Other Comprehensive Income (Loss) 12 (173 ) (27 ) (188 ) Balance as of December 31, 2014 $ 10 $ (411 ) $ 118 $ (283 ) Other Comprehensive Income before Reclassifications 2 (7 ) (25 ) (30 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 32 (2 ) 18 Net Current Period Other Comprehensive Income (Loss) (10 ) 25 (27 ) (12 ) Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (1 ) $ (204 ) $ 142 $ (63 ) Other Comprehensive Income before Reclassifications 7 (156 ) 39 (110 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 9 (69 ) (55 ) Net Current Period Other Comprehensive Income (Loss) 12 (147 ) (30 ) (165 ) Balance as of December 31, 2014 $ 11 $ (351 ) $ 112 $ (228 ) Other Comprehensive Income before Reclassifications 1 (4 ) (24 ) (27 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 28 (1 ) 15 Net Current Period Other Comprehensive Income (Loss) (11 ) 24 (25 ) (12 ) Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 10 (4 ) 6 Amortization of Actuarial Loss O&M Expense (28 ) 11 (17 ) Total Pension and OPEB Plans (18 ) 7 (11 ) Available-for-Sale Securities Realized Gains Other Income 181 (89 ) 92 Realized Losses Other Deductions (26 ) 13 (13 ) Other-Than-Temporary Impairments (OTTI) OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 135 (66 ) 69 Total $ 108 $ (55 ) $ 53 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (25 ) 11 (14 ) Total Pension and OPEB Plans (16 ) 7 (9 ) Available-for-Sale Securities Realized Gains Other Income 178 (87 ) 91 Realized Losses Other Deductions (24 ) 12 (12 ) OTTI OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 134 (65 ) 69 Total $ 109 $ (54 ) $ 55 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 12 (3 ) 9 Amortization of Actuarial Loss O&M Expense (68 ) 27 (41 ) Total Pension and OPEB Plans (56 ) 24 (32 ) Available-for-Sale Securities Realized Gains Other Income 100 (52 ) 48 Realized Losses Other Deductions (39 ) 20 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 8 (6 ) 2 Total $ (28 ) $ 10 $ (18 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (3 ) 8 Amortization of Actuarial Loss O&M Expense (60 ) 24 (36 ) Total Pension and OPEB Plans (49 ) 21 (28 ) Available-for-Sale Securities Realized Gains Other Income 98 (51 ) 47 Realized Losses Other Deductions (38 ) 19 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 7 (6 ) 1 Total $ (22 ) $ 7 $ (15 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss O&M Expense (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains Other Income 59 (29 ) 30 Realized Losses Other Deductions (37 ) 19 (18 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss O&M Expense (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains Other Income 55 (28 ) 27 Realized Losses Other Deductions (33 ) 17 (16 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) |
Power [Member] | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |
Accumulated Other Comprehensive Income (Loss), Net of Tax | Accumulated Other Comprehensive Income (Loss), Net of Tax PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (2 ) $ (238 ) $ 145 $ (95 ) Other Comprehensive Income before Reclassifications 7 (184 ) 42 (135 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 11 (69 ) (53 ) Net Current Period Other Comprehensive Income (Loss) 12 (173 ) (27 ) (188 ) Balance as of December 31, 2014 $ 10 $ (411 ) $ 118 $ (283 ) Other Comprehensive Income before Reclassifications 2 (7 ) (25 ) (30 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 32 (2 ) 18 Net Current Period Other Comprehensive Income (Loss) (10 ) 25 (27 ) (12 ) Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (1 ) $ (204 ) $ 142 $ (63 ) Other Comprehensive Income before Reclassifications 7 (156 ) 39 (110 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 9 (69 ) (55 ) Net Current Period Other Comprehensive Income (Loss) 12 (147 ) (30 ) (165 ) Balance as of December 31, 2014 $ 11 $ (351 ) $ 112 $ (228 ) Other Comprehensive Income before Reclassifications 1 (4 ) (24 ) (27 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 28 (1 ) 15 Net Current Period Other Comprehensive Income (Loss) (11 ) 24 (25 ) (12 ) Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 10 (4 ) 6 Amortization of Actuarial Loss O&M Expense (28 ) 11 (17 ) Total Pension and OPEB Plans (18 ) 7 (11 ) Available-for-Sale Securities Realized Gains Other Income 181 (89 ) 92 Realized Losses Other Deductions (26 ) 13 (13 ) Other-Than-Temporary Impairments (OTTI) OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 135 (66 ) 69 Total $ 108 $ (55 ) $ 53 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (25 ) 11 (14 ) Total Pension and OPEB Plans (16 ) 7 (9 ) Available-for-Sale Securities Realized Gains Other Income 178 (87 ) 91 Realized Losses Other Deductions (24 ) 12 (12 ) OTTI OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 134 (65 ) 69 Total $ 109 $ (54 ) $ 55 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 12 (3 ) 9 Amortization of Actuarial Loss O&M Expense (68 ) 27 (41 ) Total Pension and OPEB Plans (56 ) 24 (32 ) Available-for-Sale Securities Realized Gains Other Income 100 (52 ) 48 Realized Losses Other Deductions (39 ) 20 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 8 (6 ) 2 Total $ (28 ) $ 10 $ (18 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (3 ) 8 Amortization of Actuarial Loss O&M Expense (60 ) 24 (36 ) Total Pension and OPEB Plans (49 ) 21 (28 ) Available-for-Sale Securities Realized Gains Other Income 98 (51 ) 47 Realized Losses Other Deductions (38 ) 19 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 7 (6 ) 1 Total $ (22 ) $ 7 $ (15 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss O&M Expense (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains Other Income 59 (29 ) 30 Realized Losses Other Deductions (37 ) 19 (18 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss O&M Expense (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains Other Income 55 (28 ) 27 Realized Losses Other Deductions (33 ) 17 (16 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) |
Earnings Per Share (EPS) and Di
Earnings Per Share (EPS) and Dividends | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share (EPS) and Dividends | Earnings Per Share (EPS) and Dividends EPS Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS: Years Ended December 31, 2016 2015 2014 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 887 $ 887 1,679 1,679 $ 1,518 $ 1,518 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 505 505 505 505 506 506 Effect of Stock Based Compensation Awards — 3 — 3 — 2 Total Shares 505 508 505 508 506 508 EPS: Net Income $ 1.76 $ 1.75 3.32 3.30 $ 3.00 $ 2.99 There were approximately 0.4 million , 0.5 million and 0.4 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2016 , 2015 and 2014 , respectively. No other stock options had an antidilutive effect for the years ended December 31, 2016 , 2015 or 2014 . Dividends Years Ended December 31, Dividend Payments on Common Stock 2016 2015 2014 Per Share $ 1.64 $ 1.56 $ 1.48 in Millions $ 830 $ 789 $ 748 On February 21, 2017 , PSEG’s Board of Directors approved a $0.43 per share common stock dividend for the first quarter of 2017 . |
Financial Information By Busine
Financial Information By Business Segments | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting Information [Line Items] | |
Financial Information By Business Segments | Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,221 $ 4,023 $ 370 $ (1,553 ) $ 9,061 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,614 13 (51 ) — 1,576 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) 889 18 (20 ) — 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2015 Operating Revenues $ 6,636 $ 4,928 $ 462 $ (1,611 ) $ 10,415 Depreciation and Amortization 892 291 31 — 1,214 Operating Income (Loss) 1,462 1,430 70 — 2,962 Income from Equity Method Investments — 14 (2 ) — 12 Interest Income 25 2 33 (29 ) 31 Interest Expense 280 121 21 (29 ) 393 Income (Loss) before Income Taxes 1,257 1,367 56 — 2,680 Income Tax Expense (Benefit) 470 511 20 — 1,001 Net Income (Loss) 787 856 36 — 1,679 Gross Additions to Long-Lived Assets $ 2,692 $ 1,117 $ 54 $ — $ 3,863 As of December 31, 2015 Total Assets $ 23,677 $ 12,250 $ 2,810 $ (1,202 ) $ 37,535 Investments in Equity Method Subsidiaries $ — $ 119 $ — $ — $ 119 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2014 Operating Revenues $ 6,766 $ 5,434 $ 455 $ (1,769 ) $ 10,886 Depreciation and Amortization 906 292 29 — 1,227 Operating Income (Loss) 1,393 1,209 21 — 2,623 Income from Equity Method Investments — 14 (1 ) — 13 Interest Income 26 1 25 (22 ) 30 Interest Expense 277 122 12 (22 ) 389 Income (Loss) before Income Taxes 1,174 1,251 31 — 2,456 Income Tax Expense (Benefit) 449 491 (2 ) — 938 Net Income (Loss) 725 760 33 — 1,518 Gross Additions to Long-Lived Assets $ 2,164 $ 626 $ 30 $ — $ 2,820 As of December 31, 2014 Total Assets $ 22,186 $ 12,037 $ 2,799 $ (1,735 ) $ 35,287 Investments in Equity Method Subsidiaries $ — $ 121 $ 2 $ — $ 123 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions . |
PSE&G [Member] | |
Segment Reporting Information [Line Items] | |
Financial Information By Business Segments | Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,221 $ 4,023 $ 370 $ (1,553 ) $ 9,061 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,614 13 (51 ) — 1,576 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) 889 18 (20 ) — 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2015 Operating Revenues $ 6,636 $ 4,928 $ 462 $ (1,611 ) $ 10,415 Depreciation and Amortization 892 291 31 — 1,214 Operating Income (Loss) 1,462 1,430 70 — 2,962 Income from Equity Method Investments — 14 (2 ) — 12 Interest Income 25 2 33 (29 ) 31 Interest Expense 280 121 21 (29 ) 393 Income (Loss) before Income Taxes 1,257 1,367 56 — 2,680 Income Tax Expense (Benefit) 470 511 20 — 1,001 Net Income (Loss) 787 856 36 — 1,679 Gross Additions to Long-Lived Assets $ 2,692 $ 1,117 $ 54 $ — $ 3,863 As of December 31, 2015 Total Assets $ 23,677 $ 12,250 $ 2,810 $ (1,202 ) $ 37,535 Investments in Equity Method Subsidiaries $ — $ 119 $ — $ — $ 119 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2014 Operating Revenues $ 6,766 $ 5,434 $ 455 $ (1,769 ) $ 10,886 Depreciation and Amortization 906 292 29 — 1,227 Operating Income (Loss) 1,393 1,209 21 — 2,623 Income from Equity Method Investments — 14 (1 ) — 13 Interest Income 26 1 25 (22 ) 30 Interest Expense 277 122 12 (22 ) 389 Income (Loss) before Income Taxes 1,174 1,251 31 — 2,456 Income Tax Expense (Benefit) 449 491 (2 ) — 938 Net Income (Loss) 725 760 33 — 1,518 Gross Additions to Long-Lived Assets $ 2,164 $ 626 $ 30 $ — $ 2,820 As of December 31, 2014 Total Assets $ 22,186 $ 12,037 $ 2,799 $ (1,735 ) $ 35,287 Investments in Equity Method Subsidiaries $ — $ 121 $ 2 $ — $ 123 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions . |
Power [Member] | |
Segment Reporting Information [Line Items] | |
Financial Information By Business Segments | Financial Information by Business Segment Basis of Organization PSEG’s, PSE&G’s and Power’s operating segments were determined by management in accordance with GAAP. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how resources are allocated to each business. PSEG’s reportable segments are PSE&G and Power. PSE&G and Power each represent a single reportable segment and therefore no separate segment information is provided for these Registrants. PSE&G PSE&G earns revenues from its tariffs, under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as solar investments, sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services. Power Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding energy, capacity and ancillary services into the markets for these products. Power also enters into contracts for energy, capacity, FTRs, gas, emission allowances and other energy-related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations. Other This category includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,221 $ 4,023 $ 370 $ (1,553 ) $ 9,061 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,614 13 (51 ) — 1,576 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) 889 18 (20 ) — 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2015 Operating Revenues $ 6,636 $ 4,928 $ 462 $ (1,611 ) $ 10,415 Depreciation and Amortization 892 291 31 — 1,214 Operating Income (Loss) 1,462 1,430 70 — 2,962 Income from Equity Method Investments — 14 (2 ) — 12 Interest Income 25 2 33 (29 ) 31 Interest Expense 280 121 21 (29 ) 393 Income (Loss) before Income Taxes 1,257 1,367 56 — 2,680 Income Tax Expense (Benefit) 470 511 20 — 1,001 Net Income (Loss) 787 856 36 — 1,679 Gross Additions to Long-Lived Assets $ 2,692 $ 1,117 $ 54 $ — $ 3,863 As of December 31, 2015 Total Assets $ 23,677 $ 12,250 $ 2,810 $ (1,202 ) $ 37,535 Investments in Equity Method Subsidiaries $ — $ 119 $ — $ — $ 119 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2014 Operating Revenues $ 6,766 $ 5,434 $ 455 $ (1,769 ) $ 10,886 Depreciation and Amortization 906 292 29 — 1,227 Operating Income (Loss) 1,393 1,209 21 — 2,623 Income from Equity Method Investments — 14 (1 ) — 13 Interest Income 26 1 25 (22 ) 30 Interest Expense 277 122 12 (22 ) 389 Income (Loss) before Income Taxes 1,174 1,251 31 — 2,456 Income Tax Expense (Benefit) 449 491 (2 ) — 938 Net Income (Loss) 725 760 33 — 1,518 Gross Additions to Long-Lived Assets $ 2,164 $ 626 $ 30 $ — $ 2,820 As of December 31, 2014 Total Assets $ 22,186 $ 12,037 $ 2,799 $ (1,735 ) $ 35,287 Investments in Equity Method Subsidiaries $ — $ 121 $ 2 $ — $ 123 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions . |
Related-Party Transactions
Related-Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transaction [Line Items] | |
Related-Party Transactions | Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Administrative Billings from Services (B) 312 274 248 Total Billings from Affiliates $ 1,899 $ 1,904 $ 2,019 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivables from PSEG (C) $ 76 $ 222 Payable to Power (A) $ 193 $ 212 Payable to Services (B) 67 80 Accounts Payable—Affiliated Companies $ 260 $ 292 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 130 $ 109 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Billings from Affiliates: Administrative Billings from Services (B) $ 179 $ 187 $ 165 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivable from PSE&G (A) $ 193 $ 212 Receivable from PSEG (C) 12 64 Accounts Receivable—Affiliated Companies $ 205 $ 276 Payable to Services (B) $ 25 $ 33 Accounts Payable—Affiliated Companies $ 25 $ 33 Short-Term Loan due (to) from Affiliate (E) $ 87 $ 363 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 77 $ 35 (A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. (B) Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. (C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. (D) PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. (E) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
PSE&G [Member] | |
Related Party Transaction [Line Items] | |
Related-Party Transactions | Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Administrative Billings from Services (B) 312 274 248 Total Billings from Affiliates $ 1,899 $ 1,904 $ 2,019 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivables from PSEG (C) $ 76 $ 222 Payable to Power (A) $ 193 $ 212 Payable to Services (B) 67 80 Accounts Payable—Affiliated Companies $ 260 $ 292 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 130 $ 109 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Billings from Affiliates: Administrative Billings from Services (B) $ 179 $ 187 $ 165 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivable from PSE&G (A) $ 193 $ 212 Receivable from PSEG (C) 12 64 Accounts Receivable—Affiliated Companies $ 205 $ 276 Payable to Services (B) $ 25 $ 33 Accounts Payable—Affiliated Companies $ 25 $ 33 Short-Term Loan due (to) from Affiliate (E) $ 87 $ 363 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 77 $ 35 (A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. (B) Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. (C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. (D) PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. (E) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
Power [Member] | |
Related Party Transaction [Line Items] | |
Related-Party Transactions | Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. PSE&G The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Administrative Billings from Services (B) 312 274 248 Total Billings from Affiliates $ 1,899 $ 1,904 $ 2,019 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivables from PSEG (C) $ 76 $ 222 Payable to Power (A) $ 193 $ 212 Payable to Services (B) 67 80 Accounts Payable—Affiliated Companies $ 260 $ 292 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 130 $ 109 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Billings from Affiliates: Administrative Billings from Services (B) $ 179 $ 187 $ 165 Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivable from PSE&G (A) $ 193 $ 212 Receivable from PSEG (C) 12 64 Accounts Receivable—Affiliated Companies $ 205 $ 276 Payable to Services (B) $ 25 $ 33 Accounts Payable—Affiliated Companies $ 25 $ 33 Short-Term Loan due (to) from Affiliate (E) $ 87 $ 363 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 77 $ 35 (A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. (B) Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. (C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. (D) PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. (E) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
Selected Quarterly Data
Selected Quarterly Data | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Quarterly Data [Line Items] | |
Selected Quarterly Data | Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,616 $ 3,135 $ 1,905 $ 2,314 $ 2,450 $ 2,688 $ 2,090 $ 2,278 Operating Income $ 827 $ 1,048 $ 347 $ 568 $ 577 $ 814 $ (175 ) $ 532 Net Income (Loss) $ 471 $ 586 $ 187 $ 345 $ 327 $ 439 $ (98 ) $ 309 Earnings Per Share: Basic: Net Income (Loss) $ 0.93 $ 1.16 $ 0.37 $ 0.68 $ 0.65 $ 0.87 $ (0.19 ) $ 0.61 Diluted: Net Income (Loss) $ 0.93 $ 1.15 $ 0.37 $ 0.68 $ 0.64 $ 0.87 $ (0.19 ) $ 0.60 Weighted Average Common Shares Outstanding: Basic 505 506 505 506 505 505 505 505 Diluted 508 508 508 508 508 508 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2016 2015 2016 2015 2016 2015 2016 2015 PSE&G: Millions Operating Revenues $ 1,712 $ 2,002 $ 1,350 $ 1,466 $ 1,684 $ 1,766 $ 1,475 $ 1,402 Operating Income $ 462 $ 451 $ 333 $ 320 $ 450 $ 404 $ 369 $ 287 Net Income $ 262 $ 242 $ 179 $ 167 $ 255 $ 222 $ 193 $ 156 Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 Power: Millions Operating Revenues $ 1,313 $ 1,725 $ 714 $ 1,025 $ 1,075 $ 1,096 $ 921 $ 1,082 Operating Income (Loss) $ 343 $ 584 $ (12 ) $ 228 $ 238 $ 391 $ (556 ) $ 227 Net Income (Loss) $ 192 $ 335 $ (11 ) $ 166 $ 139 $ 206 $ (302 ) $ 149 (A) The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
PSE&G [Member] | |
Schedule of Quarterly Data [Line Items] | |
Selected Quarterly Data | Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,616 $ 3,135 $ 1,905 $ 2,314 $ 2,450 $ 2,688 $ 2,090 $ 2,278 Operating Income $ 827 $ 1,048 $ 347 $ 568 $ 577 $ 814 $ (175 ) $ 532 Net Income (Loss) $ 471 $ 586 $ 187 $ 345 $ 327 $ 439 $ (98 ) $ 309 Earnings Per Share: Basic: Net Income (Loss) $ 0.93 $ 1.16 $ 0.37 $ 0.68 $ 0.65 $ 0.87 $ (0.19 ) $ 0.61 Diluted: Net Income (Loss) $ 0.93 $ 1.15 $ 0.37 $ 0.68 $ 0.64 $ 0.87 $ (0.19 ) $ 0.60 Weighted Average Common Shares Outstanding: Basic 505 506 505 506 505 505 505 505 Diluted 508 508 508 508 508 508 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2016 2015 2016 2015 2016 2015 2016 2015 PSE&G: Millions Operating Revenues $ 1,712 $ 2,002 $ 1,350 $ 1,466 $ 1,684 $ 1,766 $ 1,475 $ 1,402 Operating Income $ 462 $ 451 $ 333 $ 320 $ 450 $ 404 $ 369 $ 287 Net Income $ 262 $ 242 $ 179 $ 167 $ 255 $ 222 $ 193 $ 156 Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 Power: Millions Operating Revenues $ 1,313 $ 1,725 $ 714 $ 1,025 $ 1,075 $ 1,096 $ 921 $ 1,082 Operating Income (Loss) $ 343 $ 584 $ (12 ) $ 228 $ 238 $ 391 $ (556 ) $ 227 Net Income (Loss) $ 192 $ 335 $ (11 ) $ 166 $ 139 $ 206 $ (302 ) $ 149 (A) The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
Power [Member] | |
Schedule of Quarterly Data [Line Items] | |
Selected Quarterly Data | Selected Quarterly Data (Unaudited) The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,616 $ 3,135 $ 1,905 $ 2,314 $ 2,450 $ 2,688 $ 2,090 $ 2,278 Operating Income $ 827 $ 1,048 $ 347 $ 568 $ 577 $ 814 $ (175 ) $ 532 Net Income (Loss) $ 471 $ 586 $ 187 $ 345 $ 327 $ 439 $ (98 ) $ 309 Earnings Per Share: Basic: Net Income (Loss) $ 0.93 $ 1.16 $ 0.37 $ 0.68 $ 0.65 $ 0.87 $ (0.19 ) $ 0.61 Diluted: Net Income (Loss) $ 0.93 $ 1.15 $ 0.37 $ 0.68 $ 0.64 $ 0.87 $ (0.19 ) $ 0.60 Weighted Average Common Shares Outstanding: Basic 505 506 505 506 505 505 505 505 Diluted 508 508 508 508 508 508 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2016 2015 2016 2015 2016 2015 2016 2015 PSE&G: Millions Operating Revenues $ 1,712 $ 2,002 $ 1,350 $ 1,466 $ 1,684 $ 1,766 $ 1,475 $ 1,402 Operating Income $ 462 $ 451 $ 333 $ 320 $ 450 $ 404 $ 369 $ 287 Net Income $ 262 $ 242 $ 179 $ 167 $ 255 $ 222 $ 193 $ 156 Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 Power: Millions Operating Revenues $ 1,313 $ 1,725 $ 714 $ 1,025 $ 1,075 $ 1,096 $ 921 $ 1,082 Operating Income (Loss) $ 343 $ 584 $ (12 ) $ 228 $ 238 $ 391 $ (556 ) $ 227 Net Income (Loss) $ 192 $ 335 $ (11 ) $ 166 $ 139 $ 206 $ (302 ) $ 149 (A) The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
Guarantees of Debt
Guarantees of Debt | 12 Months Ended |
Dec. 31, 2016 | |
Guarantees of Debt [Line Items] | |
Guarantees of Debt | Guarantees of Debt Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2016 and 2015 and for the years ended December 31, 2016 , 2015 and 2014 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,971 $ 173 $ (121 ) $ 4,023 Operating Expenses 8 3,962 161 (121 ) 4,010 Operating Income (Loss) (8 ) 9 12 — 13 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Other Income 71 120 — (89 ) 102 Other Deductions (18 ) (39 ) — — (57 ) Other-Than-Temporary Impairments — (28 ) — — (28 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 As of December 31, 2016 Current Assets $ 4,412 $ 1,593 $ 152 $ (4,697 ) $ 1,460 Property, Plant and Equipment, net 55 6,145 2,320 — 8,520 Investment in Subsidiaries 4,249 344 — (4,593 ) — Noncurrent Assets 168 2,016 129 (100 ) 2,213 Total Assets $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Current Liabilities $ 171 $ 3,752 $ 1,454 $ (4,697 ) $ 680 Noncurrent Liabilities 532 2,398 502 (100 ) 3,332 Long-Term Debt 2,382 — — — 2,382 Member’s Equity 5,799 3,948 645 (4,593 ) 5,799 Total Liabilities and Member’s Equity $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2015 Operating Revenues $ — $ 4,883 $ 179 $ (134 ) $ 4,928 Operating Expenses 12 3,451 169 (134 ) 3,498 Operating Income (Loss) (12 ) 1,432 10 — 1,430 Equity Earnings (Losses) of Subsidiaries 906 (4 ) 14 (902 ) 14 Other Income 48 174 — (53 ) 169 Other Deductions (27 ) (45 ) — — (72 ) Other-Than-Temporary Impairments — (53 ) — — (53 ) Interest Expense (116 ) (39 ) (19 ) 53 (121 ) Income Tax Benefit (Expense) 57 (574 ) 6 — (511 ) Net Income (Loss) $ 856 $ 891 $ 11 $ (902 ) $ 856 Comprehensive Income (Loss) $ 844 $ 855 $ 11 $ (866 ) $ 844 As of December 31, 2015 Current Assets $ 4,501 $ 1,912 $ 364 $ (4,828 ) $ 1,949 Property, Plant and Equipment, net 83 6,502 1,542 — 8,127 Investment in Subsidiaries 4,501 346 — (4,847 ) — Noncurrent Assets 155 1,959 136 (76 ) 2,174 Total Assets $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Current Liabilities $ 1,112 $ 3,866 $ 1,076 $ (4,828 ) $ 1,226 Noncurrent Liabilities 442 2,597 375 (76 ) 3,338 Long-Term Debt 1,684 — — — 1,684 Member’s Equity 6,002 4,256 591 (4,847 ) 6,002 Total Liabilities and Member’s Equity $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Year Ended December 31, 2015 Net Cash Provided By (Used In) Operating Activities $ 571 $ 2,089 $ 80 $ (1,034 ) $ 1,706 Net Cash Provided By (Used In) Investing Activities $ (366 ) $ (1,519 ) $ (430 ) $ 1,314 $ (1,001 ) Net Cash Provided By (Used In) Financing Activities $ (205 ) $ (571 ) $ 354 $ (280 ) $ (702 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2014 Operating Revenues $ — $ 5,390 $ 153 $ (109 ) $ 5,434 Operating Expenses 16 4,175 143 (109 ) 4,225 Operating Income (Loss) (16 ) 1,215 10 — 1,209 Equity Earnings (Losses) of Subsidiaries 799 (5 ) 14 (794 ) 14 Other Income 34 222 — (34 ) 222 Other Deductions (20 ) (32 ) — — (52 ) Other-Than-Temporary Impairments — (20 ) — — (20 ) Interest Expense (102 ) (35 ) (19 ) 34 (122 ) Income Tax Benefit (Expense) 65 (558 ) 2 — (491 ) Net Income (Loss) $ 760 $ 787 $ 7 $ (794 ) $ 760 Comprehensive Income (Loss) $ 595 $ 768 $ 7 $ (775 ) $ 595 Year Ended December 31, 2014 Net Cash Provided By (Used In) Operating Activities $ 577 $ 1,674 $ 76 $ (902 ) $ 1,425 Net Cash Provided By (Used In) Investing Activities $ 148 $ (856 ) $ (42 ) $ 226 $ (524 ) Net Cash Provided By (Used In) Financing Activities $ (724 ) $ (818 ) $ (32 ) $ 676 $ (898 ) |
Power [Member] | |
Guarantees of Debt [Line Items] | |
Guarantees of Debt | Guarantees of Debt Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2016 and 2015 and for the years ended December 31, 2016 , 2015 and 2014 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,971 $ 173 $ (121 ) $ 4,023 Operating Expenses 8 3,962 161 (121 ) 4,010 Operating Income (Loss) (8 ) 9 12 — 13 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Other Income 71 120 — (89 ) 102 Other Deductions (18 ) (39 ) — — (57 ) Other-Than-Temporary Impairments — (28 ) — — (28 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 As of December 31, 2016 Current Assets $ 4,412 $ 1,593 $ 152 $ (4,697 ) $ 1,460 Property, Plant and Equipment, net 55 6,145 2,320 — 8,520 Investment in Subsidiaries 4,249 344 — (4,593 ) — Noncurrent Assets 168 2,016 129 (100 ) 2,213 Total Assets $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Current Liabilities $ 171 $ 3,752 $ 1,454 $ (4,697 ) $ 680 Noncurrent Liabilities 532 2,398 502 (100 ) 3,332 Long-Term Debt 2,382 — — — 2,382 Member’s Equity 5,799 3,948 645 (4,593 ) 5,799 Total Liabilities and Member’s Equity $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2015 Operating Revenues $ — $ 4,883 $ 179 $ (134 ) $ 4,928 Operating Expenses 12 3,451 169 (134 ) 3,498 Operating Income (Loss) (12 ) 1,432 10 — 1,430 Equity Earnings (Losses) of Subsidiaries 906 (4 ) 14 (902 ) 14 Other Income 48 174 — (53 ) 169 Other Deductions (27 ) (45 ) — — (72 ) Other-Than-Temporary Impairments — (53 ) — — (53 ) Interest Expense (116 ) (39 ) (19 ) 53 (121 ) Income Tax Benefit (Expense) 57 (574 ) 6 — (511 ) Net Income (Loss) $ 856 $ 891 $ 11 $ (902 ) $ 856 Comprehensive Income (Loss) $ 844 $ 855 $ 11 $ (866 ) $ 844 As of December 31, 2015 Current Assets $ 4,501 $ 1,912 $ 364 $ (4,828 ) $ 1,949 Property, Plant and Equipment, net 83 6,502 1,542 — 8,127 Investment in Subsidiaries 4,501 346 — (4,847 ) — Noncurrent Assets 155 1,959 136 (76 ) 2,174 Total Assets $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Current Liabilities $ 1,112 $ 3,866 $ 1,076 $ (4,828 ) $ 1,226 Noncurrent Liabilities 442 2,597 375 (76 ) 3,338 Long-Term Debt 1,684 — — — 1,684 Member’s Equity 6,002 4,256 591 (4,847 ) 6,002 Total Liabilities and Member’s Equity $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Year Ended December 31, 2015 Net Cash Provided By (Used In) Operating Activities $ 571 $ 2,089 $ 80 $ (1,034 ) $ 1,706 Net Cash Provided By (Used In) Investing Activities $ (366 ) $ (1,519 ) $ (430 ) $ 1,314 $ (1,001 ) Net Cash Provided By (Used In) Financing Activities $ (205 ) $ (571 ) $ 354 $ (280 ) $ (702 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2014 Operating Revenues $ — $ 5,390 $ 153 $ (109 ) $ 5,434 Operating Expenses 16 4,175 143 (109 ) 4,225 Operating Income (Loss) (16 ) 1,215 10 — 1,209 Equity Earnings (Losses) of Subsidiaries 799 (5 ) 14 (794 ) 14 Other Income 34 222 — (34 ) 222 Other Deductions (20 ) (32 ) — — (52 ) Other-Than-Temporary Impairments — (20 ) — — (20 ) Interest Expense (102 ) (35 ) (19 ) 34 (122 ) Income Tax Benefit (Expense) 65 (558 ) 2 — (491 ) Net Income (Loss) $ 760 $ 787 $ 7 $ (794 ) $ 760 Comprehensive Income (Loss) $ 595 $ 768 $ 7 $ (775 ) $ 595 Year Ended December 31, 2014 Net Cash Provided By (Used In) Operating Activities $ 577 $ 1,674 $ 76 $ (902 ) $ 1,425 Net Cash Provided By (Used In) Investing Activities $ 148 $ (856 ) $ (42 ) $ 226 $ (524 ) Net Cash Provided By (Used In) Financing Activities $ (724 ) $ (818 ) $ (32 ) $ 676 $ (898 ) |
Valuation And Qualifying Accoun
Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
Valuation and Qualifying Accounts [Abstract] | |
Valuation And Qualifying Accounts | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2016 Allowance for Doubtful Accounts $ 67 $ 85 $ — $ 84 (A) $ 68 Materials and Supplies Valuation Reserve 11 32 — 6 (B) 37 2015 Allowance for Doubtful Accounts $ 52 $ 101 $ — $ 86 (A) $ 67 Materials and Supplies Valuation Reserve 15 2 — 6 (B) 11 2014 Allowance for Doubtful Accounts $ 56 $ 86 $ — $ 90 (A) $ 52 Materials and Supplies Valuation Reserve 8 9 — 2 (B) 15 (A) Accounts Receivable written off. (B) Reduced reserve to appropriate level and to remove obsolete inventory. PUBLIC SERVICE ELECTRIC AND GAS COMPANY Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2016 Allowance for Doubtful Accounts $ 67 $ 85 $ — $ 84 (A) $ 68 Materials and Supplies Valuation Reserve 1 — — 1 (B) — 2015 Allowance for Doubtful Accounts $ 52 $ 101 $ — $ 86 (A) $ 67 Materials and Supplies Valuation Reserve 2 — — 1 (B) 1 2014 Allowance for Doubtful Accounts $ 56 $ 86 $ — $ 90 (A) $ 52 Materials and Supplies Valuation Reserve — 2 — — 2 (A) Accounts Receivable written off. (B) Reduced reserve to appropriate level and to remove obsolete inventory. PSEG POWER LLC Column A Column B Column C Additions Column D Column E Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 2016 Materials and Supplies Valuation Reserve $ 10 $ 32 $ — $ 5 (A) $ 37 2015 Materials and Supplies Valuation Reserve $ 13 $ 2 $ — $ 5 (A) $ 10 2014 Materials and Supplies Valuation Reserve $ 8 $ 7 $ — $ 2 (A) $ 13 (A) Reduced reserve to appropriate level and to remove obsolete inventory. |
Organization, Basis Of Presen37
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis Of Presentation | Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP). |
Principles Of Consolidation | Principles of Consolidation Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 4. Variable Interest Entities . Entities over which the companies exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary, are accounted for under the equity method of accounting. For investments in which significant influence does not exist and the investor is not the primary beneficiary, the cost method of accounting is applied. All intercompany accounts and transactions are eliminated in consolidation. PSE&G and Power also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. PSE&G and Power consolidate their portion of any revenues and expenses related to their respective jointly-owned facilities in the appropriate revenue and expense categories. |
Accounting For The Effects Of Regulation | Accounting for the Effects of Regulation In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements reflect the economic effects of regulation. PSE&G defers the recognition of costs (a Regulatory Asset) or records the recognition of obligations (a Regulatory Liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any such costs or payment of liabilities becomes no longer probable as a result of changes in regulation and/or competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities . |
Derivative Financial Instruments | Derivative Instruments Each company uses derivative instruments to manage risk pursuant to its business plans and prudent practices. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing the contract’s market liquidity. PSEG has determined that contracts to purchase and sell certain products do not meet the definition of a derivative under the current authoritative guidance since they do not provide for net settlement, or the markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for derivatives that are designated as normal purchases and normal sales (NPNS). Further, derivatives that qualify for hedge accounting can be designated as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify or are not designated as cash flow or fair value hedges or as NPNS, changes in fair value are recorded in current period earnings. PSEG does not currently elect fair value or cash flow hedge accounting on its commodity derivative positions. Contracts that qualify for, and are designated, as NPNS are accounted for upon settlement. Contracts which qualify for NPNS are contracts for which physical delivery is probable, they will not be financially settled, and the quantities under contract are expected to be used or sold in the normal course of business over a reasonable period of time. For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities . |
Revenue Recognition | Revenue Recognition PSE&G’s regulated electric and gas revenues are recorded primarily based on services rendered to customers. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. Regulated revenues from the transmission of electricity are recognized as services are provided based on a FERC-approved annual formula rate mechanism. This mechanism provides for an annual filing of estimated revenue requirement with rates effective January 1 of each year. After completion of the annual period ending December 31, PSE&G files a true-up whereby it compares its actual revenue requirement to the original estimate to determine any over or under collection of revenue. PSE&G records the estimated financial statement impact of the difference between the actual and the filed revenue requirement as a refund or deferral for future recovery when such amounts are probable and can be reasonably estimated in accordance with accounting guidance for rate-regulated entities. The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of energy derivative contracts that are not designated as NPNS. See Note 16. Financial Risk Management Activities for further discussion. PJM Interconnection, L.L.C. (PJM), the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) facilitate the dispatch of energy and energy-related products. Power generally reports electricity sales and purchases conducted with those individual ISOs on a net hourly basis in either Revenues or Energy Costs in its Consolidated Statement of Operations, the classification of which depends on the net hourly activity. Capacity revenue and expense is also reported net based on Power’s monthly net sale or purchase position in the individual ISOs. PSEG LI is the primary beneficiary of Long Island Electric Utility Servco, LLC (Servco). For transactions in which Servco acts as principal, Servco records revenues and the related pass-through expenditures separately in Operating Revenues and Operations and Maintenance (O&M) Expense, respectively. See Note 4. Variable Interest Entities for further information. |
Depreciation And Amortization | Depreciation and Amortization PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU or FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2016 2015 2014 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.45 % 2.46 % 2.47 % Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are: • general plant assets— 3 years to 20 years • fossil production assets— 30 years to 70 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years |
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction | Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC) AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. IDC represents the cost of debt used to finance construction at Power. The amount of AFUDC or IDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2016 , 2015 and 2014 were as follows: AFUDC/IDC Capitalized 2016 2015 2014 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 66 7.81 % $ 65 8.01 % $ 44 8.09 % Power $ 54 4.87 % $ 27 5.14 % $ 24 5.14 % |
Income Taxes | Income Taxes PSEG and its subsidiaries file a consolidated federal income tax return and income taxes are allocated to PSEG’s subsidiaries based on the taxable income or loss of each subsidiary in accordance with a tax sharing agreement between PSEG and each of its affiliated subsidiaries. Allocations between PSEG and its subsidiaries are recorded through intercompany accounts. Investment tax credits deferred in prior years are being amortized over the useful lives of the related property. Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion. |
Impairment Of Long-Lived Assets | Impairment of Long-Lived Assets Management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, including prolonged periods of adverse commodity and capacity prices or a current expectation that a long-lived asset will be sold or disposed of significantly before the end of its previously estimated useful life, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset’s or asset group’s carrying amount exceeds the associated undiscounted estimated future cash flows, the asset/asset group is considered impaired to the extent that its fair value is less than its carrying amount. An impairment would result in a reduction of the value of the long-lived asset/asset group through a non-cash charge to earnings. See Note 3. Early Plant Retirements for more information. For Power, cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generation units are generally evaluated at a regional portfolio level (PJM, NYISO, ISO-NE) along with cash flows generated from the customer supply and risk management activities, inclusive of cash flows from contracts, including those that are accounted for as derivatives and meet the NPNS scope exception. In certain cases, generation assets are evaluated on an individual basis where those assets are individually contracted on a long-term basis with a third party and operations are independent of other generation assets (typically Power’s solar plants and Kalaeloa). |
Cash And Cash Equivalents | Cash and Cash Equivalents Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. |
Accounts Receivable-Allowance for Doubtful Accounts | Accounts Receivable—Allowance for Doubtful Accounts PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence. Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received. |
Materials And Supplies And Fuel | Materials and Supplies and Fuel PSE&G’s and Power’s materials and supplies are carried at average cost and charged to inventory when purchased and expensed or capitalized to Property, Plant and Equipment, as appropriate, when installed or used. Fuel inventory at Power is valued at the lower of average cost or market and includes stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged to Energy Costs when used or sold. The cost of nuclear fuel is capitalized within Property, Plant and Equipment and amortized to fuel expense using the units-of-production method. |
Property, Plant And Equipment | Property, Plant and Equipment PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation. Power capitalizes costs, including those related to its jointly-owned facilities, which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred. Power also capitalizes spare parts that meet specific criteria. Capitalized spares are depreciated over the remaining lives of their associated assets. |
Available-For-Sale Securities | Available-for-Sale Securities These securities comprise the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans. Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion. |
Pension And Other Postretirement Benefits (OPEB) Plan Assets | Pension and Other Postretirement Benefits (OPEB) Plans The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement date (December 31) for all plan assets. PSEG recognizes a long-term receivable primarily related to future funding by LIPA of Servco’s recognized pension and OPEB liabilities. This receivable is presented separately on the Consolidated Balance Sheet of PSEG as a noncurrent asset because it is restricted. Pursuant to the OSA, Servco records expense only to the extent of its contributions to its pension plan trusts and for OPEB payments made to retirees. See Note 12. Pension and Other Postretirement Benefits (OPEB) and Savings Plans for further discussion. |
Basis Adjustment | Basis Adjustment PSE&G and Power have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, $986 million , net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. The $986 million is an addition to PSE&G’s Common Stockholder’s Equity and a reduction of Power’s Member’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements. |
Use Of Estimates | Use of Estimates The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. |
New Accounting Standards | New Standards Issued and Adopted Stock Compensation-Improvements to Employee Share-Based Payment Accounting This accounting standard was issued to simplify aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Statement of Cash Flows. Under the new guidance, all excess tax benefits and tax deficiencies related to employee share-based payments will be recognized in income tax expense rather than recognized in additional paid in capital. In the Statement of Cash Flows, excess tax benefits and deficiencies will be classified with other income tax cash flows as an operating activity rather than a financing activity as currently classified. In addition, the minimum statutory tax withholding requirements were simplified in order to facilitate equity classification of the award. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early adoption is permitted for an entity in any interim or annual period. An entity that elects early adoption must adopt all of the amendments in the same period; however, the amendments within this update require different adoption methods. PSEG adopted this standard in the fourth quarter of 2016. The impact to the financial statements was immaterial. Disclosure for Investments in Certain Entities that Calculate Net Asset Value (NAV) per Share This accounting standard eliminates the requirement to categorize, in the fair value hierarchy, investments whose fair values are measured at NAV using the practical expedient provided in the fair value guidance. The practical expedient applies to investments in mutual funds or structures similar to a mutual fund for which there is not a readily determinable fair value. Although not required in the fair value hierarchy, sufficient information must be provided to allow for reconciliation between the fair value of assets categorized in the hierarchy and the balance sheet. The standard is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted. PSEG adopted this standard in the fourth quarter 2016 on a retrospective basis and has reflected the effect of the new disclosure requirements in Note 12. Pension, Other Postretirement Benefits (OPEB) and Savings Plan. Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern This accounting standard requires management to assess an entity’s ability to continue as a going concern and provide related disclosures in certain circumstances. These disclosures are only required when conditions give rise to substantial doubt about an entity’s ability to continue as a going concern within one year from the financial statement issuance date. The standard is effective for annual and interim periods beginning after December 15, 2016. PSEG adopted this standard in the fourth quarter of 2016; however, no disclosures were required this period based on the above criteria. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard clarifies the principles for recognizing revenue and removes inconsistencies in revenue recognition requirements; improves comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provides improved disclosures. The guidance provides a five-step model to be used for recognizing revenue for the transfer of promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted. PSEG expects the new guidance to result in more detailed disclosures of revenue compared to current guidance, and possibly changes in presentation. PSEG continues to evaluate all of its revenue streams and its contracts. Certain implementation issues continue to be debated and are currently being addressed by the AICPA’s Revenue Recognition Working Group and the FASB’s Transition Resource Group, including the ability to recognize revenue for certain contracts where there is uncertainty regarding collection from customers and accounting for contributions in aid of construction. As the ultimate impact of the new standard has not yet been determined, PSEG has not elected its transition method. Recognition and Measurement of Financial Assets and Financial Liabilities This accounting standard will change how entities measure equity investments that are not consolidated or accounted for under the equity method. Under the new guidance, equity investments (other than those accounted for using the equity method) will be measured at fair value through Net Income instead of Other Comprehensive Income (Loss). Entities that have elected the fair value option for financial liabilities will present changes in fair value due to a change in their own credit risk through Other Comprehensive Income (Loss). For equity investments which do not have readily determinable fair values, the impairment assessment will be simplified by requiring a qualitative assessment to identify impairments. The new standard also changes certain disclosures. The standard is effective for annual and interim reporting periods beginning after December 15, 2017. PSEG is currently analyzing the impact of this standard on our financial statements; however, PSEG expects increased volatility in Net Income due to changes in fair value of our equity securities within the NDT and Rabbi Trust Funds. Leases This accounting standard replaces existing lease accounting guidance and requires lessees to recognize all leases with a term greater than 12 months on the balance sheet using a right-of-use asset approach. At lease commencement, a lessee will recognize a lease asset and corresponding lease obligation. A lessee will classify its leases as either finance leases or operating leases based on whether control of the underlying assets has transferred to the lessee. A lessor will classify its leases as operating or direct financing leases, or as sales-type leases based on whether control of the underlying assets has transferred to the lessee. Both the lessee and lessor models require additional disclosure of key information. The standard requires lessees and lessors to apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. However, existing guidance related to leveraged leases will not change. The standard is effective for annual and interim periods beginning after December 15, 2018 with retrospective application to previously issued financial statements for 2018 and 2017. Early application is permitted. PSEG is currently analyzing the impact of this standard on its financial statements. Measurement of Credit Losses on Financial Instruments This accounting standard provides a new model for recognizing credit losses on financial assets carried at amortized cost. The new model requires entities to use an estimate of expected credit losses that will be recognized as an impairment allowance rather than a direct write-down of the amortized cost basis. The estimate of expected credit losses is to be based on past events, current conditions and supportable forecasts over a reasonable period. For purchased financial assets with credit deterioration, a similar model is to be used; however, the initial allowance will be added to the purchase price rather than reported as an allowance. Credit losses on available-for-sale securities should be measured in a manner similar to current GAAP; however, this standard requires those credit losses to be presented as an allowance, rather than a write-down. This new standard also requires additional disclosures of credit quality indicators for each class of financial asset disaggregated by year of origination. The standard is effective for annual and interim periods beginning after December 15, 2019; however, entities may adopt early beginning in the annual or interim periods after December 15, 2018. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments This accounting standard reduces the diversity in practice in how certain cash receipts and cash payments are presented and classified in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG is currently analyzing the impact of this standard on its financial statements. Statement of Cash Flows: Restricted Cash This accounting standard requires entities to explain the change during the period in the total of cash and cash equivalents and include amounts described as restricted cash or restricted cash equivalents in its reconciliation of beginning of period and end-of-period amounts in the Statement of Cash Flows. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt early including in an interim period. PSEG will include those amounts that are deemed to be restricted cash and restricted cash equivalents in its cash and cash equivalents balances in the statement of cash flows as well as disclosure regarding the nature of restricted amounts. Business Combinations: Clarifying the Definition of a Business This accounting standard was issued mainly to provide more consistency in how the definition of a business is applied to acquisitions or dispositions. The new guidance will generally reduce the number of transactions that will require treatment as a business combination. The definition of a business now includes a filter that would consider whether substantially all the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets. If this condition is met, the transaction would not qualify as a business. The standard is effective for annual and interim periods beginning after December 15, 2017; however, entities may adopt it for transactions that have closed before the effective date but have not been reported in financial statements that have been issued or made available for issuance. PSEG is currently evaluating the impact of this standard on its financial statements; however, PSEG does not expect this guidance to materially impact its financial statements upon adoption. Simplifying the Test for Goodwill Impairment This accounting standard requires an entity to perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. An entity should apply this standard on a prospective basis and will be required to disclose the nature of and reason for the change in accounting principle upon transition. The new standard is effective for impairment tests for periods beginning January 1, 2020. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. PSEG is currently assessing the impact of this guidance upon its financial statements. |
Organization, Basis Of Presen38
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Depreciation Rate Stated Percentage | The depreciation rate stated as a percentage of original cost of depreciable property was as follows: 2016 2015 2014 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.45 % 2.46 % 2.47 % |
Amounts And Average Rates Used To Calculate IDC Or AFUDC | The amounts and average rates used to calculate AFUDC or IDC for the years ended December 31, 2016 , 2015 and 2014 were as follows: AFUDC/IDC Capitalized 2016 2015 2014 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 66 7.81 % $ 65 8.01 % $ 44 8.09 % Power $ 54 4.87 % $ 27 5.14 % $ 24 5.14 % |
Early Plant Retirements Early39
Early Plant Retirements Early Plant Retirements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Power [Member] | |
Restructuring Cost and Reserve [Line Items] | |
Early Plant Retirements Related Costs [Table Text Block] | In 2016, PSEG and Power recognized the following pre-tax charges in Energy Costs, Operation and Maintenance and Depreciation expense during the period following the announcement of the early retirement of the plants: Year Ended December 31, 2016 Millions Statement of Operations Expense (pre-tax) Energy Costs Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties $ 62 Operation and Maintenance Materials and Supplies Obsolescence 31 Write-down of Construction Work in Progress 14 Other (A) 8 Depreciation and Amortization Depreciation including Asset Retirement Costs 571 Total Pre-Tax Expense $ 686 |
Property, Plant And Equipment40
Property, Plant And Equipment And Jointly-Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule Of Property, Plant And Equipment | Information related to Property, Plant and Equipment as of December 31, 2016 and 2015 is detailed below: PSE&G Power Other PSEG Consolidated Millions 2016 Transmission and Distribution: Electric Transmission $ 9,132 $ — $ — $ 9,132 Electric Distribution 7,974 — — 7,974 Gas Transmission 89 — — 89 Gas Distribution 6,369 — — 6,369 Construction Work in Progress 1,501 — — 1,501 Plant Held for Future Use 19 — — 19 Other 439 — — 439 Total Transmission and Distribution 25,523 — — 25,523 Generation: Fossil Production — 7,096 — 7,096 Nuclear Production — 2,516 — 2,516 Nuclear Fuel in Service — 783 — 783 Other Production-Solar 591 687 — 1,278 Construction Work in Progress — 1,483 — 1,483 Total Generation 591 12,565 — 13,156 Other 233 90 335 658 Total $ 26,347 $ 12,655 $ 335 $ 39,337 PSE&G Power Other PSEG Consolidated Millions 2015 Transmission and Distribution: Electric Transmission $ 7,554 $ — $ — $ 7,554 Electric Distribution 7,553 — — 7,553 Gas Transmission 89 — — 89 Gas Distribution 5,875 — — 5,875 Construction Work in Progress 1,459 — — 1,459 Plant Held for Future Use 26 — — 26 Other 411 — — 411 Total Transmission and Distribution 22,967 — — 22,967 Generation: Fossil Production — 7,005 — 7,005 Nuclear Production — 2,202 — 2,202 Nuclear Fuel in Service — 785 — 785 Other Production-Solar 569 389 — 958 Construction Work in Progress — 892 — 892 Total Generation 569 11,273 — 11,842 Other 196 81 408 685 Total $ 23,732 $ 11,354 $ 408 $ 35,494 |
Schedule Of Jointly-Owned Facilities | As of December 31, 2016 2015 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 169 $ 65 $ 166 $ 72 Power: Coal Generating: Conemaugh 23 % $ 408 $ 166 $ 404 $ 154 Keystone 23 % $ 409 $ 176 $ 408 $ 163 Nuclear Generating: Peach Bottom 50 % $ 1,272 $ 306 $ 1,219 $ 262 Salem 57 % $ 1,077 $ 304 $ 990 $ 276 Nuclear Support Facilities Various $ 238 $ 71 $ 226 $ 60 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 25 $ 42 $ 24 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. |
Regulatory Assets And Liabili41
Regulatory Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets | PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Weather Normalization Clause (WNC) 49 10 Annual filing for recovery (2) Underrecovered Electric Energy Costs—Basic Generation Service 2 11 Annual filing for recovery (1) (2) Other 6 1 Various Total Current Regulatory Assets $ 199 $ 164 Noncurrent Pension and OPEB Costs $ 1,403 $ 1,270 Various Deferred Income Taxes 507 467 Various Manufactured Gas Plant (MGP) Remediation Costs 403 431 Various (2) Storm Damage Deferrals 239 233 To be determined Electric Transmission and Gas Cost of Removal 189 160 Through depreciation rates Remediation Adjustment Charge (RAC) (Other SBC) 180 174 Through 2022 (1) (2) Conditional Asset Retirement Obligation 157 152 Various Green Program Recovery Charges (GPRC) 91 104 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 61 67 Over remaining debt life Mark-to-Market (MTM) Contracts — 63 Through 2017 Other 89 75 Various Total Noncurrent Regulatory Assets $ 3,319 $ 3,196 Total Regulatory Assets $ 3,518 $ 3,360 |
Schedule of Regulatory Liabilities | As of December 31, 2016 2015 Recovery/Refund Period Millions Regulatory Liabilities Current FERC Formula Rate True-up $ 34 $ 19 Annual filing for recovery (1) (2) GPRC 28 36 Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 11 13 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 6 1 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 5 1 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 4 31 Various (1) (2) Stranded Costs (including $42 in 2015 related to VIEs) — 64 Through December 2016 (2) Total Current Regulatory Liabilities $ 88 $ 165 Noncurrent Electric Distribution Cost of Removal $ 94 $ 122 Through depreciation rates MTM Contracts 20 — Various FERC Formula Rate True-up 1 49 Annual filing for recovery (1) (2) Other 3 4 Various Total Noncurrent Regulatory Liabilities $ 118 $ 175 Total Regulatory Liabilities $ 206 $ 340 (1) Recovered/Refunded with interest. (2) Recoverable/Refundable per specific rate order. |
Long-Term Investments (Tables)
Long-Term Investments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Long-term Investments [Abstract] | |
Schedule of Long Term Investments | Long-Term Investments as of December 31, 2016 and 2015 included the following: As of December 31, 2016 2015 Millions PSE&G Life Insurance and Supplemental Benefits $ 140 $ 150 Solar Loans 159 175 Other Investments — 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 102 119 Energy Holdings Lease Investments 649 784 Total Long-Term Investments $ 1,050 $ 1,233 (A) During the three years ended December 31, 2016 , 2015 and 2014 , dividends from these investments were $18 million , $16 million and $17 million , respectively. |
Schedule Of Net Investment In Leveraged Leases | The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2016 and 2015 , respectively. As of December 31, 2016 2015 Millions Lease Receivables (net of Non-Recourse Debt) $ 629 $ 631 Estimated Residual Value of Leased Assets 346 519 Total Investment in Rental Receivables 975 1,150 Unearned and Deferred Income (326 ) (366 ) Gross Investments in Leases 649 784 Deferred Tax Liabilities (674 ) (724 ) Net Investments in Leases $ (25 ) $ 60 |
Schedule Of Pre-Tax Income And Income Tax Effects Related To Investments In Leveraged Leases | The pre-tax income (loss) and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2016 2015 2014 Millions Pre-Tax Income (Loss) from Leases $ (135 ) $ 12 $ 24 Income Tax Expense (Benefit) on Income from Leases $ (51 ) $ 5 $ 32 |
Equity Method Investments | Equity Method Investments Power had the following equity method investments as of December 31, 2016 and 2015 : As of December 31, Name 2016 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 7 $ 16 PA 23% Conemaugh Fuels, LLC $ 8 $ 14 PA 23% PennEast Pipeline $ 11 $ 5 PA 10% Kalaeloa $ 76 $ 84 HI 50% |
Financing Receivables (Tables)
Financing Receivables (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
PSE&G [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Schedule Of Credit Risk Profile Based On Payment Activity | The following table reflects the outstanding loans, including the noncurrent portion reported in Note 7. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Outstanding Loans by Class of Customer As of December 31, Consumer Loans 2016 2015 Millions Commercial/Industrial $ 164 $ 177 Residential 11 12 Total $ 175 $ 189 |
Energy Holdings [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating | The corresponding receivables associated with the lease portfolio are reflected as follows, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Lease Receivables, Net of Non-Recourse Debt Counterparties’ Credit Rating Standard & Poor’s (S&P) as of December 31, 2016 As of December 31, 2016 Millions AA $ 16 BBB+ — BBB- 316 BB- 133 CCC 164 Total $ 629 |
Schedule Of Assets Under Lease Receivables | A more detailed description of such assets under lease is presented in the following table. Asset Location Gross Investment % Owned Total MW Fuel Type Counterparties’ S&P Credit Ratings Counterparty Millions Powerton Station Units 5 and 6 IL $ 134 64 % 1,538 Coal BB- NRG Energy, Inc. Joliet Station Units 7 and 8 IL $ 83 64 % 1,036 Gas BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Conemaugh Station Units 1 and 2 PA $ 55 17 % 1,711 Coal CCC (A) REMA Shawville Station Units 1, 2, 3 and 4 PA $ 99 100 % 596 Gas CCC (A) REMA |
Available-for-Sale Securities (
Available-for-Sale Securities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Nuclear Decommissioning Trust (NDT) Fund [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Schedule of Available-for-sale Securities Reconciliation | The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 705 $ 263 $ (11 ) $ 957 Debt Securities Government 518 8 (6 ) 520 Corporate 337 4 (4 ) 337 Total Debt Securities 855 12 (10 ) 857 Other Securities 44 — — 44 Total NDT Available-for-Sale Securities (A) $ 1,604 $ 275 $ (21 ) $ 1,858 (A) The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund. As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government 483 8 (3 ) 488 Corporate 366 3 (10 ) 359 Total Debt Securities 849 11 (13 ) 847 Other Securities 42 — — 42 Total NDT Available-for-Sale Securities $ 1,584 $ 196 $ (26 ) $ 1,754 |
Schedule Of Accounts Receivable And Accounts Payable | The amounts in the preceding tables do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 8 $ 17 Accounts Payable $ 5 $ 10 |
Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months | The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months. As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ 120 $ (10 ) $ 8 $ (1 ) $ 151 $ (13 ) $ 1 $ — Debt Securities Government (B) 276 (6 ) 4 — 245 (2 ) 19 (1 ) Corporate (C) 139 (3 ) 15 (1 ) 222 (7 ) 36 (3 ) Total Debt Securities 415 (9 ) 19 (1 ) 467 (9 ) 55 (4 ) NDT Available-for-Sale Securities $ 535 $ (19 ) $ 27 $ (2 ) $ 618 $ (22 ) $ 56 $ (4 ) (A) Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2016 . (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 |
Amount Of Available-For-Sale Debt Securities By Maturity Periods | The available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 15 1 - 5 years 257 6 - 10 years 193 11 - 15 years 50 16 - 20 years 60 Over 20 years 282 Total NDT Available-for-Sale Debt Securities $ 857 |
Schedule of Realized Gain (Loss) | The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Sales (A) $ 711 $ 1,397 $ 1,448 Net Realized Gains (Losses): Gross Realized Gains $ 53 $ 97 $ 177 Gross Realized Losses (32 ) (37 ) (23 ) Net Realized Gains (Losses) on NDT Fund $ 21 $ 60 $ 154 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. |
Rabbi Trust [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Schedule of Available-for-sale Securities Reconciliation | PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust. As of December 31, 2016 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 11 $ 11 $ — $ 22 Debt Securities Government 105 — (2 ) 103 Corporate 92 1 (2 ) 91 Total Debt Securities 197 1 (4 ) 194 Other Securities 1 — — 1 Total Rabbi Trust Available-for-Sale Securities $ 209 $ 12 $ (4 ) $ 217 As of December 31, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government 108 1 (1 ) 108 Corporate 82 — (1 ) 81 Total Debt Securities 190 1 (2 ) 189 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 204 $ 11 $ (2 ) $ 213 |
Schedule Of Accounts Receivable And Accounts Payable | The amounts in the preceding tables do not include receivables and payables for Rabbi Trust Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table. As of December 31, 2016 As of December 31, 2015 Millions Accounts Receivable $ 5 $ 1 Accounts Payable $ 3 $ — |
Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months | The following table shows the value of securities in the Rabbi Trust Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months: As of December 31, 2016 As of December 31, 2015 Less Than 12 Months Greater Than 12 Months Less Than 12 Months Greater Than 12 Months Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Fair Value Gross Unrealized Losses Millions Equity Securities (A) $ — $ — $ — $ — $ — $ — $ — $ — Debt Securities Government (B) 60 (2 ) 1 — 53 (1 ) 2 — Corporate (C) 46 (2 ) 3 — 46 (1 ) 9 — Total Debt Securities 106 (4 ) 4 — 99 (2 ) 11 — Rabbi Trust Available-for-Sale Securities $ 106 $ (4 ) $ 4 $ — $ 99 $ (2 ) $ 11 $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. (B) Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 . (C) Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016 |
Amount Of Available-For-Sale Debt Securities By Maturity Periods | The Rabbi Trust available-for-sale debt securities held as of December 31, 2016 had the following maturities: Time Frame Fair Value Millions Less than one year $ 8 1 - 5 years 44 6 - 10 years 44 11 - 15 years 9 16 - 20 years 8 Over 20 years 81 Total Rabbi Trust Available-for-Sale Debt Securities $ 194 |
Schedule of Realized Gain (Loss) | The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2016 2015 2014 Millions Proceeds from Rabbi Trust Sales (A) $ 113 $ 104 $ 467 Net Realized Gains (Losses): Gross Realized Gains $ 6 $ 3 $ 4 Gross Realized Losses (5 ) (2 ) (3 ) Net Realized Gains (Losses) on Rabbi Trust $ 1 $ 1 $ 1 (A) Includes activity in accounts related to the liquidation of funds being transitioned to new managers. |
Rabbi Trust Fair Value by Company | The fair value of the Rabbi Trust related to PSEG, PSE&G and Power are detailed as follows: As of December 31, 2016 As of December 31, 2015 Millions PSE&G $ 43 $ 42 Power 53 52 Other 121 119 Total Rabbi Trust Available-for-Sale Securities $ 217 $ 213 |
Goodwill And Other Intangibles
Goodwill And Other Intangibles (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Power [Member] | |
Goodwill [Line Items] | |
Expenses Related To Emissions And Renewable Energy Requirements | Such expenses for the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, 2016 2015 2014 Millions Emissions Expense $ 14 $ 13 $ 10 Renewable Energy Expense $ 95 $ 91 $ 59 |
Asset Retirement Obligations 46
Asset Retirement Obligations (AROs) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
Impact Of The Revisions On Asset Retirement Obligation | The changes to the ARO liabilities for PSEG, PSE&G and Power during 2015 and 2016 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2015 $ 743 $ 290 $ 450 $ 3 Liabilities Settled (5 ) (4 ) (1 ) — Liabilities Incurred 14 1 12 1 Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 16 16 — — Revision to Present Values of Estimated Cash Flows (115 ) (85 ) (30 ) — ARO Liability as of December 31, 2015 $ 679 $ 218 $ 457 $ 4 Liabilities Settled (13 ) (9 ) (4 ) — Liabilities Incurred 25 2 23 — Accretion Expense 26 — 26 — Accretion Expense Deferred and Recovered in Rate Base (A) 12 12 — — Revision to Present Values of Estimated Cash Flows (3 ) (10 ) 9 (2 ) ARO Liability as of December 31, 2016 $ 726 $ 213 $ 511 $ 2 (A) Not reflected as expense in Consolidated Statements of Operations |
Pension, OPEB and Savings Pla47
Pension, OPEB and Savings Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract] | |
Schedule of Defined Benefit Plans Disclosures | The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Service Cost 109 123 17 22 Interest Cost 202 234 59 67 Actuarial (Gain) Loss (B) 219 (289 ) 127 (45 ) Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Plan Amendments 2 — (4 ) — Benefit Obligation at End of Year (A) $ 5,772 $ 5,522 $ 1,754 $ 1,612 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,039 $ 5,293 $ 374 $ 361 Actual Return on Plan Assets 403 (11 ) 32 (1 ) Employer Contributions 33 25 71 84 Gross Benefits Paid (282 ) (268 ) (57 ) (70 ) Fair Value of Assets at End of Year $ 5,193 $ 5,039 $ 420 $ 374 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ — $ 14 $ — $ — Current Accrued Benefit Cost (11 ) (10 ) (10 ) (10 ) Noncurrent Accrued Benefit Cost (568 ) (487 ) (1,324 ) (1,228 ) Amounts Recognized $ (579 ) $ (483 ) $ (1,334 ) $ (1,238 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (B) Prior Service Cost $ (63 ) $ (83 ) $ (14 ) $ (25 ) Net Actuarial Loss 1,763 1,710 523 438 Total $ 1,700 $ 1,627 $ 509 $ 413 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Includes $ 679 million ($ 398 million , after-tax) and $ 658 million ($ 386 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2016 and 2015 , respectively. The following table provides a roll-forward of the changes in Servco’s benefit obligation and the fair value of its plan assets during the years ended December 31, 2016 and 2015 . It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years. Pension Benefits Other Benefits 2016 2015 2016 2015 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 211 $ 195 $ 375 $ 452 Service Cost 24 26 12 17 Interest Cost 9 9 17 21 Actuarial (Gain) Loss 14 (20 ) 50 (114 ) Gross Benefits Paid (1 ) — (2 ) (1 ) Plan Amendments 5 1 — — Benefit Obligation at End of Year (A) $ 262 $ 211 $ 452 $ 375 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 97 $ 69 $ — $ — Actual Return on Plan Assets 10 (2 ) — — Employer Contributions 28 30 2 1 Gross Benefits Paid (1 ) — (2 ) (1 ) Fair Value of Assets at End of Year $ 134 $ 97 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (128 ) $ (114 ) $ (452 ) $ (375 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (128 ) $ (114 ) N/A N/A OPEB Costs of Servco N/A N/A (452 ) (375 ) Amounts Recognized (B) $ (128 ) $ (114 ) $ (452 ) $ (375 ) (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. |
Components Of Net Periodic Benefit Cost | The following table provides the components of net periodic benefit cost for the years ended December 31, 2016 , 2015 and 2014 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 109 $ 123 $ 104 $ 17 $ 22 18 Interest Cost 202 234 234 59 67 69 Expected Return on Plan Assets (394 ) (414 ) (399 ) (31 ) (31 ) (26 ) Amortization of Net Prior Service Credit (19 ) (19 ) (18 ) (14 ) (14 ) (14 ) Actuarial Loss 158 150 56 40 43 23 Net Periodic Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 |
Schedule Of Pension And OPEB Costs | Pension costs and OPEB costs for PSEG, PSE&G and Power are detailed as follows: Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions PSE&G $ 29 $ 40 $ (19 ) $ 43 $ 55 $ 46 Power 16 21 (7 ) 23 27 20 Other 11 13 3 5 5 4 Total Benefit Cost (Credit) $ 56 $ 74 $ (23 ) $ 71 $ 87 $ 70 |
Schedule of Amounts Recognized in Other Comprehensive Income (Loss) | The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2016 2015 2016 2015 Millions Net Actuarial (Gain) Loss in Current Period $ 211 $ 136 $ 125 $ (14 ) Amortization of Net Actuarial Gain (Loss) (158 ) (150 ) (40 ) (43 ) Prior Service Cost (Credit) in current period 1 — (3 ) — Amortization of Prior Service Credit 19 19 14 14 Total $ 73 $ 5 $ 96 $ (43 ) |
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year | Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2017 are as follows: Pension Benefits Other Benefits 2017 2017 Millions Actuarial (Gain) Loss $ 97 $ 51 Prior Service Cost $ (18 ) $ (11 ) |
Schedule of Assumptions Used | The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.29 % 4.54 % 4.20 % 4.37 % 4.58 % 4.21 % Rate of Compensation Increase 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % 3.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Service Cost Interest Rate 4.81 % 4.20 % 5.00 % 4.87 % 4.21 % 5.01 % Interest Cost Interest Rate 3.75 % 4.20 % 5.00 % 3.76 % 4.21 % 5.01 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 3.00 % 3.00 % 3.00 % Health Care Costs Immediate Rate 7.55 % 7.75 % 7.40 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2022 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 11 $ 12 $ 13 Postretirement Benefit Obligation $ 191 $ 194 $ 201 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (9 ) $ (10 ) $ (10 ) Postretirement Benefit Obligation $ (160 ) $ (160 ) $ (165 ) The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2016 2015 2014 2016 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.61 % 4.92 % 4.50 % 4.71 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.55 % 7.33 % Ultimate Rate 4.75 % 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 97 $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (75 ) $ (60 ) $ (106 ) |
Schedule of Allocation of Plan Assets | The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 70 % 70 % Fixed Income Securities 28 28 Other Investments 2 2 Total Percentage 100 % 100 % The following tables present information about Servco’s investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 96 $ — $ 96 $ — Commingled Bonds (A) 38 — 38 — Total $ 134 $ — $ 134 $ — Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Commingled Equities (A) $ 68 $ — $ 68 $ — Commingled Bonds (A) 29 — 29 — Total $ 97 $ — $ 97 $ — (A) Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as Level 2. |
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets | The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2016 and 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Recurring Fair Value Measurements as of December 31, 2016 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 107 $ 105 $ 2 $ — Equities (B) Common Stock 944 944 — — Commingled (C) 1,387 1,247 140 — Preferred Stock 1 1 — — Bonds (D) US Treasury 441 — 441 — Government—Other 263 — 263 — Corporate 836 — 836 — Subtotal Fair Value $ 3,979 $ 2,297 $ 1,682 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,604 Private Equity (E) 16 Total Fair Value (F) $ 5,599 Recurring Fair Value Measurements as of December 31, 2015 Quoted Market Prices for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Description Total (Level 1) (Level 2) (Level 3) Millions Cash Equivalents (A) $ 96 $ 95 $ 1 $ — Equities (B) Common Stock 816 816 — — Commingled (C) 1,463 1,269 194 — Bonds (D) US Treasury 322 — 322 — Government—Other 279 — 279 — Corporate 906 — 906 — Subtotal Fair Value $ 3,882 $ 2,180 $ 1,702 $ — Measured at net asset value practical expedient (C) Commingled—Equities 1,504 Private Equity (E) 19 Total Fair Value (F) $ 5,405 (A) Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2. (C) In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. See Note 2. Recent Accounting Standards . These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015. (D) Fixed income securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. (E) Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. (F) Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015 , respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. |
Schedule Of Percentage Of Fair Value Of Total Plan Assets | The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans of Servco as of the measurement date, December 31: As of December 31, Investments 2016 2015 Equity Securities 71 % 71 % Fixed Income Securities 29 29 Total Percentage 100 % 100 % |
Schedule of Expected Benefit Payments | The following pension benefit and postretirement benefit payments are expected to be paid to Servco’s plan participants: Year Pension Benefits Other Benefits Millions 2017 $ 2 $ 4 2018 3 6 2019 5 9 2020 7 11 2021 8 13 2022-2026 76 96 Total $ 101 $ 139 The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2017 $ 310 $ 82 2018 307 86 2019 319 90 2020 331 94 2021 343 99 2022-2026 1,887 534 Total $ 3,497 $ 985 |
Schedule Of Amount Paid For Employer Matching Contributions | The amount paid for employer matching contributions to the plans for PSEG, PSE&G and Power are detailed as follows: Thrift Plan and Savings Plan Years Ended December 31, 2016 2015 2014 Millions PSE&G $ 24 $ 22 $ 20 Power 12 12 11 Other 5 5 5 Total Employer Matching Contributions $ 41 $ 39 $ 36 |
Commitments and Contingent Li48
Commitments and Contingent Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Commitments [Line Items] | |
Future Minimum Rental Payments | The total future minimum payments under various operating leases as of December 31, 2016 are: PSE&G Power Services Other Total Millions 2017 $ 12 $ 3 $ 13 $ 1 $ 29 2018 8 3 13 1 25 2019 7 3 13 1 24 2020 6 2 13 1 22 2021 6 2 14 1 23 Thereafter 61 39 132 — 232 Total Minimum Lease Payments $ 100 $ 52 $ 198 $ 5 $ 355 |
PSE&G [Member] | |
Other Commitments [Line Items] | |
Contract For Anticipated BGS-Fixed Price Eligible Load | The contract prices in dollars per MWh for the BGS-RSCP supply, as well as the approximate load, are as follows: Auction Year 2014 2015 2016 2017 36-Month Terms Ending May 2017 May 2018 May 2019 May 2020 (A) Load (MW) 2,800 2,900 2,800 2,800 $ per MWh $97.39 $99.54 $96.38 $90.78 (A) Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire. |
Power [Member] | |
Other Commitments [Line Items] | |
Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions | The following table shows the face value of Power’s outstanding guarantees, current exposure and margin positions as of December 31, 2016 and 2015 . As of December 31, 2016 As of December 31, 2015 Millions Face Value of Outstanding Guarantees $ 1,806 $ 1,734 Exposure under Current Guarantees $ 139 $ 172 Letters of Credit Margin Posted $ 157 $ 122 Letters of Credit Margin Received $ 99 $ 192 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (1 ) $ (15 ) Net Broker Balance Deposited (Received) $ 57 $ (5 ) Additional Amounts Posted Other Letters of Credit $ 51 $ 51 |
Total Minimum Purchase Commitments | As of December 31, 2016 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2021 Millions Nuclear Fuel Uranium $ 301 Enrichment $ 356 Fabrication $ 192 Natural Gas $ 1,029 Coal $ 215 |
Insurance coverages and maximum retrospective assessments for its nuclear operations | Power’s insurance coverages and maximum retrospective assessments for its nuclear operations as of December 31, 2016 were as follows: Type and Source of Coverages Site Coverage Retrospective Assessments Millions Public and Nuclear Worker Liability (Primary Layer): ANI $ 375 (A) $ — Nuclear Liability (Excess Layer): Price-Anderson Act 12,986 (B) 401 Nuclear Liability Total $ 13,361 (C) $ 401 Property Damage (Primary Layer): NEIL Primary (Salem/Hope Creek) $ 1,500 $ 35 NEIL Primary (Peach Bottom) $ 1,500 14 Property Damage (Excess Layers): NEIL Excess (Salem/Hope Creek - Nuclear) $ 300 (D) 2 NEIL Excess (Peach Bottom - Nuclear) $ 300 (D) 1 NEIL Excess (Salem/Hope Creek - Non - Nuclear) $ 300 (D) 1 NEIL Excess (Peach Bottom - Non - Nuclear) $ 600 (D) 1 Accidental Outage - PSEG Share:(Nuclear / Non-Nuclear) NEIL I (Peach Bottom) $245 / $164 (E) 8 NEIL I (Salem) $281 / $188 (E) 9 NEIL I (Hope Creek) $490 / $328 (E) 7 Nuclear Property Total $ 78 (A) The primary limit for Public Liability is a per site aggregate limit with no potential for retrospective assessment. The Nuclear Worker Liability represents the potential liability from third-party workers claiming exposure to the nuclear energy hazard. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion. (B) Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers. (C) Maximum limit of liability under the Price-Anderson Act for each nuclear incident per site. (D) For nuclear event property limits in excess of $1.5 billion , Power purchases a $300 million Excess Policy for the Salem/Hope Creek site, and a $300 million Excess Policy only for Power’s 50% interest in Peach Bottom. This limit is not subject to reinstatement in the event of a loss. In addition, for non-nuclear event limits in excess of $1.5 billion , Power maintains a $300 million limit for the combined Salem/Hope Creek sites. Exelon maintains a $600 million non-nuclear event limit for Peach Bottom . (E) Peach Bottom 2 and 3 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Peach Bottom 2 and 3 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 24 weeks. Salem 1 and 2 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 weeks. Salem 1 and 2 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 29 weeks. Hope Creek has an aggregate nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. Hope Creek has an aggregate non-nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 26 weeks. |
Schedule Of Consolidated Debt (
Schedule Of Consolidated Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt As of December 31, Maturity 2016 2015 Millions PSEG Term Loan: Variable 2017 $ 500 $ 500 Total Term Loan 500 500 Senior Notes: 1.60% 2019 400 — 2.00% 2021 300 — Total Senior Notes 700 — Principal Amount Outstanding 1,200 500 Fair Value of Swaps (A) — 6 Amounts Due Within One Year (500 ) (6 ) Net Unamortized Discount and Debt Issuance Costs (5 ) — Total Long-Term Debt of PSEG $ 695 $ 500 ` As of December 31, Maturity 2016 2015 Millions PSE&G First and Refunding Mortgage Bonds (B): 6.75% 2016 $ — $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 149 320 Pollution Control Bonds (B): Floating Rate (C) 2033 — 50 Floating Rate (C) 2046 — 50 Total Pollution Control Bonds — 100 Medium-Term Notes (MTNs) (B): 5.30% 2018 400 400 2.30% 2018 350 350 1.80% 2019 250 250 2.00% 2019 250 250 7.04% 2020 9 9 3.50% 2020 250 250 1.90% 2021 300 — 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 350 2.25% 2026 425 — 5.25% 2035 250 250 5.70% 2036 250 250 5.80% 2037 350 350 5.38% 2039 250 250 5.50% 2040 300 300 3.95% 2042 450 450 3.65% 2042 350 350 3.80% 2043 400 400 4.00% 2044 250 250 4.05% 2045 250 250 4.15% 2045 250 250 3.80% 2046 550 — Total MTNs 7,734 6,459 Principal Amount Outstanding 7,883 6,879 Amounts Due Within One Year — (171 ) Net Unamortized Discount and Debt Issuance Costs (65 ) (58 ) Total Long-Term Debt of PSE&G $ 7,818 $ 6,650 As of December 31, Maturity 2016 2015 Millions Power Senior Notes: 5.32% 2016 $ — $ 303 2.75% 2016 — 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 3.00% 2021 700 — 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,356 2,209 Pollution Control Notes: Floating Rate (C) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,400 2,253 Amounts Due Within One Year — (553 ) Net Unamortized Discount and Debt Issuance Costs (18 ) (16 ) Total Long-Term Debt of Power $ 2,382 $ 1,684 (A) PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities . (B) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (C) The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode. |
Aggregate Principal Amounts Of Maturities | The aggregate principal amounts of maturities for each of the five years following December 31, 2016 are as Year PSEG PSE&G Power Total 2017 $ 500 $ — $ — $ 500 2018 — 750 250 1,000 2019 400 500 44 944 2020 — 259 406 665 2021 300 434 950 1,684 Thereafter — 5,940 750 6,690 Total $ 1,200 $ 7,883 $ 2,400 $ 11,483 |
Short-Term Liquidity | total credit facilities and available liquidity as of December 31, 2016 were as follows: As of December 31, 2016 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Mar 2019 Commercial Paper Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 388 112 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 398 $ 602 PSE&G 5-year Credit Facility (B) $ 600 $ 14 $ 586 Apr 2020 Commercial Paper Support/Funding/Letters of Credit Total PSE&G $ 600 $ 14 $ 586 Power 5-year Credit Facility $ 1,600 $ 195 $ 1,405 Mar 2019 Funding/Letters of Credit 5-year Credit Facility (C) 953 3 950 Apr 2020 Funding/Letters of Credit Total Power $ 2,553 $ 198 $ 2,355 Total $ 4,153 $ 610 $ 3,543 (A) PSEG facility will be reduced by $12 million in March 2018. (B) PSE&G facility will be reduced by $14 million in March 2018. (C) Power facility will be reduced by $24 million in March 2018. (D) The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2016 , PSEG had $388 million outstanding at a weighted average interest rate of 1.03% . PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016 . |
Estimated Fair Values | December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (A) (B) $ 1,195 $ 1,185 $ 503 $ 506 PSE&G (B) 7,818 8,240 6,821 7,235 Power - Recourse Debt (B) 2,382 2,578 2,237 2,508 Energy Holdings: Project Level, Non-Recourse Debt (C) — — 7 7 $ 11,395 $ 12,003 $ 9,568 $ 10,256 (A) Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. (B) Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. (C) Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Schedule Of Consolidated Capi50
Schedule Of Consolidated Capital Stock (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Class of Stock Disclosures [Abstract] | |
Schedule Of Consolidated Capital Stock | As of December 31, Outstanding Shares Book Value 2016 2015 2016 2015 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 504,866,212 505,282,421 $ 4,219 $ 4,244 (A) PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2016 or 2015 . Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016 . |
Financial Risk Management Act51
Financial Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Financial Risk Management Activities [Abstract] | |
Schedule Of Derivative Instruments Fair Value In Balance Sheets | The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2016 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Cash Flow Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 435 $ (273 ) $ 162 $ — $ 1 $ 163 Noncurrent Assets 122 (98 ) 24 — — 24 Total Mark-to-Market Derivative Assets $ 557 $ (371 ) $ 186 $ — $ 1 $ 187 Derivative Contracts Current Liabilities $ (285 ) $ 277 $ (8 ) $ (5 ) $ — $ (13 ) Noncurrent Liabilities (98 ) 95 (3 ) — — (3 ) Total Mark-to-Market Derivative (Liabilities) $ (383 ) $ 372 $ (11 ) $ (5 ) $ — $ (16 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 174 $ 1 $ 175 $ (5 ) $ 1 $ 171 As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 700 $ (477 ) $ 223 $ 13 $ 6 $ 242 Noncurrent Assets 208 (131 ) 77 — — 77 Total Mark-to-Market Derivative Assets $ 908 $ (608 ) $ 300 $ 13 $ 6 $ 319 Derivative Contracts Current Liabilities $ (513 ) $ 437 $ (76 ) $ — $ — $ (76 ) Noncurrent Liabilities (132 ) 116 (16 ) (11 ) — (27 ) Total Mark-to-Market Derivative (Liabilities) $ (645 ) $ 553 $ (92 ) $ (11 ) $ — $ (103 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 263 $ (55 ) $ 208 $ 2 $ 6 $ 216 (A) Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015 . PSE&G does not have any derivative contracts subject to master netting or similar agreements. (B) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2016 and 2015 , net cash collateral (received) paid of $1 million and $(55) million , respectively, were netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016 , $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015 , cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectivel |
Schedule Of Derivative Instruments Designated As Cash Flow Hedges | The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2016 , 2015 and 2014 . Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, 2016 2015 2014 2016 2015 2014 Millions Millions PSEG Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Interest Rate Swaps 3 — — Interest Expense — — — Total PSEG $ 3 $ 3 $ 12 $ — $ 20 $ (9 ) Power Energy-Related Contracts $ — $ 3 $ 12 Operating Revenues $ — $ 20 $ (9 ) Total Power $ — $ 3 $ 12 $ — $ 20 $ (9 ) There were no pre-tax gain (loss) recognized in income on derivatives (ineffective portion) as of December 31, 2016 , 2015 and 2014 . |
Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss | The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis. Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2014 $ 17 $ 10 Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income (20 ) (12 ) Balance as of December 31, 2015 $ — $ — Gain Recognized in AOCI 3 2 Less: Gain Reclassified into Income — — Balance as of December 31, 2016 $ 3 $ 2 |
Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations | The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as NPNS for the years ended December 31, 2016 , 2015 and 2014 . Derivatives Not Designated as Hedges Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives Pre-Tax Gain (Loss) Recognized in Income on Derivatives Years Ended December 31, 2016 2015 2014 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 230 $ 412 $ (348 ) Energy-Related Contracts Energy Costs (8 ) (8 ) 32 Total PSEG and Power $ 222 $ 404 $ (316 ) |
Schedule Of Gross Volume, On Absolute Value Basis For Derivative Contracts | The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2016 and 2015 . Type Notional Total PSEG Power PSE&G Millions As of December 31, 2016 Natural Gas Dth 357 — 348 9 Electricity MWh 323 — 323 — Financial Transmission Rights (FTRs) MWh 9 — 9 — Interest Rate Swaps U.S. Dollars 500 500 — — As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — FTRs MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — |
Schedule Providing Credit Risk From Others, Net Of Collateral | . The following table provides information on Power’s credit risk from others, net of collateral, as of December 31, 2016 . It further delineates that exposure by the credit rating of the counterparties, which is determined by the lowest rating from S&P, Moody’s or an internal scoring model. In addition, it provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties. Rating Current Exposure Securities held as Collateral Net Exposure Number of Counterparties >10% Net Exposure of Counterparties >10% Millions Millions Investment Grade $ 423 $ 94 $ 329 1 $ 219 (A) Non-Investment Grade 26 1 25 — — Total $ 449 $ 95 $ 354 1 $ 219 (A) Represents net exposure with PSE&G. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables present information about PSEG’s, PSE&G’s and Power’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2016 and December 31, 2015 , including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for PSE&G and Power. Recurring Fair Value Measurements as of December 31, 2016 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 Interest Rate Swaps (C) $ 1 $ — $ — $ 1 $ — NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 37 $ — $ — $ 37 $ — Debt Securities—Govt Other $ 66 $ — $ — $ 66 $ — Debt Securities—Corporate $ 91 $ — $ — $ 91 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (16 ) $ 372 $ (18 ) $ (364 ) $ (6 ) PSE&G Assets: Cash Equivalents (A) $ 365 $ — $ 365 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ — $ — $ — $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 7 $ — $ — $ 7 $ — Debt Securities—Govt Other $ 13 $ — $ — $ 13 $ — Debt Securities—Corporate $ 18 $ — $ — $ 18 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (5 ) $ — $ — $ — $ (5 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 186 $ (371 ) $ 17 $ 533 $ 7 NDT Fund (D) Equity Securities $ 957 $ — $ 954 $ 3 $ — Debt Securities—US Treasury $ 227 $ — $ — $ 227 $ — Debt Securities—Govt Other $ 293 $ — $ — $ 293 $ — Debt Securities—Corporate $ 337 $ — $ — $ 337 $ — Other Securities $ 44 $ — $ 44 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 16 $ — $ — $ 16 $ — Debt Securities—Corporate $ 23 $ — $ — $ 23 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ 372 $ (18 ) $ (364 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2015 Description Total Netting (E) Quoted Market Prices for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Millions PSEG Assets: Cash Equivalents (A) $ 326 $ — $ 326 $ — $ — Derivative Contracts: Energy-Related Contracts (B) $ 313 $ (608 ) $ — $ 896 $ 25 Interest Rate Swaps (C) $ 6 $ — $ — $ 6 $ — NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—US Treasury $ 48 $ — $ — $ 48 $ — Debt Securities—Govt Other $ 60 $ — $ — $ 60 $ — Debt Securities—Corporate $ 81 $ — $ — $ 81 $ — Other Securities $ 2 $ — $ 2 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (103 ) $ 553 $ — $ (644 ) $ (12 ) PSE&G Assets: Cash Equivalents (A) $ 160 $ — $ 160 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 13 $ — $ — $ — $ 13 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 9 $ — $ — $ 9 $ — Debt Securities—Govt Other $ 12 $ — $ — $ 12 $ — Debt Securities—Corporate $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (11 ) $ — $ — $ — $ (11 ) Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 300 $ (608 ) $ — $ 896 $ 12 NDT Fund (D) Equity Securities $ 865 $ — $ 865 $ — $ — Debt Securities—US Treasury $ 177 $ — $ — $ 177 $ — Debt Securities—Govt Other $ 311 $ — $ — $ 311 $ — Debt Securities—Corporate $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—US Treasury $ 12 $ — $ — $ 12 $ — Debt Securities—Govt Other $ 14 $ — $ — $ 14 $ — Debt Securities—Corporate $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) (A) Represents money market mutual funds. (B) Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange. Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. (C) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (D) The fair value measurement table excludes cash of $1 million which is part of the NDT Fund, The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities). Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market. Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. (E) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016 , net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016 , $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015 , net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015 , $(69) million was netted against assets and $14 million was netted against liabilities. |
Schedule Of Quantitative Information About Level 3 Fair Value Measurements | following tables provide details surrounding significant Level 3 valuations as of December 31, 2016 and 2015 . Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2016 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ — $ (5 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ — $ (5 ) Power Electricity Electric Load Contracts $ 7 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Gas (A) Other — — Total Power $ 7 $ (1 ) Total PSEG $ 7 $ (6 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2015 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 13 $ (11 ) Discounted Cash Flow Transportation Costs $0.60 to $0.80/Dth Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Electricity Other 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) (A) Includes gas supply positions which were immaterial as of December 31, 2016 . |
Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis | A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2016 and 2015 , respectively, follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2016 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2016 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2016 Millions PSEG Net Derivative Assets (Liabilities) $ 13 $ 13 $ (7 ) $ 3 $ (21 ) $ — $ 1 PSE&G Net Derivative Assets (Liabilities) $ 2 $ — $ (7 ) $ — $ — $ — $ (5 ) Power Net Derivative Assets (Liabilities) $ 11 $ 13 $ — $ 3 $ (21 ) $ — $ 6 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2015 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2015 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances/ Settlements (C) Transfers In/Out Balance as of December 31, 2015 Millions PSEG Net Derivative Assets (Liabilities) $ 37 $ 20 $ (24 ) $ — $ (20 ) $ — $ 13 PSE&G Net Derivative Assets (Liabilities) $ 26 $ — $ (24 ) $ — $ — $ — $ 2 Power Net Derivative Assets (Liabilities) $ 11 $ 20 $ — $ — $ (20 ) $ — $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015 , respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 is realized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015 , respectively. |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Accrual Adjustments | 2016 2015 2014 Millions Compensation Cost included in Operation and Maintenance Expense $ 29 $ 34 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 12 $ 14 $ 13 |
Stock Options Activity | Changes in stock options for 2016 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2016 1,707,250 $ 36.00 Exercised 677,350 $ 33.06 Canceled/Forfeited — $ — Outstanding as of December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 Exercisable at December 31, 2016 1,029,900 $ 37.93 2.0 $ 7,640,178 |
Activity For Options Exercised | Activity for options exercised for the years ended December 31, 2016 , 2015 and 2014 is shown below: 2016 2015 2014 Millions Total Intrinsic Value of Options Exercised $ 7 $ 3 $ 4 Cash Received from Options Exercised $ 22 $ 12 $ 16 Tax Benefit Realized from Options Exercised $ 1 $ — $ — |
Restricted Stock Units Activity | Changes in restricted stock units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 408,507 $ 34.95 Granted 285,258 $ 42.28 Vested 362,098 $ 37.23 Canceled/Forfeited 9,471 $ 39.67 Non-vested as of December 31, 2016 322,196 $ 38.75 1.0 $ 14,137,960 |
Performance Units Information | Changes in performance share units for the year ended December 31, 2016 are summarized as follows: Shares Weighted Average Grant Date Fair Value Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Non-vested as of January 1, 2016 403,961 $ 40.42 Granted 319,718 $ 45.97 Vested 301,554 $ 41.22 Canceled/Forfeited 28,313 $ 42.04 Non-vested as of December 31, 2016 393,812 $ 44.20 1.6 $ 17,280,471 |
Other Income and Deductions (Ta
Other Income and Deductions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Other Income and Deductions Disclosure [Abstract] | |
Schedule Of Other Income | Other Income PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 96 $ — $ 96 Allowance for Funds Used During Construction 49 — — 49 Solar Loan Interest 22 — — 22 Other 12 6 6 24 Total Other Income $ 83 $ 102 $ 6 $ 191 Year Ended December 31, 2015 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 138 $ — $ 138 Allowance for Funds Used During Construction 48 — — 48 Solar Loan Interest 23 — — 23 Gain on Insurance Recovery — 28 — 28 Other 8 3 6 17 Total Other Income $ 79 $ 169 $ 6 $ 254 Year Ended December 31, 2014 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 219 $ — $ 219 Allowance for Funds Used During Construction 31 — — 31 Solar Loan Interest 24 — — 24 Other 6 3 7 16 Total Other Income $ 61 $ 222 $ 7 $ 290 |
Schedule Of Other Deductions | Other Deductions PSE&G Power Other (A) Consolidated Total Millions Year Ended December 31, 2016 NDT Fund Realized Losses and Expenses $ — $ 40 $ — $ 40 Other 4 17 6 27 Total Other Deductions $ 4 $ 57 $ 6 $ 67 Year Ended December 31, 2015 NDT Fund Realized Losses and Expenses $ — $ 45 $ — $ 45 Other 4 27 26 57 Total Other Deductions $ 4 $ 72 $ 26 $ 102 Year Ended December 31, 2014 NDT Fund Realized Losses and Expenses $ — $ 31 $ — $ 31 Other 3 21 6 30 Total Other Deductions $ 3 $ 52 $ 6 $ 61 (A) Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Line Items] | |
Unrecognized Tax Benefits | 2016 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2016 $ 386 $ 181 $ 111 $ 93 Increases as a Result of Positions Taken in a Prior Period 12 3 6 2 Decreases as a Result of Positions Taken in a Prior Period (62 ) (23 ) (1 ) (38 ) Increases as a Result of Positions Taken during the Current Period 19 6 12 — Decreases as a Result of Positions Taken during the Current Period — — — — Decreases as a Result of Settlements with Taxing Authorities — — — — Decreases due to Lapses of Applicable Statute of Limitations (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits as of December 31, 2016 $ 328 $ 140 $ 128 $ 57 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (200 ) (106 ) (74 ) (20 ) Regulatory Asset—Unrecognized Tax Benefits (31 ) (31 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 97 $ 3 $ 54 $ 37 2015 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2015 $ 332 $ 165 $ 70 $ 95 Increases as a Result of Positions Taken in a Prior Period 87 55 28 4 Decreases as a Result of Positions Taken in a Prior Period (50 ) (43 ) (6 ) (1 ) Increases as a Result of Positions Taken during the Current Period 28 5 23 — Decreases as a Result of Positions Taken during the Current Period (1 ) (1 ) — — Decreases as a Result of Settlements with Taxing Authorities (10 ) — (4 ) (5 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2015 $ 386 $ 181 $ 111 $ 93 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (264 ) (162 ) (68 ) (34 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 95 $ (8 ) $ 43 $ 59 2014 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2014 $ 478 $ 208 $ 156 $ 110 Increases as a Result of Positions Taken in a Prior Period 82 65 17 — Decreases as a Result of Positions Taken in a Prior Period (190 ) (92 ) (80 ) (18 ) Increases as a Result of Positions Taken during the Current Period 30 16 9 5 Decreases as a Result of Positions Taken during the Current Period (8 ) — (8 ) — Decreases as a Result of Settlements with Taxing Authorities (60 ) (32 ) (24 ) (2 ) Decreases due to Lapses of Applicable Statute of Limitations — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2014 $ 332 $ 165 $ 70 $ 95 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (225 ) (138 ) (52 ) (35 ) Regulatory Asset—Unrecognized Tax Benefits (27 ) (27 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 80 $ — $ 18 $ 60 |
Interest And Penalties Related To Uncertain Tax Positions | PSEG and its subsidiaries include accrued interest and penalties related to uncertain tax positions required to be recorded, as Income Tax Expense in the Consolidated Statements of Operations. Accumulated interest and penalties that are recorded on the Consolidated Balance Sheets on uncertain tax positions were as follows: Accumulated Interest and Penalties on Uncertain Tax Positions as of December 31, 2016 2015 2014 Millions PSE&G $ 22 $ 20 $ 15 Power 17 6 9 Energy Holdings 20 40 45 Total $ 59 $ 66 $ 69 |
Possible Decrease In Total Unrecognized Tax Benefits Including Interest | It is reasonably possible that total unrecognized tax benefits will significantly increase or decrease within the next twelve months due to either agreements with various taxing authorities upon audit, the expiration of the Statute of Limitations, or other pending tax matters. These potential increases or decreases are as follows: Possible (Increase)/Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 14 PSE&G $ 3 Power $ 7 |
Description Of Income Tax Years By Material Jurisdictions | A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are: PSEG PSE&G Power United States Federal 2011-2015 N/A N/A New Jersey 2006-2015 2011-2015 N/A Pennsylvania 2006-2015 2007-2015 N/A Connecticut 2007-2015 N/A N/A Texas 2008-2015 N/A N/A California 2006-2015 N/A N/A New York 2014-2015 N/A 2014-2015 |
PSEG [Member] | |
Income Taxes [Line Items] | |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSEG 2016 2015 2014 Millions Net Income $ 887 $ 1,679 $ 1,518 Income Taxes: Operating Income: Current Expense: Federal $ (74 ) $ 243 $ 335 State 61 85 58 Total Current (13 ) 328 393 Deferred Expense: Federal 311 540 262 State 28 104 260 Total Deferred 339 644 522 Investment Tax Credit (ITC) 85 29 23 Total Income Taxes $ 411 $ 1,001 $ 938 Pre-Tax Income $ 1,298 $ 2,680 $ 2,456 Tax Computed at Statutory Rate 35% $ 454 $ 938 $ 860 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 56 129 145 Uncertain Tax Positions (31 ) 7 (9 ) Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 14 Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (25 ) (13 ) (14 ) Audit Settlement — — (12 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (9 ) (4 ) (17 ) Sub-Total (43 ) 63 78 Total Income Tax Provision $ 411 $ 1,001 $ 938 Effective Income Tax Rate 31.7 % 37.4 % 38.2 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent OPEB $ 283 $ 256 Related to Uncertain Tax Position 155 160 Securitization-Overcollection — 27 Total Noncurrent Assets $ 438 $ 443 Liabilities: Noncurrent: Plant-Related Items $ 6,593 $ 6,174 New Jersey Corporate Business Tax 674 615 Leasing Activities 565 612 Pension Costs 197 218 AROs and NDT Fund 398 393 Taxes Recoverable Through Future Rate (net) 208 191 Other 212 244 Total Noncurrent Liabilities $ 8,847 $ 8,447 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 8,409 $ 8,004 ITC 249 162 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,658 $ 8,166 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. Also, the deferred tax effect of AROs is presented net of the deferred tax effect of the associated funding of those obligations. |
PSE&G [Member] | |
Income Taxes [Line Items] | |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, PSE&G 2016 2015 2014 Millions Net Income $ 889 $ 787 $ 725 Income Taxes: Operating Income: Current Expense: Federal $ (153 ) $ 32 $ 124 State 10 52 16 Total Current (143 ) 84 140 Deferred Expense: Federal 551 325 214 State 102 52 84 Total Deferred 653 377 298 ITC 5 9 11 Total Income Taxes $ 515 $ 470 $ 449 Pre-Tax Income $ 1,404 $ 1,257 $ 1,174 Tax Computed at Statutory Rate 35% $ 491 $ 440 $ 411 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 72 67 65 Uncertain Tax Positions (18 ) (14 ) — Plant-Related Items (20 ) (20 ) (13 ) Tax Credits (7 ) (6 ) (7 ) Audit Settlement — — 1 Other (3 ) 3 (8 ) Sub-Total 24 30 38 Total Income Tax Provision $ 515 $ 470 $ 449 Effective Income Tax Rate 36.7 % 37.4 % 38.2 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: OPEB $ 189 $ 164 Securitization-Overcollection — 27 Total Noncurrent Assets $ 189 $ 191 Liabilities: Noncurrent: Plant-Related Items $ 4,983 $ 4,435 New Jersey Corporate Business Tax 385 312 Conservation Costs 33 40 Pension Costs 252 262 Taxes Recoverable Through Future Rate (net) 208 191 Other 118 54 Total Noncurrent Liabilities $ 5,979 $ 5,294 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 5,790 $ 5,103 ITC 83 78 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,873 $ 5,181 The deferred tax effect of certain assets and liabilities is presented in the table above net of the deferred tax effect associated with the respective regulatory deferrals. |
Power [Member] | |
Income Taxes [Line Items] | |
Schedule of Effective Income Tax Rate Reconciliation | A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows: Years Ended December 31, Power 2016 2015 2014 Millions Net Income $ 18 $ 856 $ 760 Income Taxes: Operating Income: Current Expense: Federal $ 107 $ 220 $ 231 State 40 30 39 Total Current 147 250 270 Deferred Expense: Federal (222 ) 189 163 State (68 ) 52 48 Total Deferred (290 ) 241 211 ITC 82 20 10 Total Income Taxes $ (61 ) $ 511 $ 491 Pre-Tax Income $ (43 ) $ 1,367 $ 1,251 Tax Computed at Statutory Rate 35% $ (15 ) $ 478 $ 438 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) (18 ) 59 58 Manufacturing Deduction (17 ) (10 ) (16 ) NDT Fund 3 7 15 Tax Credits (18 ) (7 ) (6 ) Uncertain Tax Positions 9 22 (8 ) Audit Settlement — — (4 ) Nuclear Decommissioning Tax Carryback — (33 ) — Other (5 ) (5 ) 14 Sub-Total (46 ) 33 53 Total Income Tax Provision $ (61 ) $ 511 $ 491 Effective Income Tax Rate 141.9 % 37.4 % 39.2 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for Power: As of December 31, Power 2016 2015 Millions Deferred Income Taxes Assets: Noncurrent: Pension Costs $ 68 $ 56 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 53 47 Other 76 — Total Noncurrent Assets $ 215 $ 121 Liabilities: Noncurrent: Plant-Related Items $ 1,605 $ 1,736 New Jersey Corporate Business Tax 214 243 AROs and NDT Fund 400 395 Other — 10 Total Noncurrent Liabilities $ 2,219 $ 2,384 Summary of Accumulated Deferred Income Taxes: Net Noncurrent Deferred Income Tax Liabilities $ 2,004 $ 2,263 ITC 166 84 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,170 $ 2,347 In the above table, the deferred tax effect of asset retirement obligations is presented net of the deferred tax effect of the associated funding of those obligations. |
Accumulated Other Comprehensi56
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block] | PSEG Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (2 ) $ (238 ) $ 145 $ (95 ) Other Comprehensive Income before Reclassifications 7 (184 ) 42 (135 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 11 (69 ) (53 ) Net Current Period Other Comprehensive Income (Loss) 12 (173 ) (27 ) (188 ) Balance as of December 31, 2014 $ 10 $ (411 ) $ 118 $ (283 ) Other Comprehensive Income before Reclassifications 2 (7 ) (25 ) (30 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 32 (2 ) 18 Net Current Period Other Comprehensive Income (Loss) (10 ) 25 (27 ) (12 ) Balance as of December 31, 2015 $ — $ (386 ) $ 91 $ (295 ) Other Comprehensive Income before Reclassifications 2 (45 ) 40 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 33 2 35 Net Current Period Other Comprehensive Income (Loss) 2 (12 ) 42 32 Balance as of December 31, 2016 $ 2 $ (398 ) $ 133 $ (263 ) Power Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) Cash Flow Hedges Pension and OPEB Plans Available-for -Sale Securities Total Millions Balance as of December 31, 2013 $ (1 ) $ (204 ) $ 142 $ (63 ) Other Comprehensive Income before Reclassifications 7 (156 ) 39 (110 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) 5 9 (69 ) (55 ) Net Current Period Other Comprehensive Income (Loss) 12 (147 ) (30 ) (165 ) Balance as of December 31, 2014 $ 11 $ (351 ) $ 112 $ (228 ) Other Comprehensive Income before Reclassifications 1 (4 ) (24 ) (27 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (12 ) 28 (1 ) 15 Net Current Period Other Comprehensive Income (Loss) (11 ) 24 (25 ) (12 ) Balance as of December 31, 2015 $ — $ (327 ) $ 87 $ (240 ) Other Comprehensive Income before Reclassifications — (42 ) 39 (3 ) Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) — 29 3 32 Net Current Period Other Comprehensive Income (Loss) — (13 ) 42 29 Balance as of December 31, 2016 $ — $ (340 ) $ 129 $ (211 ) |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 10 (4 ) 6 Amortization of Actuarial Loss O&M Expense (28 ) 11 (17 ) Total Pension and OPEB Plans (18 ) 7 (11 ) Available-for-Sale Securities Realized Gains Other Income 181 (89 ) 92 Realized Losses Other Deductions (26 ) 13 (13 ) Other-Than-Temporary Impairments (OTTI) OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 135 (66 ) 69 Total $ 108 $ (55 ) $ 53 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2014 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ (9 ) $ 4 $ (5 ) Total Cash Flow Hedges (9 ) 4 (5 ) Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (25 ) 11 (14 ) Total Pension and OPEB Plans (16 ) 7 (9 ) Available-for-Sale Securities Realized Gains Other Income 178 (87 ) 91 Realized Losses Other Deductions (24 ) 12 (12 ) OTTI OTTI (20 ) 10 (10 ) Total Available-for-Sale Securities 134 (65 ) 69 Total $ 109 $ (54 ) $ 55 PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 12 (3 ) 9 Amortization of Actuarial Loss O&M Expense (68 ) 27 (41 ) Total Pension and OPEB Plans (56 ) 24 (32 ) Available-for-Sale Securities Realized Gains Other Income 100 (52 ) 48 Realized Losses Other Deductions (39 ) 20 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 8 (6 ) 2 Total $ (28 ) $ 10 $ (18 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2015 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Cash Flow Hedges Energy-Related Contracts Operating Revenues $ 20 $ (8 ) $ 12 Total Cash Flow Hedges 20 (8 ) 12 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (3 ) 8 Amortization of Actuarial Loss O&M Expense (60 ) 24 (36 ) Total Pension and OPEB Plans (49 ) 21 (28 ) Available-for-Sale Securities Realized Gains Other Income 98 (51 ) 47 Realized Losses Other Deductions (38 ) 19 (19 ) OTTI OTTI (53 ) 26 (27 ) Total Available-for-Sale Securities 7 (6 ) 1 Total $ (22 ) $ 7 $ (15 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 12 $ (5 ) $ 7 Amortization of Actuarial Loss O&M Expense (68 ) 28 (40 ) Total Pension and OPEB Plans (56 ) 23 (33 ) Available-for-Sale Securities Realized Gains Other Income 59 (29 ) 30 Realized Losses Other Deductions (37 ) 19 (18 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 4 (2 ) Total $ (62 ) $ 27 $ (35 ) Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2016 Description of Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) Location of Pre-Tax Amount In Statement of Operations Pre-Tax Amount Tax (Expense) Benefit After-Tax Amount Millions Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense $ 11 $ (5 ) $ 6 Amortization of Actuarial Loss O&M Expense (59 ) 24 (35 ) Total Pension and OPEB Plans (48 ) 19 (29 ) Available-for-Sale Securities Realized Gains Other Income 55 (28 ) 27 Realized Losses Other Deductions (33 ) 17 (16 ) OTTI OTTI (28 ) 14 (14 ) Total Available-for-Sale Securities (6 ) 3 (3 ) Total $ (54 ) $ 22 $ (32 ) |
Earnings Per Share (EPS) and 57
Earnings Per Share (EPS) and Dividends (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Basic And Diluted Earnings Per Share Computation | The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS: Years Ended December 31, 2016 2015 2014 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 887 $ 887 1,679 1,679 $ 1,518 $ 1,518 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 505 505 505 505 506 506 Effect of Stock Based Compensation Awards — 3 — 3 — 2 Total Shares 505 508 505 508 506 508 EPS: Net Income $ 1.76 $ 1.75 3.32 3.30 $ 3.00 $ 2.99 |
Dividend Payments On Common Stock | Years Ended December 31, Dividend Payments on Common Stock 2016 2015 2014 Per Share $ 1.64 $ 1.56 $ 1.48 in Millions $ 830 $ 789 $ 748 |
Financial Information By Busi58
Financial Information By Business Segments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Financial Information By Business Segments | PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2016 Operating Revenues $ 6,221 $ 4,023 $ 370 $ (1,553 ) $ 9,061 Depreciation and Amortization 565 881 30 — 1,476 Operating Income (Loss) 1,614 13 (51 ) — 1,576 Income from Equity Method Investments — 11 — — 11 Interest Income 24 4 4 (2 ) 30 Interest Expense 289 84 14 (2 ) 385 Income (Loss) before Income Taxes 1,404 (43 ) (63 ) — 1,298 Income Tax Expense (Benefit) 515 (61 ) (43 ) — 411 Net Income (Loss) 889 18 (20 ) — 887 Gross Additions to Long-Lived Assets $ 2,816 $ 1,343 $ 40 $ — $ 4,199 As of December 31, 2016 Total Assets $ 26,288 $ 12,193 $ 2,373 $ (784 ) $ 40,070 Investments in Equity Method Subsidiaries $ — $ 102 $ — $ — $ 102 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2015 Operating Revenues $ 6,636 $ 4,928 $ 462 $ (1,611 ) $ 10,415 Depreciation and Amortization 892 291 31 — 1,214 Operating Income (Loss) 1,462 1,430 70 — 2,962 Income from Equity Method Investments — 14 (2 ) — 12 Interest Income 25 2 33 (29 ) 31 Interest Expense 280 121 21 (29 ) 393 Income (Loss) before Income Taxes 1,257 1,367 56 — 2,680 Income Tax Expense (Benefit) 470 511 20 — 1,001 Net Income (Loss) 787 856 36 — 1,679 Gross Additions to Long-Lived Assets $ 2,692 $ 1,117 $ 54 $ — $ 3,863 As of December 31, 2015 Total Assets $ 23,677 $ 12,250 $ 2,810 $ (1,202 ) $ 37,535 Investments in Equity Method Subsidiaries $ — $ 119 $ — $ — $ 119 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2014 Operating Revenues $ 6,766 $ 5,434 $ 455 $ (1,769 ) $ 10,886 Depreciation and Amortization 906 292 29 — 1,227 Operating Income (Loss) 1,393 1,209 21 — 2,623 Income from Equity Method Investments — 14 (1 ) — 13 Interest Income 26 1 25 (22 ) 30 Interest Expense 277 122 12 (22 ) 389 Income (Loss) before Income Taxes 1,174 1,251 31 — 2,456 Income Tax Expense (Benefit) 449 491 (2 ) — 938 Net Income (Loss) 725 760 33 — 1,518 Gross Additions to Long-Lived Assets $ 2,164 $ 626 $ 30 $ — $ 2,820 As of December 31, 2014 Total Assets $ 22,186 $ 12,037 $ 2,799 $ (1,735 ) $ 35,287 Investments in Equity Method Subsidiaries $ — $ 121 $ 2 $ — $ 123 (A) Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. (B) Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions . |
Related-Party Transactions (Tab
Related-Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
PSE&G [Member] | |
Related Party Transaction [Line Items] | |
Schedule Of Related Party Transactions, Revenue | The financial statements for PSE&G include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings from Affiliates: Net Billings from Power primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Administrative Billings from Services (B) 312 274 248 Total Billings from Affiliates $ 1,899 $ 1,904 $ 2,019 |
Schedule Of Related Party Transactions, Payables | Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivables from PSEG (C) $ 76 $ 222 Payable to Power (A) $ 193 $ 212 Payable to Services (B) 67 80 Accounts Payable—Affiliated Companies $ 260 $ 292 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 130 $ 109 |
Power [Member] | |
Related Party Transaction [Line Items] | |
Schedule Of Related Party Transactions, Revenue | The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2016 2015 2014 Millions Billings to Affiliates: Net Billings to PSE&G primarily through BGS and BGSS (A) $ 1,587 $ 1,630 $ 1,771 Billings from Affiliates: Administrative Billings from Services (B) $ 179 $ 187 $ 165 |
Schedule Of Related Party Transactions, Receivables | Years Ended December 31, Related Party Transactions 2016 2015 Millions Receivable from PSE&G (A) $ 193 $ 212 Receivable from PSEG (C) 12 64 Accounts Receivable—Affiliated Companies $ 205 $ 276 Payable to Services (B) $ 25 $ 33 Accounts Payable—Affiliated Companies $ 25 $ 33 Short-Term Loan due (to) from Affiliate (E) $ 87 $ 363 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 77 $ 35 (A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. (B) Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. (C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. (D) PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. (E) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
Selected Quarterly Data (Tables
Selected Quarterly Data (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of Quarterly Data [Line Items] | |
Schedule Of Selected Quarterly Data | The information shown in the following tables, in the opinion of PSEG, PSE&G and Power includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts. Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 PSEG Consolidated: Millions, except per share data Operating Revenues $ 2,616 $ 3,135 $ 1,905 $ 2,314 $ 2,450 $ 2,688 $ 2,090 $ 2,278 Operating Income $ 827 $ 1,048 $ 347 $ 568 $ 577 $ 814 $ (175 ) $ 532 Net Income (Loss) $ 471 $ 586 $ 187 $ 345 $ 327 $ 439 $ (98 ) $ 309 Earnings Per Share: Basic: Net Income (Loss) $ 0.93 $ 1.16 $ 0.37 $ 0.68 $ 0.65 $ 0.87 $ (0.19 ) $ 0.61 Diluted: Net Income (Loss) $ 0.93 $ 1.15 $ 0.37 $ 0.68 $ 0.64 $ 0.87 $ (0.19 ) $ 0.60 Weighted Average Common Shares Outstanding: Basic 505 506 505 506 505 505 505 505 Diluted 508 508 508 508 508 508 508 508 |
PSE&G [Member] | |
Schedule of Quarterly Data [Line Items] | |
Schedule Of Selected Quarterly Data | Quarter Ended March 31, June 30, September 30, December 31, 2016 2015 2016 2015 2016 2015 2016 2015 PSE&G: Millions Operating Revenues $ 1,712 $ 2,002 $ 1,350 $ 1,466 $ 1,684 $ 1,766 $ 1,475 $ 1,402 Operating Income $ 462 $ 451 $ 333 $ 320 $ 450 $ 404 $ 369 $ 287 Net Income $ 262 $ 242 $ 179 $ 167 $ 255 $ 222 $ 193 $ 156 |
Power [Member] | |
Schedule of Quarterly Data [Line Items] | |
Schedule Of Selected Quarterly Data | Quarter Ended March 31, June 30, September 30, December 31, (A) 2016 2015 2016 2015 2016 2015 2016 2015 Power: Millions Operating Revenues $ 1,313 $ 1,725 $ 714 $ 1,025 $ 1,075 $ 1,096 $ 921 $ 1,082 Operating Income (Loss) $ 343 $ 584 $ (12 ) $ 228 $ 238 $ 391 $ (556 ) $ 227 Net Income (Loss) $ 192 $ 335 $ (11 ) $ 166 $ 139 $ 206 $ (302 ) $ 149 (A) The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
Guarantees of Debt (Tables)
Guarantees of Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Guarantees of Debt [Line Items] | |
Schedule Of Financial Statements Of Guarantors | The following tables present condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries, as of December 31, 2016 and 2015 and for the years ended December 31, 2016 , 2015 and 2014 . Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2016 Operating Revenues $ — $ 3,971 $ 173 $ (121 ) $ 4,023 Operating Expenses 8 3,962 161 (121 ) 4,010 Operating Income (Loss) (8 ) 9 12 — 13 Equity Earnings (Losses) of Subsidiaries 36 (3 ) 11 (33 ) 11 Other Income 71 120 — (89 ) 102 Other Deductions (18 ) (39 ) — — (57 ) Other-Than-Temporary Impairments — (28 ) — — (28 ) Interest Expense (115 ) (40 ) (18 ) 89 (84 ) Income Tax Benefit (Expense) 52 (11 ) 20 — 61 Net Income (Loss) $ 18 $ 8 $ 25 $ (33 ) $ 18 Comprehensive Income (Loss) $ 47 $ 50 $ 25 $ (75 ) $ 47 As of December 31, 2016 Current Assets $ 4,412 $ 1,593 $ 152 $ (4,697 ) $ 1,460 Property, Plant and Equipment, net 55 6,145 2,320 — 8,520 Investment in Subsidiaries 4,249 344 — (4,593 ) — Noncurrent Assets 168 2,016 129 (100 ) 2,213 Total Assets $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Current Liabilities $ 171 $ 3,752 $ 1,454 $ (4,697 ) $ 680 Noncurrent Liabilities 532 2,398 502 (100 ) 3,332 Long-Term Debt 2,382 — — — 2,382 Member’s Equity 5,799 3,948 645 (4,593 ) 5,799 Total Liabilities and Member’s Equity $ 8,884 $ 10,098 $ 2,601 $ (9,390 ) $ 12,193 Year Ended December 31, 2016 Net Cash Provided By (Used In) Operating Activities $ 97 $ 1,442 $ 323 $ (607 ) $ 1,255 Net Cash Provided By (Used In) Investing Activities $ 60 $ (707 ) $ (789 ) $ 289 $ (1,147 ) Net Cash Provided By (Used In) Financing Activities $ (157 ) $ (736 ) $ 466 $ 318 $ (109 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2015 Operating Revenues $ — $ 4,883 $ 179 $ (134 ) $ 4,928 Operating Expenses 12 3,451 169 (134 ) 3,498 Operating Income (Loss) (12 ) 1,432 10 — 1,430 Equity Earnings (Losses) of Subsidiaries 906 (4 ) 14 (902 ) 14 Other Income 48 174 — (53 ) 169 Other Deductions (27 ) (45 ) — — (72 ) Other-Than-Temporary Impairments — (53 ) — — (53 ) Interest Expense (116 ) (39 ) (19 ) 53 (121 ) Income Tax Benefit (Expense) 57 (574 ) 6 — (511 ) Net Income (Loss) $ 856 $ 891 $ 11 $ (902 ) $ 856 Comprehensive Income (Loss) $ 844 $ 855 $ 11 $ (866 ) $ 844 As of December 31, 2015 Current Assets $ 4,501 $ 1,912 $ 364 $ (4,828 ) $ 1,949 Property, Plant and Equipment, net 83 6,502 1,542 — 8,127 Investment in Subsidiaries 4,501 346 — (4,847 ) — Noncurrent Assets 155 1,959 136 (76 ) 2,174 Total Assets $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Current Liabilities $ 1,112 $ 3,866 $ 1,076 $ (4,828 ) $ 1,226 Noncurrent Liabilities 442 2,597 375 (76 ) 3,338 Long-Term Debt 1,684 — — — 1,684 Member’s Equity 6,002 4,256 591 (4,847 ) 6,002 Total Liabilities and Member’s Equity $ 9,240 $ 10,719 $ 2,042 $ (9,751 ) $ 12,250 Year Ended December 31, 2015 Net Cash Provided By (Used In) Operating Activities $ 571 $ 2,089 $ 80 $ (1,034 ) $ 1,706 Net Cash Provided By (Used In) Investing Activities $ (366 ) $ (1,519 ) $ (430 ) $ 1,314 $ (1,001 ) Net Cash Provided By (Used In) Financing Activities $ (205 ) $ (571 ) $ 354 $ (280 ) $ (702 ) Power Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2014 Operating Revenues $ — $ 5,390 $ 153 $ (109 ) $ 5,434 Operating Expenses 16 4,175 143 (109 ) 4,225 Operating Income (Loss) (16 ) 1,215 10 — 1,209 Equity Earnings (Losses) of Subsidiaries 799 (5 ) 14 (794 ) 14 Other Income 34 222 — (34 ) 222 Other Deductions (20 ) (32 ) — — (52 ) Other-Than-Temporary Impairments — (20 ) — — (20 ) Interest Expense (102 ) (35 ) (19 ) 34 (122 ) Income Tax Benefit (Expense) 65 (558 ) 2 — (491 ) Net Income (Loss) $ 760 $ 787 $ 7 $ (794 ) $ 760 Comprehensive Income (Loss) $ 595 $ 768 $ 7 $ (775 ) $ 595 Year Ended December 31, 2014 Net Cash Provided By (Used In) Operating Activities $ 577 $ 1,674 $ 76 $ (902 ) $ 1,425 Net Cash Provided By (Used In) Investing Activities $ 148 $ (856 ) $ (42 ) $ 226 $ (524 ) Net Cash Provided By (Used In) Financing Activities $ (724 ) $ (818 ) $ (32 ) $ 676 $ (898 ) |
Organization, Basis Of Presen62
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Power [Member] | ||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | ||
Basis Adjustment | $ (986) | $ (986) |
PSE&G [Member] | ||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | ||
Basis Adjustment | $ 986 | $ 986 |
Organization, Basis Of Presen63
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Depreciation Rate Stated Percentage) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
PSE&G [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation Rate | 2.45% | 2.46% | 2.47% |
General Plant Assets [Member] | Minimum [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 3 years | ||
General Plant Assets [Member] | Maximum [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 20 years | ||
Fossil Production [Member] | Minimum [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 30 years | ||
Fossil Production [Member] | Maximum [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 70 years | ||
Nuclear Production [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 60 years | ||
Pumped Storage Facilities [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 76 years | ||
Solar Assets [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 25 years |
Organization, Basis Of Presen64
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Amounts And Average Rates Used To Calculate IDC Or AFUDC) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
PSE&G [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
IDC/AFUDC | $ 66 | $ 65 | $ 44 |
Average Rate | 7.81% | 8.01% | 8.09% |
Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
IDC/AFUDC | $ 54 | $ 27 | $ 24 |
Average Rate | 4.87% | 5.14% | 5.14% |
Early Plant Retirements Early65
Early Plant Retirements Early Plant Retirements (Details) - Power [Member] - USD ($) $ in Millions | 5 Months Ended | 12 Months Ended | |
May 31, 2017 | Dec. 31, 2016 | ||
Restructuring Cost and Reserve [Line Items] | |||
Total Pre-Tax Restructuring Costs | $ 686 | ||
Energy Costs [Member] | |||
Restructuring Cost and Reserve [Line Items] | |||
Coal Inventory Lower of Cost or Market Adjustments and Capacity Penalties | 62 | ||
Operation and Maintenance Expense [Member] | |||
Restructuring Cost and Reserve [Line Items] | |||
Materials and Supplies Obsolescence | 31 | ||
Write-down of Construction Work in Progress | 14 | ||
Other | [1] | 8 | |
Depreciation And Amortization [Domain] | |||
Restructuring Cost and Reserve [Line Items] | |||
Depreciation, including Asset Retirement Costs | $ 571 | ||
Subsequent Event [Member] | Depreciation And Amortization [Domain] | |||
Restructuring Cost and Reserve [Line Items] | |||
Depreciation, including Asset Retirement Costs | $ 958 | ||
[1] | Includes severance and miscellaneous costs. Power recorded $7 million of severance expense which it expects to pay in 2017. |
Variable Interest Entities (V66
Variable Interest Entities (VIEs) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | $ 2,090 | $ 2,450 | $ 1,905 | $ 2,616 | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 9,061 | $ 10,415 | $ 10,886 |
Operation and Maintenance | 3,008 | 2,978 | 3,150 | ||||||||
PSE&G [Member] | |||||||||||
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | $ 1,475 | $ 1,684 | $ 1,350 | $ 1,712 | $ 1,402 | $ 1,766 | $ 1,466 | $ 2,002 | 6,221 | 6,636 | 6,766 |
Operation and Maintenance | 1,475 | 1,560 | 1,558 | ||||||||
Long Island ServCo [Member] | |||||||||||
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | 410 | 375 | 389 | ||||||||
Operation and Maintenance | $ 410 | $ 375 | $ 389 |
Property, Plant And Equipment67
Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Property, Plant And Equipment) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | $ 25,523 | $ 22,967 |
Total Generation | 13,156 | 11,842 |
Other | 658 | 685 |
Total | 39,337 | 35,494 |
PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 25,523 | 22,967 |
Total Generation | 591 | 569 |
Other | 233 | 196 |
Total | 26,347 | 23,732 |
Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 12,565 | 11,273 |
Other | 90 | 81 |
Total | 12,655 | 11,354 |
Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 0 | 0 |
Other | 335 | 408 |
Total | 335 | 408 |
Electric Transmission [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 9,132 | 7,554 |
Electric Transmission [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 9,132 | 7,554 |
Electric Transmission [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Electric Transmission [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Electric Distribution [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 7,974 | 7,553 |
Electric Distribution [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 7,974 | 7,553 |
Electric Distribution [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Electric Distribution [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Gas Transmission [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 89 | 89 |
Gas Transmission [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 89 | 89 |
Gas Transmission [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Gas Transmission [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Gas Distribution [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 6,369 | 5,875 |
Gas Distribution [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 6,369 | 5,875 |
Gas Distribution [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Gas Distribution [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Construction Work In Progress [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 1,501 | 1,459 |
Total Generation | 1,483 | 892 |
Construction Work In Progress [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 1,501 | 1,459 |
Total Generation | 0 | 0 |
Construction Work In Progress [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 1,483 | 892 |
Construction Work In Progress [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 0 | 0 |
Plant Held For Future Use [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 19 | 26 |
Plant Held For Future Use [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 19 | 26 |
Plant Held For Future Use [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Plant Held For Future Use [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Other Plant [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 439 | 411 |
Other Plant [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 439 | 411 |
Other Plant [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Other Plant [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Fossil Production [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 7,096 | 7,005 |
Fossil Production [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Fossil Production [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 7,096 | 7,005 |
Fossil Production [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Nuclear Production [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 2,516 | 2,202 |
Nuclear Production [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Nuclear Production [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 2,516 | 2,202 |
Nuclear Production [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Nuclear Fuel In Service [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 783 | 785 |
Nuclear Fuel In Service [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Nuclear Fuel In Service [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 783 | 785 |
Nuclear Fuel In Service [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 0 | 0 |
Other Production-Solar [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 1,278 | 958 |
Other Production-Solar [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 591 | 569 |
Other Production-Solar [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 687 | 389 |
Other Production-Solar [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | $ 0 | $ 0 |
Property, Plant And Equipment68
Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Jointly-Owned Facilities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Conemaugh [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 23.00% | |
Plant | $ 408 | $ 404 |
Accumulated Depreciation | $ 166 | 154 |
Keystone [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 23.00% | |
Plant | $ 409 | 408 |
Accumulated Depreciation | $ 176 | 163 |
Peach Bottom [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 50.00% | |
Plant | $ 1,272 | 1,219 |
Accumulated Depreciation | $ 306 | 262 |
Salem [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 57.00% | |
Plant | $ 1,077 | 990 |
Accumulated Depreciation | 304 | 276 |
Nuclear Support Facilities [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant | 238 | 226 |
Accumulated Depreciation | $ 71 | 60 |
Yards Creek [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 50.00% | |
Plant | $ 42 | 42 |
Accumulated Depreciation | $ 25 | 24 |
Merrill Creek Reservoir [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 14.00% | |
Plant | $ 1 | 1 |
Accumulated Depreciation | 0 | 0 |
Transmission Facilities [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant | 169 | 166 |
Accumulated Depreciation | $ 65 | $ 72 |
Regulatory Assets And Liabili69
Regulatory Assets And Liabilities (Schedule Of Regulatory Assets and Liabilities) (Details) $ in Millions | 1 Months Ended | 3 Months Ended | ||||
Oct. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($)$ / DTH | Oct. 01, 2016 | Dec. 31, 2015USD ($) | ||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liabilities of Consolidated Variable Interest Entity, Current | $ 0 | $ 42 | ||||
Regulatory Assets, Current | 199 | 164 | ||||
Regulatory Assets, Noncurrent | 3,319 | 3,196 | ||||
Regulatory Liability, Current | 88 | 123 | ||||
Regulatory Liabilities, Noncurrent | 118 | 175 | ||||
PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets of Variable Interest Entities (VIEs) | 0 | |||||
Regulatory Liabilities of Consolidated Variable Interest Entity, Current | $ 0 | 42 | ||||
Current BGSS rate per therm | 0.40 | |||||
Proposed BGSS rate per therm | 0.34 | |||||
Self Implementing Bill Credit per therm | $ / DTH | 0.08 | |||||
True-up adjustment for Transmission Formula Rate Revenues | $ (34) | |||||
Deferred Storm and Property Reserve Deficiency, Noncurrent | 220 | |||||
Regulatory Assets, Current | 199 | 164 | ||||
Regulatory Assets Including Consolidated Variable Interest Entities, Current | 199 | 164 | ||||
Regulatory Assets, Noncurrent | 3,319 | 3,196 | ||||
Total Noncurrent Regulatory Assets | 3,319 | 3,196 | ||||
Total Regulatory Assets | 3,518 | 3,360 | ||||
Regulatory Liability, Current | 88 | 123 | ||||
Regulatory Liabilities Including Consolidated Variable Interest Entity, Current | 88 | 165 | ||||
Regulatory Liabilities, Noncurrent | 118 | 175 | ||||
Regulatory Liabilities Of Consolidated Variable Interest Entity Noncurrent | 0 | |||||
Total Noncurrent Regulatory Liabilities | 118 | 175 | ||||
Total Regulatory Liabilities | 206 | 340 | ||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 121 | |||||
Proposed Recovery of costs for Electric Green Energy Program | $ 44 | |||||
Proposed Recovery of costs for Gas Green Energy Programs | $ 13 | |||||
Stranded Costs [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1] | 0 | 64 | |||
Solar and EE Recovery Charge formerly RRC and currently Green Program Recovery Charges (GPRC) [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 28 | 36 | |||
Societal Benefits Charges (SBC) [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 4 | 31 | |||
Gas Margin Adjustment Clause [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 11 | 13 | |||
FERC Formula Rate True-Up [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 34 | 19 | |||
Regulatory Liabilities, Noncurrent | [1],[2] | 1 | 49 | |||
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 6 | 1 | |||
Electric and Gas Cost Of Removal [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liabilities, Noncurrent | 94 | 122 | ||||
Other [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liabilities, Noncurrent | 3 | 4 | ||||
Non-Utility Generation Charge [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Liability, Current | [1],[2] | 5 | 1 | |||
New Jersey Clean Energy Program [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Current | [1] | 142 | 142 | |||
Weather Normalization Clause [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Current | [1] | 49 | 10 | |||
Solar and EE Recovery Charge formerly RRC and currently Green Program Recovery Charges (GPRC) [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | [1],[2] | 91 | 104 | |||
Pension and Other Postretirement Benefit Costs [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 1,403 | 1,270 | ||||
Deferred Income Taxes [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 507 | 467 | ||||
Manufactured Gas Plant (MGP) Remediation Costs [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | [1] | 403 | 431 | |||
Storm Damage Deferral [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 239 | 233 | ||||
Remediation Adjustment Charge (Other SBC) [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | [1],[2] | 180 | 174 | |||
Conditional Asset Retirement Obligation [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 157 | 152 | ||||
Electric and Gas Cost Of Removal [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 189 | 160 | ||||
Unamortized Loss On Reacquired Debt And Debt Expense [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 61 | 67 | ||||
Mark-To-Market Contracts [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Noncurrent | 0 | 63 | ||||
Regulatory Liabilities, Noncurrent | 20 | 0 | ||||
Other [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Current | 6 | 1 | ||||
Regulatory Assets, Noncurrent | 89 | 75 | ||||
Underrecovered Electric Costs Basic Generation Service [Member] | PSE&G [Member] | ||||||
Regulatory Assets And Liabilities [Line Items] | ||||||
Regulatory Assets, Current | [1],[2] | $ 2 | $ 11 | |||
[1] | Recoverable/Refundable per specific rate order. | |||||
[2] | Recovered/Refunded with interest. |
Regulatory Assets And Liabili70
Regulatory Assets And Liabilities (Significant Orders and Pending Filings) (Details) - PSE&G [Member] $ in Millions | 1 Months Ended | 3 Months Ended | |||||||
Nov. 30, 2016USD ($) | Oct. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jul. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Apr. 30, 2016USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($)$ / DTH | Oct. 01, 2016 | |
Regulatory Assets And Liabilities [Line Items] | |||||||||
Deferred Storm and Property Reserve Deficiency, Noncurrent | $ 220 | ||||||||
Self Implementing Bill Credit per therm | $ / DTH | 0.08 | ||||||||
Current BGSS rate per therm | 0.40 | ||||||||
Proposed BGSS rate per therm | 0.34 | ||||||||
True-up adjustment for Transmission Formula Rate Revenues | $ (34) | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 121 | ||||||||
Proposed Recovery of costs for Electric Green Energy Program | $ 44 | ||||||||
Proposed Recovery of costs for Gas Green Energy Programs | 13 | ||||||||
Public Utilities, Approved Additional Capital Expenditures | $ 80 | ||||||||
Public Utilities, Requested Return on Equity, Percentage | 9.75% | ||||||||
Gas Distribution [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 23 | ||||||||
Gas System Modernization Program [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 10 | ||||||||
Electric Distribution [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 12 | 16 | |||||||
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
BGSS Revenue Reduction | $ 87 | ||||||||
Weather Normalization Clause [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 54 | ||||||||
Remediation Adjustment Charge (Other SBC) [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 41 | $ 54 | |||||||
Subsequent Event [Member] | |||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||
BGSS Revenue Reduction | $ 47 |
Long-Term Investments (Schedule
Long-Term Investments (Schedule Of Long Term Investments) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | $ 1,050 | $ 1,233 | ||
Dividends in equity method investments | 18 | 16 | $ 17 | |
Power [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 102 | 119 | ||
PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 299 | 330 | ||
Life Insurance And Supplemental Benefits [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 140 | 150 | ||
Solar Loan Investments [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 159 | 175 | ||
Lease Investments [Member] | Energy Holdings [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 649 | 784 | ||
Partnerships And Corporate Joint Ventures [Member] | Power [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | [1] | 102 | 119 | |
Other Investments [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | $ 0 | $ 5 | ||
[1] | During the three years ended December 31, 2016, 2015 and 2014, dividends from these investments were $18 million, $16 million and $17 million, respectively. |
Long-Term Investments (Schedu72
Long-Term Investments (Schedule Of Net Investment In Leveraged Leases) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Long-term Investments [Abstract] | ||
Lease Receivables (net of Non-Recourse Debt) | $ 629 | $ 631 |
Estimated Residual Value of Leased Assets | 346 | 519 |
Total Investment in Rental Receivables | 975 | 1,150 |
Unearned and Deferred Income | (326) | (366) |
Gross Investment in Leases | 649 | 784 |
Deferred Tax Liabilities | (674) | (724) |
Net Investments in Leases | $ (25) | $ 60 |
Long-Term Investments (Schedu73
Long-Term Investments (Schedule Of Pre-Tax Income And Income Tax Effects Related To Investments In Leveraged Leases) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Long-term Investments [Abstract] | |||
Pre-Tax Income (Loss) from Leases | $ (135) | $ 12 | $ 24 |
Income Tax Expense (Benefit) on Income from Leases | $ (51) | $ 5 | $ 32 |
Long-Term Investments (Equity M
Long-Term Investments (Equity Method Investments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Long-Term Investments [Line Items] | |||
Long-Term Investments | $ 1,050 | $ 1,233 | |
Keystone [Member] | |||
Long-Term Investments [Line Items] | |||
Location of the affiliated companies, equity method investments | PA | ||
Owned percentage | 23.00% | ||
Conemaugh [Member] | |||
Long-Term Investments [Line Items] | |||
Location of the affiliated companies, equity method investments | PA | ||
Owned percentage | 23.00% | ||
PennEast [Member] | |||
Long-Term Investments [Line Items] | |||
Location of the affiliated companies, equity method investments | PA | ||
Owned percentage | 10.00% | ||
Kalaeloa [Member] | |||
Long-Term Investments [Line Items] | |||
Location of the affiliated companies, equity method investments | HI | ||
Owned percentage | 50.00% | ||
Power [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | $ 102 | 119 | |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | [1] | 102 | 119 |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Keystone [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 7 | 16 | |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Conemaugh [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 8 | 14 | |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | PennEast [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 11 | 5 | |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Kalaeloa [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | $ 76 | $ 84 | |
[1] | During the three years ended December 31, 2016, 2015 and 2014, dividends from these investments were $18 million, $16 million and $17 million, respectively. |
Financing Receivables (Schedule
Financing Receivables (Schedule Of Credit Risk Profile Based On Payment Activity) (Detail) - PSE&G [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Concentration Risk [Line Items] | ||
Loans Receivable, Net | $ 175 | $ 189 |
Commercial/Industrial [Member] | ||
Concentration Risk [Line Items] | ||
Loans Receivable, Net | 164 | 177 |
Residential [Member] | ||
Concentration Risk [Line Items] | ||
Loans Receivable, Net | $ 11 | $ 12 |
Financing Receivables (Schedu76
Financing Receivables (Schedule Of Lease Receivables, Net Of Nonrecourse Debt, Associated With Leveraged Lease Portfolio Based On Counterparty Credit Rating) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | $ 629 | $ 631 |
Energy Holdings [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 629 | |
Energy Holdings [Member] | Counterparties' Credit Rating (S&P), AA [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 16 | |
Energy Holdings [Member] | Counterparties' Credit Rating (S&P), BBB plus - BBB minus [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 316 | |
Energy Holdings [Member] | Standard & Poor's, BB minus Rating [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 133 | |
Energy Holdings [Member] | Standard & Poor's, CCC+ Rating [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | $ 164 |
Financing Receivables (Narrativ
Financing Receivables (Narrative) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Financing Receivable, Recorded Investment [Line Items] | ||
Net Investments in Leases | $ (25) | $ 60 |
Lease investment with non-investment grade counterparties, gross | 426 | |
Lease investment with non-investment grade counterparties, net of deferred taxes | $ (131) | |
Powerton Station [Member] | ||
Financing Receivable, Recorded Investment [Line Items] | ||
Lease Receivable Percent Owned | 64.00% |
Financing Receivables (Schedu78
Financing Receivables (Schedule Of Assets Under Lease Receivables) (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)MW | |
Powerton Station Units 5 And 6 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | IL |
Lease Receivable, Gross Investment | $ | $ 134 |
Lease Receivable, % Owned | 64.00% |
Lease Receivable, Total, MW | MW | 1,538 |
Lease Receivable, Asset, Fuel Type | Coal |
Lease Receivable, Counterparties' S&P Credit Ratings | BB- |
Lease Receivable, Counterparty | NRG Energy, Inc. |
Joliet Station Units 7 And 8 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | IL |
Lease Receivable, Gross Investment | $ | $ 83 |
Lease Receivable, % Owned | 64.00% |
Lease Receivable, Total, MW | MW | 1,036 |
Lease Receivable, Asset, Fuel Type | Gas |
Lease Receivable, Counterparties' S&P Credit Ratings | BB- |
Lease Receivable, Counterparty | NRG Energy, Inc. |
Keystone Station Units 1 And 2 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | PA |
Lease Receivable, Gross Investment | $ | $ 55 |
Lease Receivable, % Owned | 17.00% |
Lease Receivable, Total, MW | MW | 1,711 |
Lease Receivable, Asset, Fuel Type | Coal |
Lease Receivable, Counterparties' S&P Credit Ratings | CCC (A) |
Lease Receivable, Counterparty | REMA |
Conemaugh Station Units 1 And 2 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | PA |
Lease Receivable, Gross Investment | $ | $ 55 |
Lease Receivable, % Owned | 17.00% |
Lease Receivable, Total, MW | MW | 1,711 |
Lease Receivable, Asset, Fuel Type | Coal |
Lease Receivable, Counterparties' S&P Credit Ratings | CCC (A) |
Lease Receivable, Counterparty | REMA |
Shawville Station Units 1, 2, 3 And 4 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | PA |
Lease Receivable, Gross Investment | $ | $ 99 |
Lease Receivable, % Owned | 100.00% |
Lease Receivable, Total, MW | MW | 596 |
Lease Receivable, Asset, Fuel Type | Gas |
Lease Receivable, Counterparties' S&P Credit Ratings | CCC (A) |
Lease Receivable, Counterparty | REMA |
Available-For-Sale Securities79
Available-For-Sale Securities (Fair Values And Gross Unrealized Gains And Losses For The Securities) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | $ 209 | $ 204 | |
Gross Unrealized Gains | 12 | 11 | |
Gross Unrealized Losses | (4) | (2) | |
Fair Value | 217 | 213 | |
Rabbi Trust [Member] | Equity Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 11 | 12 | |
Gross Unrealized Gains | 11 | 10 | |
Gross Unrealized Losses | 0 | 0 | |
Fair Value | 22 | 22 | |
Rabbi Trust [Member] | Government Obligations [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 105 | 108 | |
Gross Unrealized Gains | 0 | 1 | |
Gross Unrealized Losses | (2) | (1) | |
Fair Value | 103 | 108 | |
Rabbi Trust [Member] | Other Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 92 | 82 | |
Gross Unrealized Gains | 1 | 0 | |
Gross Unrealized Losses | (2) | (1) | |
Fair Value | 91 | 81 | |
Rabbi Trust [Member] | Total Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 197 | 190 | |
Gross Unrealized Gains | 1 | 1 | |
Gross Unrealized Losses | (4) | (2) | |
Fair Value | 194 | 189 | |
Rabbi Trust [Member] | Other Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 1 | 2 | |
Gross Unrealized Gains | 0 | 0 | |
Gross Unrealized Losses | 0 | 0 | |
Fair Value | 1 | 2 | |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 1,604 | 1,584 | |
Gross Unrealized Gains | 275 | 196 | |
Gross Unrealized Losses | (21) | (26) | |
Fair Value | 1,858 | [1] | 1,754 |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Equity Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 705 | 693 | |
Gross Unrealized Gains | 263 | 185 | |
Gross Unrealized Losses | (11) | (13) | |
Fair Value | 957 | 865 | |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Government Obligations [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 518 | 483 | |
Gross Unrealized Gains | 8 | 8 | |
Gross Unrealized Losses | (6) | (3) | |
Fair Value | 520 | 488 | |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Other Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 337 | 366 | |
Gross Unrealized Gains | 4 | 3 | |
Gross Unrealized Losses | (4) | (10) | |
Fair Value | 337 | 359 | |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Total Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 855 | 849 | |
Gross Unrealized Gains | 12 | 11 | |
Gross Unrealized Losses | (10) | (13) | |
Fair Value | 857 | 847 | |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | Other Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Cost | 44 | 42 | |
Gross Unrealized Gains | 0 | 0 | |
Gross Unrealized Losses | 0 | 0 | |
Fair Value | 44 | 42 | |
Power [Member] | Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value | $ 53 | $ 52 | |
[1] | (A)The NDT available-for-sale securities table excludes cash of $1 million which is part of the NDT Fund. |
Available-For-Sale Securities80
Available-For-Sale Securities (Schedule Of Accounts Receivable And Accounts Payable) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Rabbi Trust [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Accounts Receivable | $ 5 | $ 1 |
Accounts Payable | 3 | 0 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Accounts Receivable | 8 | 17 |
Accounts Payable | $ 5 | $ 10 |
Available-For-Sale Securities81
Available-For-Sale Securities (Value Of Securities That Have Been In An Unrealized Loss Position For Less Than And Greater Than 12 Months) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | $ 535 | $ 618 | |
Gross Unrealized Losses, Less than 12 Months | (19) | (22) | |
Fair Value, Greater Than 12 Months | 27 | 56 | |
Gross Unrealized Losses, Greater Than 12 Months | (2) | (4) | |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [1] | 120 | 151 |
Gross Unrealized Losses, Less than 12 Months | [1] | (10) | (13) |
Fair Value, Greater Than 12 Months | [1] | 8 | 1 |
Gross Unrealized Losses, Greater Than 12 Months | [1] | (1) | 0 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government Obligations [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [2] | 276 | 245 |
Gross Unrealized Losses, Less than 12 Months | [2] | (6) | (2) |
Fair Value, Greater Than 12 Months | [2] | 4 | 19 |
Gross Unrealized Losses, Greater Than 12 Months | [2] | 0 | (1) |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [3] | 139 | 222 |
Gross Unrealized Losses, Less than 12 Months | [3] | (3) | (7) |
Fair Value, Greater Than 12 Months | [3] | 15 | 36 |
Gross Unrealized Losses, Greater Than 12 Months | [3] | (1) | (3) |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Total Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | 415 | 467 | |
Gross Unrealized Losses, Less than 12 Months | (9) | (9) | |
Fair Value, Greater Than 12 Months | 19 | 55 | |
Gross Unrealized Losses, Greater Than 12 Months | (1) | (4) | |
Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | 106 | 99 | |
Gross Unrealized Losses, Less than 12 Months | (4) | (2) | |
Fair Value, Greater Than 12 Months | 4 | 11 | |
Gross Unrealized Losses, Greater Than 12 Months | 0 | 0 | |
Rabbi Trust [Member] | Equity Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [4] | 0 | 0 |
Gross Unrealized Losses, Less than 12 Months | [4] | 0 | 0 |
Fair Value, Greater Than 12 Months | [4] | 0 | 0 |
Gross Unrealized Losses, Greater Than 12 Months | [4] | 0 | 0 |
Rabbi Trust [Member] | Government Obligations [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [5] | 60 | 53 |
Gross Unrealized Losses, Less than 12 Months | [5] | (2) | (1) |
Fair Value, Greater Than 12 Months | [5] | 1 | 2 |
Gross Unrealized Losses, Greater Than 12 Months | [5] | 0 | 0 |
Rabbi Trust [Member] | Other Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | [6] | 46 | 46 |
Gross Unrealized Losses, Less than 12 Months | [6] | (2) | (1) |
Fair Value, Greater Than 12 Months | [6] | 3 | 9 |
Gross Unrealized Losses, Greater Than 12 Months | [6] | 0 | 0 |
Rabbi Trust [Member] | Total Debt Securities [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | 106 | 99 | |
Gross Unrealized Losses, Less than 12 Months | (4) | (2) | |
Fair Value, Greater Than 12 Months | 4 | 11 | |
Gross Unrealized Losses, Greater Than 12 Months | $ 0 | $ 0 | |
[1] | Equity Securities—Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over a broad range of securities with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2016. | ||
[2] | Debt Securities (Government)—Unrealized losses on Power’s NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. Power also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016. | ||
[3] | Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016. | ||
[4] | Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund are through a mutual fund which invests primarily in common stocks within a broad range of industries and sectors. | ||
[5] | Debt Securities (Government)—Unrealized losses on PSEG’s Rabbi Trust investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. These investments are guaranteed by the U.S. government or an agency of the U.S. government. PSEG also has investments in municipal bonds that are primarily in investment grade securities. It is not expected that these securities will settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016. | ||
[6] | Debt Securities (Corporate)—PSEG’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since PSEG does not intend to sell these securities nor will it be more-likely-than-not required to sell, PSEG does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2016. |
Available-For-Sale Securities82
Available-For-Sale Securities (Proceeds From The Sales Of And The Net Realized Gains On Securities) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | ||||
Schedule of Available-for-sale Securities [Line Items] | ||||
Proceeds from Sale and Maturity of Available-for-sale Securities | [1] | $ 711 | $ 1,397 | $ 1,448 |
Gross Realized Gains | 53 | 97 | 177 | |
Gross Realized Losses | (32) | (37) | (23) | |
Net Realized Gains (Losses) | 21 | 60 | 154 | |
Rabbi Trust [Member] | ||||
Schedule of Available-for-sale Securities [Line Items] | ||||
Proceeds from Sale and Maturity of Available-for-sale Securities | [2] | 113 | 104 | 467 |
Gross Realized Gains | 6 | 3 | 4 | |
Gross Realized Losses | (5) | (2) | (3) | |
Net Realized Gains (Losses) | $ 1 | $ 1 | $ 1 | |
[1] | Includes activity in accounts related to the liquidation of funds being transitioned to new managers. | |||
[2] | (A)Includes activity in accounts related to the liquidation of funds being transitioned to new managers. |
Available-For-Sale Securities83
Available-For-Sale Securities (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | $ 28 | $ 53 | $ 20 |
Power [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | 28 | $ 53 | $ 20 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | 28 | ||
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent | 128 | ||
Decommissioning Liability, Noncurrent | 454 | ||
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Minimum [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Decommissioning Costs Including Contingencies | 2,800 | ||
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Maximum [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Decommissioning Costs Including Contingencies | 3,000 | ||
Debt Securities [Member] | Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent | $ 5 |
Available-For-Sale Securities84
Available-For-Sale Securities (Amount Of Available-For-Sale Debt Securities By Maturity Periods) (Detail) $ in Millions | Dec. 31, 2016USD ($) |
Rabbi Trust [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-sale debt securities, Less than one year | $ 8 |
Available-for-sale debt securities, 1-5 years | 44 |
Available-for-sale debt securities, 6-10 years | 44 |
Available-for-sale debt securities, 11-15 years | 9 |
Available-for-sale debt securities, 16-20 years | 8 |
Available-for-sale debt securities, Over 20 years | 81 |
Total Available-for-Sale Debt Securities | 194 |
Power [Member] | Nuclear Decommissioning Trust (NDT) Fund [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-sale debt securities, Less than one year | 15 |
Available-for-sale debt securities, 1-5 years | 257 |
Available-for-sale debt securities, 6-10 years | 193 |
Available-for-sale debt securities, 11-15 years | 50 |
Available-for-sale debt securities, 16-20 years | 60 |
Available-for-sale debt securities, Over 20 years | 282 |
Total Available-for-Sale Debt Securities | $ 857 |
Available-For-Sale Securities85
Available-For-Sale Securities (Fair Value Of Rabbi Trust) (Detail) - Rabbi Trust [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | $ 217 | $ 213 |
Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | 53 | 52 |
PSE&G [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | 43 | 42 |
Other [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | $ 121 | $ 119 |
Goodwill And Other Intangible86
Goodwill And Other Intangibles (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Goodwill [Line Items] | ||
Goodwill | $ 16 | $ 16 |
Intangible assets | 98 | 102 |
Power [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 16 | 16 |
Intangible assets | $ 98 | $ 102 |
Goodwill And Other Intangible87
Goodwill And Other Intangibles (Expenses Related To Emissions And Renewable Energy Requirements) (Details) - Power [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Goodwill [Line Items] | |||
Emissions Expense | $ 14 | $ 13 | $ 10 |
Renewable Energy Expense | $ 95 | $ 91 | $ 59 |
Asset Retirement Obligations 88
Asset Retirement Obligations (AROs) (Impact Of The Revisions On Asset Retirement Obligation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | $ 679 | $ 743 | |
Liabilities Settled | (13) | (5) | |
Liabilities Incurred | 25 | 14 | |
Accretion Expense | 26 | 26 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 12 | 16 |
Asset Retirement Obligation, Revision of Estimate | (3) | (115) | |
ARO Liability, Ending Balance | 726 | 679 | |
PSE&G [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 218 | 290 | |
Liabilities Settled | (9) | (4) | |
Liabilities Incurred | 2 | 1 | |
Accretion Expense | 0 | 0 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 12 | 16 |
Asset Retirement Obligation, Revision of Estimate | (10) | (85) | |
ARO Liability, Ending Balance | 213 | 218 | |
Power [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 457 | 450 | |
Liabilities Settled | (4) | (1) | |
Liabilities Incurred | 23 | 12 | |
Accretion Expense | 26 | 26 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 0 | 0 |
Asset Retirement Obligation, Revision of Estimate | 9 | (30) | |
ARO Liability, Ending Balance | 511 | 457 | |
Other [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 4 | 3 | |
Liabilities Settled | 0 | 0 | |
Liabilities Incurred | 0 | 1 | |
Accretion Expense | 0 | 0 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 0 | 0 |
Asset Retirement Obligation, Revision of Estimate | (2) | 0 | |
ARO Liability, Ending Balance | $ 2 | $ 4 | |
[1] | Not reflected as expense in Consolidated Statements of Operations |
Pension, OPEB and Savings Pla89
Pension, OPEB and Savings Plans (Narrative) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2017 | Dec. 31, 2016USD ($)plan | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 128 | $ 114 | ||
Number of PSEG's defined contribution plans | plan | 2 | |||
Historical annualized rate of return | 9.30% | |||
Defined benefit plan funded status of plan percentage | 90.00% | |||
Rabbi trust assets used to fund nonqualified pension plans | $ 217 | |||
Defined benefit plans, projected benefit and accumulated benefit obligations | 5,600 | 5,400 | ||
OPEB Plan estimated contribution in next fiscal year | $ 14 | |||
Maximum annual 401(k) contribution per employee, percent | 50.00% | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 50.00% | |||
Total Employer Matching Contributions | $ 41 | 39 | $ 36 | |
Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 398 | 386 | ||
Accumulated Other Comprehensive Income (Loss), Defined Benefit Pension and Other Postretirement Plans, Before Tax | 679 | 658 | ||
Defined Benefit Plan, Net Periodic Benefit Cost | 56 | 74 | $ (23) | |
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 568 | $ 487 | ||
Expected long-term rate of return on plan assets | 8.00% | 8.00% | 8.00% | |
Interest in Master Trust assets percentage | 93.00% | |||
Other Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Benefit Obligation | $ 161 | |||
Other Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | 71 | $ 87 | $ 70 | |
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 1,324 | $ 1,228 | ||
Expected long-term rate of return on plan assets | 8.00% | 8.00% | 8.00% | |
Interest in Master Trust assets percentage | 7.00% | |||
Equity Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target allocation percentage of assets | 70.00% | |||
Fixed Income Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target allocation percentage of assets | 30.00% | |||
Power [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Total Employer Matching Contributions | $ 12 | $ 12 | $ 11 | |
Power [Member] | Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | 16 | 21 | (7) | |
Power [Member] | Other Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 23 | 27 | 20 | |
Thrift Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Employer matching contribution, percent | 8.00% | |||
Savings Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Employer matching contribution, percent | 7.00% | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Number of PSEG's defined contribution plans | plan | 2 | |||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | $ 35 | |||
Maximum annual 401(k) contribution per employee, percent | 8.00% | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 50.00% | |||
Employer matching contribution, percent | 50.00% | |||
Total Employer Matching Contributions | $ 5 | 4 | 3 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | 28 | 30 | $ 67 | |
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 128 | 114 | ||
Expected long-term rate of return on plan assets | 7.70% | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 2 | |||
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 452 | $ 375 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Equity Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target allocation percentage of assets | 70.00% | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Target allocation percentage of assets | 30.00% | |||
Change in Accounting Method Accounted for as Change in Estimate [Member] | Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 34 | |||
Change in Accounting Method Accounted for as Change in Estimate [Member] | Other Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 13 | |||
Subsequent Event [Member] | Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected long-term rate of return on plan assets | 7.60% |
Pension, OPEB and Savings Pla90
Pension, OPEB and Savings Plans (Changes In The Benefit Obligation And The Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | [1] | $ 5,405 | ||||
Fair Value of Assets at End of Year | [1] | 5,599 | $ 5,405 | |||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (128) | (114) | ||||
Pension Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | [2] | 5,522 | 5,722 | |||
Service Cost | 109 | 123 | $ 104 | |||
Interest Cost | 202 | 234 | 234 | |||
Actuarial (Gain) Loss | 219 | [3] | (289) | |||
Gross Benefits Paid | (282) | (268) | ||||
Plan Assumptions | 2 | 0 | ||||
Benefit Obligation at End of Year | [2] | 5,772 | [3] | 5,522 | 5,722 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 5,039 | 5,293 | ||||
Actual Return on Plan Assets | 403 | (11) | ||||
Employer Contributions | 33 | 25 | ||||
Gross Benefits Paid | (282) | (268) | ||||
Fair Value of Assets at End of Year | 5,193 | 5,039 | 5,293 | |||
Funded Status (Plan Assets less Benefit Obligation) | (579) | (483) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Assets | 0 | 14 | ||||
Current Accrued Benefit Cost | (11) | (10) | ||||
Noncurrent Accrued Benefit Cost | (568) | (487) | ||||
Amounts Recognized | (579) | (483) | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract] | ||||||
Prior Service Cost | (63) | (83) | ||||
Net Actuarial Loss | 1,763 | 1,710 | ||||
Total | (1,700) | (1,627) | ||||
Other Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | [2] | 1,612 | 1,638 | |||
Service Cost | 17 | 22 | 18 | |||
Interest Cost | 59 | 67 | 69 | |||
Actuarial (Gain) Loss | 127 | [3] | (45) | |||
Gross Benefits Paid | (57) | (70) | ||||
Plan Assumptions | (4) | 0 | ||||
Benefit Obligation at End of Year | [2] | 1,754 | [3] | 1,612 | 1,638 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 374 | 361 | ||||
Actual Return on Plan Assets | 32 | (1) | ||||
Employer Contributions | 71 | 84 | ||||
Gross Benefits Paid | (57) | (70) | ||||
Fair Value of Assets at End of Year | 420 | 374 | 361 | |||
Funded Status (Plan Assets less Benefit Obligation) | (1,334) | (1,238) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Assets | 0 | 0 | ||||
Current Accrued Benefit Cost | (10) | (10) | ||||
Noncurrent Accrued Benefit Cost | (1,324) | (1,228) | ||||
Amounts Recognized | (1,334) | (1,238) | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract] | ||||||
Prior Service Cost | (14) | (25) | ||||
Net Actuarial Loss | 523 | 438 | ||||
Total | (509) | (413) | ||||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | ||||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 97 | |||||
Fair Value of Assets at End of Year | 134 | 97 | ||||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | 211 | [4] | 195 | |||
Service Cost | 24 | 26 | ||||
Interest Cost | 9 | 9 | ||||
Actuarial (Gain) Loss | 14 | (20) | ||||
Gross Benefits Paid | (1) | 0 | ||||
Plan Assumptions | 5 | 1 | ||||
Benefit Obligation at End of Year | 262 | [4] | 211 | [4] | 195 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 97 | 69 | ||||
Actual Return on Plan Assets | 10 | (2) | ||||
Employer Contributions | 28 | 30 | ||||
Gross Benefits Paid | (1) | 0 | ||||
Fair Value of Assets at End of Year | 134 | 97 | 69 | |||
Funded Status (Plan Assets less Benefit Obligation) | (128) | (114) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (128) | (114) | ||||
Amounts Recognized | [5] | (128) | (114) | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | 375 | [4] | 452 | |||
Service Cost | 12 | 17 | ||||
Interest Cost | 17 | 21 | ||||
Actuarial (Gain) Loss | 50 | (114) | ||||
Gross Benefits Paid | (2) | (1) | ||||
Plan Assumptions | 0 | 0 | ||||
Benefit Obligation at End of Year | 452 | [4] | 375 | [4] | 452 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 0 | 0 | ||||
Actual Return on Plan Assets | 0 | 0 | ||||
Employer Contributions | 2 | 1 | ||||
Gross Benefits Paid | (2) | (1) | ||||
Fair Value of Assets at End of Year | 0 | 0 | $ 0 | |||
Funded Status (Plan Assets less Benefit Obligation) | (452) | (375) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (452) | (375) | ||||
Amounts Recognized | [5] | $ (452) | $ (375) | |||
[1] | Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015, respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. | |||||
[2] | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. | |||||
[3] | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. | |||||
[4] | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. | |||||
[5] | Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG’s Consolidated Balance Sheets. |
Pension, OPEB and Savings Pla91
Pension, OPEB and Savings Plans (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 109 | $ 123 | $ 104 |
Interest Cost | 202 | 234 | 234 |
Expected Return on Plan Assets | (394) | (414) | (399) |
Amortization of Prior Service Cost | (19) | (19) | (18) |
Amortization of Actuarial Loss | 158 | 150 | 56 |
Net Periodic Benefit Cost | 56 | 74 | (23) |
Total Benefit Costs, Including Effect of Regulatory Asset | 56 | 74 | (23) |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 17 | 22 | 18 |
Interest Cost | 59 | 67 | 69 |
Expected Return on Plan Assets | (31) | (31) | (26) |
Amortization of Prior Service Cost | (14) | (14) | (14) |
Amortization of Actuarial Loss | 40 | 43 | 23 |
Net Periodic Benefit Cost | 71 | 87 | 70 |
Total Benefit Costs, Including Effect of Regulatory Asset | $ 71 | $ 87 | $ 70 |
Pension, OPEB and Savings Pla92
Pension, OPEB and Savings Plans (Schedule Of Pension And OPEB Costs) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 56 | $ 74 | $ (23) |
Total Benefit Costs | 56 | 74 | (23) |
Pension Benefits [Member] | PSE&G [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 29 | 40 | (19) |
Pension Benefits [Member] | Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 16 | 21 | (7) |
Pension Benefits [Member] | Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 11 | 13 | 3 |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 71 | 87 | 70 |
Total Benefit Costs | 71 | 87 | 70 |
Other Benefits [Member] | PSE&G [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 43 | 55 | 46 |
Other Benefits [Member] | Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 23 | 27 | 20 |
Other Benefits [Member] | Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 5 | $ 5 | $ 4 |
Pension, OPEB and Savings Pla93
Pension, OPEB and Savings Plans (Pre-Tax Changes Recognized In Accumulated Other Comprehensive Income (Loss), Regulatory Assets And Deferred Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net Actuarial (Gain) Loss in Current Period | $ 211 | $ 136 |
Amortization of Net Actuarial Gain (Loss) | (158) | (150) |
Prior Service Cost (Credit) in current period | 1 | 0 |
Amortization of Prior Service Credit | 19 | 19 |
Total | 73 | 5 |
Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net Actuarial (Gain) Loss in Current Period | 125 | (14) |
Amortization of Net Actuarial Gain (Loss) | (40) | (43) |
Prior Service Cost (Credit) in current period | (3) | 0 |
Amortization of Prior Service Credit | 14 | 14 |
Total | $ 96 | $ (43) |
Pension, OPEB and Savings Pla94
Pension, OPEB and Savings Plans (Amounts Expected To Be Amortized From Accumulated OCL, Regulatory Assets And Deferred Assets Into Net Periodic Benefit Cost) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Actuarial (Gain) Loss | $ 97 |
Prior Service Cost | (18) |
Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Actuarial (Gain) Loss | 51 |
Prior Service Cost | $ (11) |
Pension, OPEB and Savings Pla95
Pension, OPEB and Savings Plans (Assumptions Used To Determine The Benefit Obligations And Net Periodic Benefit Costs) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.29% | 4.54% | 4.20% |
Expected Return on Plan Assets | 8.00% | 8.00% | 8.00% |
Rate of Compensation Increase | 3.61% | 3.61% | 3.61% |
Service Cost Interest Rate | 4.81% | 4.20% | 5.00% |
Interest Cost Interest Rate | 3.75% | 4.20% | 5.00% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.61% | 3.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.54% | 4.20% | 5.00% |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.37% | 4.58% | 4.21% |
Expected Return on Plan Assets | 8.00% | 8.00% | 8.00% |
Rate of Compensation Increase | 3.61% | 3.61% | 3.61% |
Service Cost Interest Rate | 4.87% | 4.21% | 5.01% |
Interest Cost Interest Rate | 3.76% | 4.21% | 5.01% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.61% | 3.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.58% | 4.21% | 5.01% |
Administrative Expense | 3.00% | 3.00% | 3.00% |
Immediate Rate | 7.55% | 7.75% | 7.40% |
Ultimate Rate | 4.75% | 4.75% | 5.00% |
Year Ultimate Rate Reached | 2,025 | 2,025 | 2,022 |
Total of Service Cost and Interest Cost effect of 1 percent increase | $ 11 | $ 12 | $ 13 |
Postretirement Benefit Obligation effect of 1 percent increase | 191 | 194 | 201 |
Total of Service Cost and Interest Cost effect of 1 percent decrease | (9) | (10) | (10) |
Postretirement Benefit Obligation effect of 1 percent decrease | $ (160) | $ (160) | $ (165) |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.61% | 4.92% | 4.50% |
Expected Return on Plan Assets | 7.70% | ||
Rate of Compensation Increase | 3.25% | 3.25% | 3.25% |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.71% | 4.97% | 4.60% |
Rate of Compensation Increase | 3.25% | 3.25% | 3.25% |
Administrative Expense | 5.00% | 5.00% | 5.00% |
Immediate Rate | 7.55% | 7.55% | 7.33% |
Ultimate Rate | 4.75% | 4.75% | 5.00% |
Year Ultimate Rate Reached | 2,025 | 2,025 | 2,021 |
Postretirement Benefit Obligation effect of 1 percent increase | $ 97 | $ 75 | $ 160 |
Postretirement Benefit Obligation effect of 1 percent decrease | $ (75) | $ (60) | $ (106) |
Pension, OPEB and Savings Pla96
Pension, OPEB and Savings Plans (Fair Value Measurements And The Levels Of Inputs Used In Determining Fair Values) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | ||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [1] | $ 5,599 | $ 5,405 | |
Interest and dividend receivables | 14 | 8 | ||
Cash Equivalents [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [2] | 107 | 96 | |
Equity Securities [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 944 | 816 | |
Equity Securities [Member] | Preferred Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 1 | ||
Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3],[4] | 1,387 | 1,463 | |
Government-Other [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 263 | 279 | |
US Treasury Obligations [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 441 | 322 | |
Corporate [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 836 | 906 | |
Subtotal before Measured at Net Asset Value Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 3,979 | 3,882 | ||
Commingled Equities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1,604 | 1,504 | ||
Private Equity [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [6] | 16 | 19 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [1] | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Cash Equivalents [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [2] | 105 | 95 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Equity Securities [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 944 | 816 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Equity Securities [Member] | Preferred Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 1 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3],[4] | 1,247 | 1,269 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Government-Other [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | US Treasury Obligations [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Corporate [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 2,297 | 2,180 | ||
Significant Other Observable Inputs (Level 2) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [1] | |||
Significant Other Observable Inputs (Level 2) [Member] | Cash Equivalents [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [2] | 2 | 1 | |
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 0 | 0 | |
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member] | Preferred Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3],[4] | 140 | 194 | |
Significant Other Observable Inputs (Level 2) [Member] | Government-Other [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 263 | 279 | |
Significant Other Observable Inputs (Level 2) [Member] | US Treasury Obligations [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 441 | 322 | |
Significant Other Observable Inputs (Level 2) [Member] | Corporate [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 836 | 906 | |
Significant Other Observable Inputs (Level 2) [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1,682 | 1,702 | ||
Significant Other Observable Inputs (Level 2) [Member] | Other Securities [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 1,698 | |||
Pension And OPEB Plans Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [1] | |||
Pension And OPEB Plans Level 3 [Member] | Cash Equivalents [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [2] | 0 | 0 | |
Pension And OPEB Plans Level 3 [Member] | Equity Securities [Member] | Common Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 0 | 0 | |
Pension And OPEB Plans Level 3 [Member] | Equity Securities [Member] | Preferred Stock [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3] | 0 | ||
Pension And OPEB Plans Level 3 [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [3],[4] | 0 | 0 | |
Pension And OPEB Plans Level 3 [Member] | Government-Other [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 0 | 0 | |
Pension And OPEB Plans Level 3 [Member] | US Treasury Obligations [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | [5] | 0 | |
Pension And OPEB Plans Level 3 [Member] | Corporate [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [5] | 0 | 0 | |
Pension And OPEB Plans Level 3 [Member] | Subtotal before Measured at Net Asset Value Practical Expedient [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 134 | 97 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 96 | 68 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 38 | 29 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 0 | 0 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Fixed Income Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 0 | 0 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 134 | 97 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 96 | 68 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Fixed Income Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 38 | 29 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | 0 | 0 | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Equities Commingled - US [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | 0 | 0 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Fixed Income Funds [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair value of plan assets | [7] | $ 0 | $ 0 | |
[1] | Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015, respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. | |||
[2] | Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active market (Level 1). Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). | |||
[3] | Common stocks and preferred stocks are measured using observable data in active markets and considered Level 1. Investments in certain commingled equity funds are measured at their published daily net asset value (NAV) available to investors; if they are redeemable daily without restrictions, they are classified as Level 1 or, if they have restrictions which prevent daily redemptions, they are classified as Level 2. | |||
[4] | In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled equity funds. As a result, PSEG determined that certain commingled funds in the amount of $1,698 million at December 31, 2015 should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at their published price. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report such investments as Level 2. In addition, as part of our implementation of the new accounting guidance on investments measured at fair value using NAV as a practical expedient in 2016, the majority of these same commingled equity funds have been removed from the fair value hierarchy as they are measured at fair value using the NAV per share (or its equivalent) practical expedient. See Note 2. Recent Accounting Standards. These funds do not meet the definition of readily determinable fair value due to limitations in published NAV (last business day of the month) and include certain redemption restrictions ranging from one to fifteen days advance notice prior to redemption days and limitations on withdrawals over 25% of the total fund. The objectives of these funds are mainly tracking the S&P Index or achieving long-term growth through investment in foreign equity securities and the MSCI Emerging Markets Index. As a result of the error correction for the $1,698 million that should have been classified as Level 2 for 2015 and $1,504 million that was removed from the fair value hierarchy as part of the new guidance on NAV practical expedient implementation, $194 million has been reclassified to Level 2 as of December 31, 2015. | |||
[5] | Fixed income securities include mainly investment grade corporate and municipal bonds, US Treasury obligations and Federal Agency asset-backed securities with a wide range of maturities. These investments are valued using an evaluated pricing approach that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads or the most recent quoted for similar securities which are a Level 2 measure. | |||
[6] | Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. | |||
[7] | Investments in commingled equity and bond funds have a readily determinable fair value as they publish a daily NAV available to investors which is the basis for current transactions and contain certain redemption restrictions requiring advance notice of one to two days for withdrawals (Level 2). In 2016, PSEG re-evaluated the classification, within the fair value hierarchy, of its commingled funds. As a result, PSEG determined that the commingled equity funds should have been classified as Level 2 instead of Level 1, as previously presented for 2015, due to the funds having certain redemption restrictions which prevent daily redemptions at the published price. In addition to the advance notice of one or two days, redemption days may be limited to twice per month for certain funds. PSEG has determined that this error is immaterial to its previously filed financial reports and, accordingly, has corrected the error by revising the amounts disclosed for 2015 to report the commingled equity fund balance of $68 million as of December 31, 2015 as Level 2. |
Pension, OPEB and Savings Pla97
Pension, OPEB and Savings Plans (Reconciliations Of The Beginning And Ending Balances Of Pension And OPEB Plans' Level 3 Assets) (Details) $ in Millions | Dec. 31, 2016USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | ||
Fair Value of Assets at Beginning of Year | $ 5,405 | [1] |
Fair Value of Assets at End of Year | 5,599 | [1] |
Pension And OPEB Plans Level 3 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair Value of Assets at Beginning of Year | [1] | |
Fair Value of Assets at End of Year | [1] | |
Private Equity [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Fair Value of Assets at Beginning of Year | 19 | [2] |
Fair Value of Assets at End of Year | $ 16 | [2] |
[1] | Excludes net receivable of $14 million and $8 million at December 31, 2016 and 2015, respectively, which consists of interest and dividend, receivables and payables related to pending securities sales and purchases. | |
[2] | Private equity investments include various limited partnerships that invest in operating companies through acquisitions or developing a portfolio of non-US distressed investments. These investments are valued at NAV on an annual basis and have significant redemption restrictions preventing redemption until fund liquidation and limited ability to sell these investments. These investments have been removed from the fair value hierarchy in accordance with the new guidance on NAV practical expedient. |
Pension, OPEB and Savings Pla98
Pension, OPEB and Savings Plans (Schedule Of Percentage Of Fair Value Of Total Plan Assets) (Details) | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 100.00% | 100.00% |
Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 70.00% | 70.00% |
Fixed Income Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 28.00% | 28.00% |
Other Investments [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 2.00% | 2.00% |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 100.00% | 100.00% |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Equity Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 71.00% | 71.00% |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Fixed Income Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 29.00% | 29.00% |
Pension, OPEB and Savings Pla99
Pension, OPEB and Savings Plans (Estimated Future Benefit Payments) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Payments Expected Next Twelve Months | $ 310 |
Payments Expected Year Two | 307 |
Payments Expected Year Three | 319 |
Payments Expected Year Four | 331 |
Payments Expected Year Five | 343 |
Payments Expected Thereafter | 1,887 |
Total Estimated Future Benefit Payments | 3,497 |
Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Payments Expected Next Twelve Months | 82 |
Payments Expected Year Two | 86 |
Payments Expected Year Three | 90 |
Payments Expected Year Four | 94 |
Payments Expected Year Five | 99 |
Payments Expected Thereafter | 534 |
Total Estimated Future Benefit Payments | 985 |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Payments Expected Next Twelve Months | 2 |
Payments Expected Year Two | 3 |
Payments Expected Year Three | 5 |
Payments Expected Year Four | 7 |
Payments Expected Year Five | 8 |
Payments Expected Thereafter | 76 |
Total Estimated Future Benefit Payments | 101 |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Payments Expected Next Twelve Months | 4 |
Payments Expected Year Two | 6 |
Payments Expected Year Three | 9 |
Payments Expected Year Four | 11 |
Payments Expected Year Five | 13 |
Payments Expected Thereafter | 96 |
Total Estimated Future Benefit Payments | $ 139 |
Pension, OPEB and Savings Pl100
Pension, OPEB and Savings Plans (Schedule Of Amount Paid For Employer Matching Contributions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | $ 41 | $ 39 | $ 36 |
Power [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | 12 | 12 | 11 |
PSE&G [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | 24 | 22 | 20 |
Other [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | $ 5 | $ 5 | $ 5 |
Commitments And Contingent L101
Commitments And Contingent Liabilities (Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions) (Detail) - Power [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Other Commitments [Line Items] | ||
Face Value of Outstanding Guarantees | $ 1,806 | $ 1,734 |
Exposure under Current Guarantees | 139 | 172 |
Letters of Credit Margin Posted | 157 | 122 |
Letters of Credit Margin Received | 99 | 192 |
Counterparty Cash Margin Deposited | 0 | 0 |
Counterparty Cash Margin Received | (1) | (15) |
Net Broker Balance Deposited (Received) | 57 | (5) |
Other Letters of Credit | 51 | $ 51 |
755 MW Gas-Fired Combined Cycle Generating Station [Member] | ||
Other Commitments [Line Items] | ||
Face Value of Outstanding Guarantees | 21 | |
PennEast Natural Gas Pipeline [Member] | ||
Other Commitments [Line Items] | ||
Face Value of Outstanding Guarantees | $ 106 |
Commitments And Contingent L102
Commitments And Contingent Liabilities (Environmental Matters) (Detail) | 1 Months Ended | 12 Months Ended | |||||
Jun. 30, 2008USD ($) | Dec. 31, 2016USD ($)Potentially_Responsible_PartyentitysiteStationPlantmi | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Mar. 31, 2007Potentially_Responsible_Party | Dec. 31, 2006 | Dec. 31, 2003Potentially_Responsible_Party | |
Site Contingency [Line Items] | |||||||
Percentage of residential gas supply permitted to be recovered in gas hedging by BPU | 80.00% | ||||||
Number of miles related to the Passaic River constituting a facility as determined by the US Environmental Protection Agency | mi | 17 | ||||||
Number Of Miles Pertaining To Passaic River Tidal Reach Required To Be Studied By Epa | mi | 8 | ||||||
Number of legal entities contacted by EPA in conjunction with Newark Bay study area contamination | entity | 11 | ||||||
Number of operating electric generating stations located on Hackensack River | Station | 2 | ||||||
Number of former MGP contamination sites located on Hackensack river in conjunction with Newark Bay study area contamination | site | 1 | ||||||
Accrued environmental costs | $ 401,000,000 | $ 415,000,000 | |||||
Operation and Maintenance | 3,008,000,000 | 2,978,000,000 | $ 3,150,000,000 | ||||
New England Generation Fleet | 13,156,000,000 | 11,842,000,000 | |||||
Clean Energy Program Current | 142,000,000 | 142,000,000 | |||||
PSE&G [Member] | |||||||
Site Contingency [Line Items] | |||||||
Percentage Of Cost Attributable To Potentially Responsible Party | 7.00% | ||||||
Accrued environmental costs | 332,000,000 | 365,000,000 | |||||
Regulatory assets | 3,518,000,000 | 3,360,000,000 | |||||
Operation and Maintenance | 1,475,000,000 | 1,560,000,000 | 1,558,000,000 | ||||
New England Generation Fleet | 591,000,000 | 569,000,000 | |||||
Clean Energy Program Current | $ 142,000,000 | 142,000,000 | |||||
Power [Member] | |||||||
Site Contingency [Line Items] | |||||||
Ownership Percentage Of Keystone Coal Fired Plant In Pennsylvania | 23.00% | ||||||
Operation and Maintenance | $ 1,143,000,000 | 1,057,000,000 | $ 1,186,000,000 | ||||
New England Generation Fleet | 12,565,000,000 | $ 11,273,000,000 | |||||
PSD NSR Regulations Site Contingency [Member] | Power [Member] | |||||||
Site Contingency [Line Items] | |||||||
Penalty per day from date of violation-minimum | 25,000 | ||||||
Penalty per day from date of violation-maximum | 37,500 | ||||||
MGP Remediation Site Contingency [Member] | PSE&G [Member] | |||||||
Site Contingency [Line Items] | |||||||
Estimated expenditures, low end of range | 403,000,000 | ||||||
Estimated expenditures, high end of range | 460,000,000 | ||||||
Accrued environmental costs | 403,000,000 | ||||||
Remediation liability recorded as other current liabilities | 81,000,000 | ||||||
Remediation liability recorded as environmental costs in noncurrent liabilities | 322,000,000 | ||||||
Regulatory assets | 403,000,000 | ||||||
Remedial Investigation And Feasibility Study [Member] | |||||||
Site Contingency [Line Items] | |||||||
Estimated, total cost of the study | 30,000,000 | ||||||
Estimated Total Cost Of Study Low End of Range | $ 25,000,000 | ||||||
Passaic River mile 10.9 contaminant removal [Member] | |||||||
Site Contingency [Line Items] | |||||||
Percentage Of Cost Attributable To Potentially Responsible Party | 3.00% | ||||||
PSE&G's Former MGP Sites [Member] | |||||||
Site Contingency [Line Items] | |||||||
Estimated, total cost of the study | $ 190,000,000 | ||||||
Number Of Potentially Responsible Parties In Connection With Environmental Liabilities For Operations Conducted Near Passaic River | Potentially_Responsible_Party | 52 | 73 | |||||
Number of MGP sites identified by registrant and the NJDEP requiring some level of remedial action | site | 38 | ||||||
Total Spend of Study to date | $ 158,000,000 | ||||||
Company Share of Total Spend of Study to date | 11,000,000 | ||||||
PSE&G's Former MGP Sites [Member] | Power [Member] | |||||||
Site Contingency [Line Items] | |||||||
Percentage Of Cost Attributable To Potentially Responsible Party | 1.00% | ||||||
Passaic River Site Contingency [Member] | |||||||
Site Contingency [Line Items] | |||||||
Estimated Cleanup Costs EPA Preferred Method | 2,300,000,000 | ||||||
Estimated cleanup costs agreed to by two potentially responsible parties | $ 80,000,000 | ||||||
Aggregate number of PRPs directed by the NJDEP to arrange for natural resource damage assessment and interim compensatory restoration along the lower Passaic River | Potentially_Responsible_Party | 56 | ||||||
Estimated cost of interim natural resource injury restoration | 950,000,000 | ||||||
CPG Estimated Cleanup Costs Low Estimate | 518,000,000 | ||||||
CPG Estimated Cleanup Costs High Estimate | 3,200,000,000 | ||||||
CPG Targeted Method Cleanup Costs Low Estimate | 518,000,000 | ||||||
CPG Targeted Remedy Cleanup Costs High Estimate | 772,000,000 | ||||||
Accrual for Environmental Loss Contingencies | $ 57,000,000 | ||||||
Passaic River Site Contingency [Member] | Transferred To Power From PSE&G [Member] | |||||||
Site Contingency [Line Items] | |||||||
Number of operating electric generating station (Essex Site) | Plant | 1 | ||||||
Passaic River Site Contingency [Member] | PSE&G [Member] | |||||||
Site Contingency [Line Items] | |||||||
Number of former generating electric station | Plant | 1 | ||||||
Number of former Manufactured Gas Plant (MGP) sites | Plant | 4 | ||||||
CPG Targeted Method Cleanup Costs Low Estimate | $ 10,000,000 | ||||||
Accrual for Environmental Loss Contingencies, Period Increase (Decrease) | 36,000,000 | ||||||
Accrual for Environmental Loss Contingencies | 46,000,000 | ||||||
Passaic River Site Contingency [Member] | Power [Member] | |||||||
Site Contingency [Line Items] | |||||||
CPG Targeted Method Cleanup Costs Low Estimate | 3,000,000 | ||||||
Accrual for Environmental Loss Contingencies, Period Increase (Decrease) | 8,000,000 | ||||||
Accrual for Environmental Loss Contingencies | $ 11,000,000 |
Commitments And Contingent L103
Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Detail) cf in Billions | 12 Months Ended | |
Dec. 31, 2016cf$ / mwd$ / mwhMW | ||
Long-term Purchase Commitment [Line Items] | ||
Number of cubic feet in gas hedging permitted to be recovered by BPU | cf | 115 | |
Percentage of residential gas supply permitted to be recovered in gas hedging by BPU | 80.00% | |
Percentage of annual residential gas supply requirements to be hedged | 50.00% | |
Number of cubic feet to be hedged | cf | 70 | |
PSE&G [Member] | Auction Year 2014 [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
36-Month Terms Ending | May 31, 2017 | |
Load (MW) | MW | 2,800 | |
Dollars Per Megawatt Hour | $ / mwh | 97.39 | |
PSE&G [Member] | Auction Year 2015 [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
36-Month Terms Ending | May 31, 2018 | |
Load (MW) | MW | 2,900 | |
Dollars Per Megawatt Hour | $ / mwh | 99.54 | |
PSE&G [Member] | Auction Year 2016 [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
36-Month Terms Ending | May 31, 2019 | |
Load (MW) | MW | 2,800 | |
$ per kWh | $ / mwd | 335.33 | |
Dollars Per Megawatt Hour | $ / mwh | 96.38 | |
PSE&G [Member] | Auction Year 2017 [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
36-Month Terms Ending | May 31, 2020 | [1] |
Load (MW) | MW | 2,800 | |
$ per kWh | $ / mwd | 276.83 | |
Dollars Per Megawatt Hour | $ / mwh | 90.78 | |
[1] | Prices set in the 2017 BGS auction will become effective on June 1, 2017 when the 2014 BGS auction agreements expire. |
Commitments And Contingent L104
Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Detail) - Power [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Coverage percentage of nuclear fuel commitments of uranium, enrichment, and fabrication requirements | 100.00% |
Commitments Through 2017 [Member] | Nuclear Fuel Uranium [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | $ 301 |
Commitments Through 2017 [Member] | Nuclear Fuel Enrichment [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 356 |
Commitments Through 2017 [Member] | Nuclear Fuel Fabrication [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 192 |
Commitments Through 2017 [Member] | Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 1,029 |
Commitments Through 2017 [Member] | Coal [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | $ 215 |
Commitments And Contingent L105
Commitments And Contingent Liabilities (Regulatory Proceedings) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Loss Contingencies [Line Items] | |||
Costs recognized in Operation and Maintenance Expense | $ 3,008 | $ 2,978 | $ 3,150 |
Insured Event, Gain (Loss) | 28 | ||
PSE&G [Member] | |||
Loss Contingencies [Line Items] | |||
Costs recognized in Operation and Maintenance Expense | 1,475 | 1,560 | 1,558 |
Insured Event, Gain (Loss) | 0 | ||
Power [Member] | |||
Loss Contingencies [Line Items] | |||
Costs recognized in Operation and Maintenance Expense | $ 1,143 | 1,057 | $ 1,186 |
Insured Event, Gain (Loss) | 28 | ||
Power [Member] | Regulatory Agency [Domain] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Loss in Period | $ 25 |
Commitments And Contingent L106
Commitments And Contingent Liabilities (Nuclear Insurance Coverages and Assessments) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Jan. 31, 2017USD ($) | Dec. 31, 2016USD ($)MW | ||
Other Commitments [Line Items] | |||
Retrospective Assessment Power Generation | MW | 100 | ||
Inflation Adjustment For Assessment Years | 5 years | ||
Nuclear Insurance Aggregate Limit | $ 3,200 | ||
Ownership Interest Per Reactor Per Incident | 127 | ||
Ownership Interest Payable Per Reactor Per Incident Per Year | 19 | ||
Maximum Aggregate Assessment Per Incident | 401 | ||
Maximum Aggregate Annual Assessment | 60 | ||
Property limit in excess | 1,500 | ||
Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Nuclear Liability, Total | [1] | 13,361 | |
Replacement Power Total | |||
Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Nuclear Liability, Total | [1] | 401 | |
Replacement Power Total | 78 | ||
Power With Exelon Generation [Member] | |||
Other Commitments [Line Items] | |||
Blanket limit shared | 300 | ||
ANI [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Public and Nuclear Worker Liability, Primary Layer | [2] | 375 | |
ANI [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Public and Nuclear Worker Liability, Primary Layer | [2] | 0 | |
Price-Anderson Act [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Nuclear Liability, Excess Layer | [3] | 12,986 | |
Price-Anderson Act [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Nuclear Liability, Excess Layer | [3] | 401 | |
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Primary Layer | 1,500 | ||
Property Damage, Excess Layers | [4] | 300 | |
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Primary Layer | 35 | ||
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Retrospective Assessments Nuclear [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 2 | |
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Retrospective Assessments, Non-Nuclear [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 1 | |
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Total Site Coverage for Non Nuclear Event [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 300 | |
NEIL I (Peach Bottom) [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Primary Layer | 1,500 | ||
Property Damage, Excess Layers | [4] | 300 | |
Accidental Outage | [5] | 245 | |
Indemnity limit on weekly indemnity | $ 2.3 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 476 days | ||
NEIL I (Peach Bottom) [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Primary Layer | $ 14 | ||
Accidental Outage | [5] | 8 | |
NEIL I (Peach Bottom) [Member] | Retrospective Assessments Nuclear [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 1 | |
NEIL I (Peach Bottom) [Member] | Retrospective Assessments, Non-Nuclear [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 1 | |
NEIL I (Peach Bottom) [Member] | Total Site Coverage for Non Nuclear Event [Member] | |||
Other Commitments [Line Items] | |||
Property Damage, Excess Layers | [4] | 600 | |
Accidental Outage | [5] | 164 | |
Indemnity limit on weekly indemnity | $ 2.3 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 168 days | ||
NEIL 1 (Salem) [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | $ 281 | |
Indemnity limit on weekly indemnity | $ 2.5 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 532 days | ||
NEIL 1 (Salem) [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | $ 9 | |
NEIL 1 (Salem) [Member] | Total Site Coverage for Non Nuclear Event [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | 188 | |
Indemnity limit on weekly indemnity | $ 2.5 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 203 days | ||
NEIL I (Hope Creek) [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | $ 490 | |
Indemnity limit on weekly indemnity | $ 4.5 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 497 days | ||
NEIL I (Hope Creek) [Member] | Retrospective Assessments [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | $ 7 | |
NEIL I (Hope Creek) [Member] | Total Site Coverage for Non Nuclear Event [Member] | |||
Other Commitments [Line Items] | |||
Accidental Outage | [5] | 328 | |
Indemnity limit on weekly indemnity | $ 4.5 | ||
Weekly indemnity, time period | 364 days | ||
Indemnity period, after initial period, percentage | 80.00% | ||
Indemnity period, after initial period, time period | 182 days | ||
Subsequent Event [Member] | ANI [Member] | Total Site Coverage [Member] | |||
Other Commitments [Line Items] | |||
Public and Nuclear Worker Liability, Primary Layer | [2] | $ 450 | |
[1] | Maximum limit of liability under the Price-Anderson Act for each nuclear incident per site. | ||
[2] | The primary limit for Public Liability is a per site aggregate limit with no potential for retrospective assessment. The Nuclear Worker Liability represents the potential liability from third-party workers claiming exposure to the nuclear energy hazard. This coverage is subject to an industry aggregate limit that is subject to reinstatement at ANI discretion. | ||
[3] | Retrospective premium program under the Price-Anderson Act liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of September 10, 2013. The next adjustment is due on or before September 10, 2018. This retrospective program is in excess of the Public and Nuclear Worker Liability primary layers. | ||
[4] | For nuclear event property limits in excess of $1.5 billion, Power purchases a $300 million Excess Policy for the Salem/Hope Creek site, and a $300 million Excess Policy only for Power’s 50% interest in Peach Bottom. This limit is not subject to reinstatement in the event of a loss. In addition, for non-nuclear event limits in excess of $1.5 billion, Power maintains a $300 million limit for the combined Salem/Hope Creek sites. Exelon maintains a $600 million non-nuclear event limit for Peach Bottom. | ||
[5] | Peach Bottom 2 and 3 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Peach Bottom 2 and 3 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 24 weeks. Salem 1 and 2 have an aggregate nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 weeks. Salem 1 and 2 have an aggregate non-nuclear indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 29 weeks. Hope Creek has an aggregate nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. Hope Creek has an aggregate non-nuclear indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 26 weeks. |
Commitments And Contingent L107
Commitments And Contingent Liabilities (Future Minimum Lease Payments) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Other Commitments [Line Items] | |
Due Next Twelve Months | $ 29 |
Due in Two Years | 25 |
Due in Three Years | 24 |
Due in Four Years | 22 |
Due in Five Years | 23 |
Thereafter | 232 |
Capital Leases, Future Minimum Payments Due | 355 |
PSE&G [Member] | |
Other Commitments [Line Items] | |
Due Next Twelve Months | 12 |
Due in Two Years | 8 |
Due in Three Years | 7 |
Due in Four Years | 6 |
Due in Five Years | 6 |
Thereafter | 61 |
Capital Leases, Future Minimum Payments Due | 100 |
Power [Member] | |
Other Commitments [Line Items] | |
Due Next Twelve Months | 3 |
Due in Two Years | 3 |
Due in Three Years | 3 |
Due in Four Years | 2 |
Due in Five Years | 2 |
Thereafter | 39 |
Capital Leases, Future Minimum Payments Due | 52 |
Services [Member] | |
Other Commitments [Line Items] | |
Due Next Twelve Months | 13 |
Due in Two Years | 13 |
Due in Three Years | 13 |
Due in Four Years | 13 |
Due in Five Years | 14 |
Thereafter | 132 |
Capital Leases, Future Minimum Payments Due | 198 |
Other [Member] | |
Other Commitments [Line Items] | |
Due Next Twelve Months | 1 |
Due in Two Years | 1 |
Due in Three Years | 1 |
Due in Four Years | 1 |
Due in Five Years | 1 |
Thereafter | 0 |
Capital Leases, Future Minimum Payments Due | $ 5 |
Schedule Of Consolidated Deb108
Schedule Of Consolidated Debt (Long-Term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 11,483 | ||
Long-term Debt, Current Maturities | (500) | $ (734) | |
Total Long-Term Debt | 10,895 | 8,834 | |
Power [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | 2,400 | 2,253 | |
Long-term Debt, Current Maturities | 0 | (553) | |
Net Unamortized Discount and Debt Issuance Costs | (18) | (16) | |
Total Long-Term Debt | 2,382 | 1,684 | |
Power [Member] | Senior Notes Five Point Three Two Percentage Due Two Thousand Sixteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 0 | 303 | |
Stated interest rate of debt instrument | 5.32% | ||
Maturity Year | 2,016 | ||
Power [Member] | Senior Notes Two Point Seven Five Percentage Due Two Thousand Sixteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 0 | 250 | |
Stated interest rate of debt instrument | 2.75% | ||
Maturity Year | 2,016 | ||
Power [Member] | Senior Notes Two Point Four Five Percentage Due Two Thousand Eighteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 250 | 250 | |
Stated interest rate of debt instrument | 2.45% | ||
Maturity Year | 2,018 | ||
Power [Member] | Senior Notes Five Point One Three Percentage Due Two Thousand Twenty [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 406 | 406 | |
Stated interest rate of debt instrument | 5.13% | ||
Maturity Year | 2,020 | ||
Power [Member] | Senior Notes Four Point One Five Percentage Due Two Thousand Twenty One [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 250 | 250 | |
Stated interest rate of debt instrument | 4.15% | ||
Maturity Year | 2,021 | ||
Power [Member] | Senior Notes Three Point Zero Percent Due In Two Thousand Twenty One [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 700 | 0 | |
Stated interest rate of debt instrument | 3.00% | ||
Maturity Year | 2,021 | ||
Power [Member] | Senior Notes Four Point Three Percent Due Two Thousand Twenty Three [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 250 | 250 | |
Stated interest rate of debt instrument | 4.30% | ||
Maturity Year | 2,023 | ||
Power [Member] | Senior Notes Eight Point Six Three Percent Due Two Thousand Thirty One [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 500 | 500 | |
Stated interest rate of debt instrument | 8.63% | ||
Maturity Year | 2,031 | ||
Power [Member] | Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 2,356 | 2,209 | |
Power [Member] | Pollution Control Notes Floating Rate Due On Two Thousand Nineteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [1] | $ 44 | 44 |
Maturity Year | [1] | 2,019 | |
Power [Member] | Pollution Control Notes [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 44 | 44 | |
PSEG [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | 1,200 | 500 | |
Fair Value Of Swaps | [2] | 0 | 6 |
Long-term Debt, Current Maturities | (500) | (6) | |
Net Unamortized Discount and Debt Issuance Costs | (5) | 0 | |
Total Long-Term Debt | 695 | 500 | |
PSEG [Member] | Variable Rate Term Loan due 2017 [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 500 | 500 | |
Maturity Year | 2,017 | ||
PSEG [Member] | Senior Notes One Point Six Zero Percent Due In Two Thousand Nineteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 400 | 0 | |
Stated interest rate of debt instrument | 1.60% | ||
Maturity Year | 2,019 | ||
PSEG [Member] | Senior Notes Two Point Zero Percent Due In Two Thousand Twenty One [Member] [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 300 | 0 | |
Stated interest rate of debt instrument | 2.00% | ||
Maturity Year | 2,021 | ||
PSEG [Member] | Senior Notes [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 700 | 0 | |
PSE&G [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt, Current Maturities | 0 | (171) | |
Total Long-Term Debt | 7,818 | 6,650 | |
PSE&G [Member] | First And Refunding Mortgage Bonds Six Point Seven Five Percentage Due On Two Thousand Sixteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 0 | 171 |
Stated interest rate of debt instrument | 6.75% | ||
Maturity Year | [3] | 2,016 | |
PSE&G [Member] | First And Refunding Mortgage Bonds Nine Point Two Five Percentage Due On Two Twenty One [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 134 | 134 |
Stated interest rate of debt instrument | 9.25% | ||
Maturity Year | [3] | 2,021 | |
PSE&G [Member] | First And Refunding Mortgage Bonds Eight Point Zero Zero Percentage Due On Two Thirty Seven [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 7 | 7 |
Stated interest rate of debt instrument | 8.00% | ||
Maturity Year | [3] | 2,037 | |
PSE&G [Member] | First And Refunding Mortgage Bonds Five Point Zero Zero Percentage Due On Two Thirty Seven [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 8 | 8 |
Stated interest rate of debt instrument | 5.00% | ||
Maturity Year | [3] | 2,037 | |
PSE&G [Member] | First And Refunding Mortgage Bonds [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 149 | 320 | |
PSE&G [Member] | Pollution Control Bonds Due On 2033 [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [1],[3] | $ 0 | 50 |
Maturity Year | [1],[3] | 2,033 | |
PSE&G [Member] | Pollution Control Bonds Due On 2046 [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [1],[3] | $ 0 | 50 |
Maturity Year | [1],[3] | 2,046 | |
PSE&G [Member] | Pollution Control Bonds [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 0 | 100 | |
PSE&G [Member] | Medium Term Notes Five Point Three Zero Percentage Due On Two Thousand Eighteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 400 | 400 |
Stated interest rate of debt instrument | 5.30% | ||
Maturity Year | [3] | 2,018 | |
PSE&G [Member] | Medium Term Notes Two Point Three Zero Percent Due In Two Thousand Eighteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 350 | 350 |
Stated interest rate of debt instrument | 2.30% | ||
Maturity Year | [3] | 2,018 | |
PSE&G [Member] | Medium Term Notes One Point Eight Percent Due In Two Thousand Nineteen [Member] [Domain] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 1.80% | ||
Maturity Year | [3] | 2,019 | |
PSE&G [Member] | Medium Term Notes Two Point Zero Percent Due In Two Thousand Nineteen [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 2.00% | ||
Maturity Year | [3] | 2,019 | |
PSE&G [Member] | Medium Term Notes Seven Point Zero Four Percentage Due On Two Thousand Twenty [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 9 | 9 |
Stated interest rate of debt instrument | 7.04% | ||
Maturity Year | [3] | 2,020 | |
PSE&G [Member] | Medium Term Notes Three Point Five Zero Percentage Due On Two Thousand Twenty [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 3.50% | ||
Maturity Year | [3] | 2,020 | |
PSE&G [Member] | Medium Term Notes One Point Nine Zero Percent Due In Two Thousand Twenty One [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 300 | 0 |
Stated interest rate of debt instrument | 1.90% | ||
Maturity Year | [3] | 2,021 | |
PSE&G [Member] | Medium Term Notes Two Point Three Eight Percent Due In Two Thousand Twenty Three [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 500 | 500 |
Stated interest rate of debt instrument | 2.375% | ||
Maturity Year | [3] | 2,023 | |
PSE&G [Member] | Medium Term Notes Three Point Seven Five Percent Due In Two Thousand Twenty Four [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 3.75% | ||
Maturity Year | [3] | 2,024 | |
PSE&G [Member] | Medium Term Notes Three Point One Five Percent Due In Two Thousand Twenty Four [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 3.15% | ||
Maturity Year | [3] | 2,024 | |
PSE&G [Member] | Medium Term Notes Three Point Zero Five Percent Due In Two Thousand Twenty Four [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 3.05% | ||
Maturity Year | [3] | 2,024 | |
PSE&G [Member] | Medium Term Notes Three Point Zero Percent Due In Two Thousand Twenty Five [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 350 | 350 |
Stated interest rate of debt instrument | 3.00% | ||
Maturity Year | [3] | 2,025 | |
PSE&G [Member] | Medium Term Notes Two Point Two Five Percent due Two Thousand Twenty Six [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 425 | 0 |
Stated interest rate of debt instrument | 2.25% | ||
Maturity Year | [3] | 2,026 | |
PSE&G [Member] | Medium Term Notes Five Point Two Five Percentage Due On Two Thousand Thirty Five [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 5.25% | ||
Maturity Year | [3] | 2,035 | |
PSE&G [Member] | Medium Term Notes Five Point Seven Zero Percentage Due On Two Thousand Thirty Six [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 5.70% | ||
Maturity Year | [3] | 2,036 | |
PSE&G [Member] | Medium Term Notes Five Point Eight Zero Percentage Due On Two Thousand Thirty Seven [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 350 | 350 |
Stated interest rate of debt instrument | 5.80% | ||
Maturity Year | [3] | 2,037 | |
PSE&G [Member] | Medium Term Notes Five Point Three Eight Percentage Due On Two Thousand Thirty Nine [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 5.38% | ||
Maturity Year | [3] | 2,039 | |
PSE&G [Member] | Medium Term Notes Five Point Five Zero Percentage Due On Two Thousand Forty [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 300 | 300 |
Stated interest rate of debt instrument | 5.50% | ||
Maturity Year | [3] | 2,040 | |
PSE&G [Member] | Medium-Term Notes 3.95% Due On 2042 [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 450 | 450 |
Stated interest rate of debt instrument | 3.95% | ||
Maturity Year | [3] | 2,042 | |
PSE&G [Member] | Medium-Term Notes 3.65% Due On 2042 [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 350 | 350 |
Stated interest rate of debt instrument | 3.65% | ||
Maturity Year | [3] | 2,042 | |
PSE&G [Member] | Medium Term Notes Three Point Eight Zero Percent Due In Two Thousand Forty Three [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 400 | 400 |
Stated interest rate of debt instrument | 3.80% | ||
Maturity Year | [3] | 2,043 | |
PSE&G [Member] | Medium Term Notes Four Point Zero Percent Due In Two Thousand Forty Four [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 4.00% | ||
Maturity Year | [3] | 2,044 | |
PSE&G [Member] | Medium Term Notes Four Point Zero Five Percent due Two Thousand Forty Five [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | |
Stated interest rate of debt instrument | 4.05% | ||
Maturity Year | [3] | 2,045 | |
PSE&G [Member] | Medium Term Notes Four Point One Five Percent Due In Two Thousand Forty Five [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 250 | 250 |
Stated interest rate of debt instrument | 4.15% | ||
Maturity Year | [3] | 2,045 | |
PSE&G [Member] | Medium Term Notes Three Point Eight Zero Percent due Two Thousand Forty Six [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | [3] | $ 550 | 0 |
Stated interest rate of debt instrument | 3.80% | ||
Maturity Year | [3] | 2,046 | |
PSE&G [Member] | Total Medium Term Notes [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | $ 7,734 | 6,459 | |
PSE&G Excluding Transition Funding and Transition Funding II [Member] | |||
Debt Instrument [Line Items] | |||
Principal Amount Outstanding | 7,883 | 6,879 | |
Long-term Debt, Current Maturities | 0 | (171) | |
Net Unamortized Discount and Debt Issuance Costs | (65) | (58) | |
Total Long-Term Debt | $ 7,818 | $ 6,650 | |
[1] | The Pollution Control Financing Authority of Salem County bonds (Salem Bonds), which were repurchased and retired in 2016, and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, were variable rate bonds that were in weekly reset mode. | ||
[2] | PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheets. For additional information, see Note 16. Financial Risk Management Activities. | ||
[3] | Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. |
Schedule Of Consolidated Deb109
Schedule Of Consolidated Debt (Long-Term Debt Maturities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Repayments in Next Twelve Months | $ 500 | |
Repayments in Year Two | 1,000 | |
Repayments in Year Three | 944 | |
Repayments in Year Four | 665 | |
Repayments in Year Five | 1,684 | |
Thereafter | 6,690 | |
Total | 11,483 | |
PSEG [Member] | ||
Debt Instrument [Line Items] | ||
Repayments in Next Twelve Months | 500 | |
Repayments in Year Two | 0 | |
Repayments in Year Three | 400 | |
Repayments in Year Four | 0 | |
Repayments in Year Five | 300 | |
Thereafter | 0 | |
Total | 1,200 | $ 500 |
PSE&G | ||
Debt Instrument [Line Items] | ||
Repayments in Next Twelve Months | 0 | |
Repayments in Year Two | 750 | |
Repayments in Year Three | 500 | |
Repayments in Year Four | 259 | |
Repayments in Year Five | 434 | |
Thereafter | 5,940 | |
Total | 7,883 | 6,879 |
Power [Member] | ||
Debt Instrument [Line Items] | ||
Repayments in Next Twelve Months | 0 | |
Repayments in Year Two | 250 | |
Repayments in Year Three | 44 | |
Repayments in Year Four | 406 | |
Repayments in Year Five | 950 | |
Thereafter | 750 | |
Total | $ 2,400 | $ 2,253 |
Schedule Of Consolidated Deb110
Schedule Of Consolidated Debt (Long-Term Debt Financing Transactions) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
PSEG [Member] | Senior Notes One Point Six Zero Percent Due In Two Thousand Nineteen [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 400 |
Stated interest rate of debt instrument | 1.60% |
PSEG [Member] | Senior Notes Two Point Zero Percent Due In Two Thousand Twenty One [Member] [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 300 |
Stated interest rate of debt instrument | 2.00% |
PSE&G [Member] | Medium Term Notes Three Point Zero Percent Due In Two Thousand Twenty Five [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate of debt instrument | 3.00% |
PSE&G [Member] | Medium Term Notes Four Point Zero Five Percent due Two Thousand Forty Five [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate of debt instrument | 4.05% |
PSE&G [Member] | Medium Term Notes Four Point One Five Percent Due In Two Thousand Forty Five [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate of debt instrument | 4.15% |
PSE&G [Member] | Pollution Control Bonds [Member] | |
Debt Instrument [Line Items] | |
Repayments of Long-term Debt | $ 100 |
PSE&G [Member] | First And Refunding Mortgage Bonds Six Point Seven Five Percentage Due On Two Thousand Sixteen [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate of debt instrument | 6.75% |
Repayments of Long-term Debt | $ 171 |
PSE&G [Member] | Medium Term Notes One Point Nine Zero Percent Due In Two Thousand Twenty One [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 300 |
Stated interest rate of debt instrument | 1.90% |
PSE&G [Member] | Medium Term Notes Three Point Eight Zero Percent due Two Thousand Forty Six [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 550 |
Stated interest rate of debt instrument | 3.80% |
PSE&G [Member] | Medium Term Notes Two Point Two Five Percent due Two Thousand Twenty Six [Member] | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Long-term Debt | $ 425 |
Stated interest rate of debt instrument | 2.25% |
Power [Member] | Senior Notes Three Point Zero Percent Due In Two Thousand Twenty One [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 700 |
Stated interest rate of debt instrument | 3.00% |
Power [Member] | Senior Notes Five Point Three Two Percentage Due Two Thousand Sixteen [Member] | |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 303 |
Stated interest rate of debt instrument | 5.32% |
Power [Member] | Senior Notes Two Point Seven Five Percentage Due Two Thousand Sixteen [Member] | |
Debt Instrument [Line Items] | |
Stated interest rate of debt instrument | 2.75% |
Repayments of Long-term Debt | $ 250 |
Schedule Of Consolidated Deb111
Schedule Of Consolidated Debt (Short-Term Liquidity) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 4,153 | ||
Line of Credit Facility, Amount Outstanding | 610 | ||
Available Liquidity | 3,543 | ||
Commercial Paper and Loans | $ 388 | $ 364 | |
Commitments of single institution as percentage of total commitments | 7.00% | ||
PSEG [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,000 | ||
Line of Credit Facility, Amount Outstanding | 398 | ||
Available Liquidity | 602 | ||
PSE&G [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 600 | ||
Line of Credit Facility, Amount Outstanding | 14 | ||
Available Liquidity | 586 | ||
Commercial Paper and Loans | 0 | $ 153 | |
Power [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 2,553 | ||
Line of Credit Facility, Amount Outstanding | 198 | ||
Available Liquidity | 2,355 | ||
5-year Credit Facility, April 2019 [Member] | PSEG [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 500 | ||
Line of Credit Facility, Amount Outstanding | 10 | ||
Available Liquidity | $ 490 | ||
Expiration Date | Mar 2,019 | ||
5-year Credit Facility, April 2019 [Member] | Power [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,600 | ||
Line of Credit Facility, Amount Outstanding | 195 | ||
Available Liquidity | $ 1,405 | ||
Expiration Date | Mar 2,019 | ||
Five Year Credit Facility Maturing on April 2020 [Member] | PSEG [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | [1] | $ 500 | |
Line of Credit Facility, Amount Outstanding | [2] | 388 | |
Available Liquidity | 112 | ||
Commercial Paper and Loans | $ 388 | ||
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in March 2018 | [3] | $ 12 | |
Short-term Debt, Weighted Average Interest Rate | 1.03% | ||
Five Year Credit Facility Maturing on April 2020 [Member] | PSE&G [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | [4] | $ 600 | |
Line of Credit Facility, Amount Outstanding | [2] | 14 | |
Available Liquidity | $ 586 | ||
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in March 2018 | [3] | $ 14 | |
Five Year Credit Facility Maturing on April 2020 [Member] | Power [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | [3] | 953 | |
Line of Credit Facility, Amount Outstanding | 3 | ||
Available Liquidity | $ 950 | ||
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in March 2018 | [3] | $ 24 | |
[1] | PSEG facility will be reduced by $12 million in March 2018. | ||
[2] | The primary use of PSEG’s and PSE&G’s credit facilities is to support their respective Commercial Paper Programs under which as of December 31, 2016, PSEG had $388 million outstanding at a weighted average interest rate of 1.03%. PSE&G had no amounts outstanding under its Commercial Paper Program as of December 31, 2016. | ||
[3] | PSE&G facility will be reduced by $14 million in March 2018. | ||
[4] | Power facility will be reduced by $24 million in March 2018. |
Schedule Of Consolidated Deb112
Schedule Of Consolidated Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 11,395 | $ 9,568 | |
Long-term Debt, Fair Value | 12,003 | 10,256 | |
PSEG [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 1,195 | 503 | |
Long-term Debt, Fair Value | [1],[2] | 1,185 | 506 |
PSE&G | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 7,818 | 6,821 | |
Long-term Debt, Fair Value | [2] | 8,240 | 7,235 |
Power [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 2,382 | 2,237 | |
Long-term Debt, Fair Value | [2] | 2,578 | 2,508 |
Energy Holdings [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 0 | 7 | |
Long-term Debt, Fair Value | [3] | $ 0 | $ 7 |
[1] | Fair value includes a $500 million floating rate term loan and net offsets. The fair value of the term loan debt (Level 2 measurement) was considered to be equal to the carrying value because the interest payments are based on LIBOR rates that are reset monthly. As of December 31, 2015, carrying amount includes such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. | ||
[2] | Given that most bonds do not trade, the fair value amounts of taxable debt securities (primarily Level 2 measurements) are generally determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk into the discount rates, pricing is obtained (i.e. U.S. Treasury rate plus credit spread) based on expected new issue pricing across each of the companies’ respective debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. | ||
[3] | Non-recourse project debt was valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Schedule Of Consolidated Cap113
Schedule Of Consolidated Capital Stock (Consolidated Capital Stock) (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Class of Stock [Line Items] | |||
Common Stock, authorized | 1,000,000,000 | 1,000,000,000 | |
Common Stock, Shares, outstanding | [1] | 504,866,212 | 505,282,421 |
Common Stock, book value | [1] | $ 4,219 | $ 4,244 |
DRASPP, ESPP and various employee plans [Member] | |||
Class of Stock [Line Items] | |||
Common stock available for issuance through PSEG's DRASPP, ESPP and various employee benefit plans | 7,000,000 | ||
PSE&G [Member] | |||
Class of Stock [Line Items] | |||
Common Stock, authorized | 150,000,000 | 150,000,000 | |
PSE&G [Member] | Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Common Stock, authorized | 7,500,000 | ||
Preferred stock, par value | $ 100 | ||
PSE&G [Member] | Cumulative Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Common Stock, authorized | 10,000,000 | ||
Preferred stock, par value | $ 25 | ||
[1] | PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) or the Employee Stock Purchase Plan (ESPP) in 2016 or 2015. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to approximately 7 million shares as of December 31, 2016. |
Financial Risk Management Ac114
Financial Risk Management Activities (Schedule Of Derivative Transactions Designated And Effective As Cash Flow Hedges) (Detail) $ in Millions | Dec. 31, 2016USD ($) |
Derivative [Line Items] | |
Impact on Accumulated Other Comprehensive Income (Loss) (after tax) | $ 2 |
Financial Risk Management Ac115
Financial Risk Management Activities (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivatives, Fair Value [Line Items] | |||
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net | $ 1 | ||
Interest Rate Cash Flow Hedge Derivative at Fair Value, Net | 1 | ||
Long-term Debt | 11,483 | ||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | 2 | ||
Net cash collateral received in connection with net derivative contracts | 1 | $ (55) | |
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral | 19 | 78 | |
PSEG [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Long-term Debt | 1,200 | 500 | |
Fair value of interest rate swaps designated as underlying hedges | 6 | ||
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral | 9 | 12 | |
Additional collateral aggregate fair value | 10 | 66 | |
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges | 6 | 19 | $ 20 |
PSEG [Member] | Variable Rate Term Loan due 2017 [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Long-term Debt | $ 500 | 500 | |
PSEG [Member] | Senior Notes One Point Six Zero Percent Due In Two Thousand Nineteen [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Stated interest rate of debt instrument | 1.60% | ||
Long-term Debt | $ 400 | 0 | |
Debt Instrument, Face Amount | $ 400 | ||
PSEG [Member] | Senior Notes Two Point Zero Percent Due In Two Thousand Twenty One [Member] [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Stated interest rate of debt instrument | 2.00% | ||
Long-term Debt | $ 300 | 0 | |
Debt Instrument, Face Amount | 300 | ||
Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net Credit Exposure With Counterparties After Applying Collateral | 354 | ||
Long-term Debt | $ 2,400 | 2,253 | |
Power [Member] | Senior Notes Three Point Zero Percent Due In Two Thousand Twenty One [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Stated interest rate of debt instrument | 3.00% | ||
Long-term Debt | $ 700 | 0 | |
Debt Instrument, Face Amount | 700 | ||
Non Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | (3) | (16) | |
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | 4 | 12 | |
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | 2 | ||
Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | $ (53) | ||
Fair Value Hedging [Member] | PSEG [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Aggregate amount of series of interest rate swaps converting to variable-rate debt | 550 | ||
Cash Flow Hedging [Member] | PSEG [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Aggregate amount of series of interest rate swaps converting to variable-rate debt | 500 | ||
Cash Flow Hedging [Member] | PSEG [Member] | Senior Notes One Point Six Zero Percent Due In Two Thousand Nineteen [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Aggregate amount of series of interest rate swaps converting to variable-rate debt | 400 | ||
Cash Flow Hedging [Member] | PSEG [Member] | Senior Notes Two Point Zero Percent Due In Two Thousand Twenty One [Member] [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Aggregate amount of series of interest rate swaps converting to variable-rate debt | $ 300 |
Financial Risk Management Ac116
Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheets) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ 1 | $ (55) | |
Derivative Contracts, Current Assets | 163 | 242 | |
Derivative Contracts, Noncurrent Assets | 24 | 77 | |
Total Mark-to-Market Derivative Assets | 187 | 319 | |
Derivative Contracts, Current Liabilities | (13) | (76) | |
Derivative Contracts, Noncurrent Liabilities | (3) | (27) | |
Total Mark-to-Market Derivative (Liabilities) | (16) | (103) | |
Net Mark-to-Market Derivative Assets (Liabilities) | 171 | 216 | |
Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 162 | 223 | [1] |
Derivative Contracts, Noncurrent Assets | 24 | 77 | [1] |
Total Mark-to-Market Derivative Assets | 186 | 300 | [1] |
Derivative Contracts, Current Liabilities | (8) | (76) | [1] |
Derivative Contracts, Noncurrent Liabilities | (3) | (16) | [1] |
Total Mark-to-Market Derivative (Liabilities) | (11) | (92) | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 175 | 208 | [1] |
Power [Member] | Netting [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Total Mark-to-Market Derivative Assets | (371) | (608) | [1],[2] |
Total Mark-to-Market Derivative (Liabilities) | 372 | 553 | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 1 | (55) | [1],[2] |
PSE&G [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 0 | 13 | |
Derivative Contracts, Current Liabilities | (5) | 0 | |
Derivative Contracts, Noncurrent Liabilities | 0 | (11) | |
Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (53) | ||
Non Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (3) | (16) | |
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 4 | 12 | |
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 2 | ||
Interest Rate Swaps [Member] | PSEG [Member] | Fair Value Hedging [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 1 | 6 | [1] |
Derivative Contracts, Noncurrent Assets | 0 | 0 | [1] |
Total Mark-to-Market Derivative Assets | 1 | 6 | [1] |
Derivative Contracts, Current Liabilities | 0 | 0 | [1] |
Derivative Contracts, Noncurrent Liabilities | 0 | 0 | [1] |
Total Mark-to-Market Derivative (Liabilities) | 0 | 0 | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 1 | 6 | [1] |
Energy-Related Contracts [Member] | Not Designated as Hedging Instrument [Member] | Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 435 | 700 | [1] |
Derivative Contracts, Noncurrent Assets | 122 | 208 | [1] |
Total Mark-to-Market Derivative Assets | 557 | 908 | [1] |
Derivative Contracts, Current Liabilities | (285) | (513) | [1] |
Derivative Contracts, Noncurrent Liabilities | (98) | (132) | [1] |
Total Mark-to-Market Derivative (Liabilities) | (383) | (645) | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 174 | 263 | [1] |
Energy-Related Contracts [Member] | Not Designated as Hedging Instrument [Member] | PSE&G [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 0 | 13 | [1] |
Derivative Contracts, Noncurrent Assets | 0 | 0 | [1] |
Total Mark-to-Market Derivative Assets | 0 | 13 | [1] |
Derivative Contracts, Current Liabilities | (5) | 0 | [1] |
Derivative Contracts, Noncurrent Liabilities | 0 | (11) | [1] |
Total Mark-to-Market Derivative (Liabilities) | (5) | (11) | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | (5) | 2 | [1] |
Energy-Related Contracts [Member] | Current Assets [Member] | Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (273) | (477) | [1],[2] |
Energy-Related Contracts [Member] | Non Current Assets [Member] | Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (98) | (131) | [1],[2] |
Energy-Related Contracts [Member] | Current Liabilities [Member] | Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 277 | 437 | [1],[2] |
Energy-Related Contracts [Member] | Noncurrent Liabilities [Member] | Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ 95 | $ 116 | [1],[2] |
[1] | Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements. | ||
[2] | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset on the Consolidated Balance Sheets. As of December 31, 2016 and 2015, net cash collateral (received) paid of $1 million and $(55) million, respectively, were netted against the corresponding net derivative contract positions. Of the $1 million as of December 31, 2016, $(3) million was netted against noncurrent assets and $4 million was netted against current liabilities. Of the $(55) million as of December 31, 2015, cash collateral of $(53) million and $(16) million were netted against current assets and noncurrent assets, respectively, and $12 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. |
Financial Risk Management Ac117
Financial Risk Management Activities (Schedule Of Derivative Instruments Designated As Cash Flow Hedges) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion) | $ 3 | $ 3 | $ 12 |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 0 | (20) | 9 |
Power [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion) | 0 | 3 | 12 |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 0 | (20) | 9 |
Operating Revenues [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion) | 0 | 3 | 12 |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 0 | (20) | 9 |
Operating Revenues [Member] | Power [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion) | 0 | 3 | 12 |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 0 | (20) | 9 |
Interest Expense [Member] | Interest Rate Swaps [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Amount of Pre-Tax Gain (Loss) attributed to Cash Flow Hedges Recognized in AOCI on Derivatives (Effective Portion) | 3 | 0 | 0 |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | $ 0 | $ 0 | $ 0 |
Financial Risk Management Ac118
Financial Risk Management Activities (Schedule Of Reconciliation For Derivative Activity Included In Accumulated Other Comprehensive Loss) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative [Line Items] | |||
Gain (Loss) Recognized in AOCI, After-Tax | $ (3) | $ (30) | $ (135) |
Less: Gain Reclassified to Income, After-Tax | 35 | 18 | (53) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Derivative [Line Items] | |||
Balance as of Beginning of Year | 0 | 17 | |
Gain (Loss) Recognized in AOCI, Pre-Tax | 3 | 3 | |
Less: Gain Reclassified into Income, Pre-Tax | 0 | (20) | 9 |
Balance as of End of Year | 3 | 0 | 17 |
Balance as of Beginning of Year | 0 | 10 | |
Gain (Loss) Recognized in AOCI, After-Tax | 2 | 2 | 7 |
Less: Gain Reclassified to Income, After-Tax | 0 | (12) | 5 |
Balance as of End of Year | $ 2 | $ 0 | $ 10 |
Financial Risk Management Ac119
Financial Risk Management Activities (Schedule Of Derivative Instruments Not Designated As Hedging Instruments And Impact On Results Of Operations) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | $ 222 | $ 404 | $ (316) |
Operating Revenues [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | 230 | 412 | (348) |
Energy Costs [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | $ (8) | $ (8) | $ 32 |
Financial Risk Management Ac120
Financial Risk Management Activities (Schedule Of Gross Volume, On Absolute Basis For Derivative Contracts) (Detail) $ / mwh in Millions, $ / Derivative in Millions, $ / DTH in Millions | 12 Months Ended | |
Dec. 31, 2016$ / DTH$ / Derivative$ / mwh | Dec. 31, 2015$ / DTH$ / Derivative$ / mwh | |
Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 357 | 201 |
Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 323 | 299 |
FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 9 | 23 |
Interest Rate Swaps [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / Derivative | 500 | 550 |
PSEG [Member] | Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 0 | 0 |
PSEG [Member] | Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 0 | |
PSEG [Member] | FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 0 | 0 |
PSEG [Member] | Interest Rate Swaps [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / Derivative | 500 | 550 |
Power [Member] | Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / DTH | 348 | 168 |
Power [Member] | Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 323 | 299 |
Power [Member] | FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 9 | 23 |
Power [Member] | Interest Rate Swaps [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / Derivative | 0 | 0 |
PSE&G [Member] | Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / DTH | 9 | 33 |
PSE&G [Member] | Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 0 | 0 |
PSE&G [Member] | FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 0 | 0 |
PSE&G [Member] | Interest Rate Swaps [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / Derivative | 0 | 0 |
Financial Risk Management Ac121
Financial Risk Management Activities (Schedule Providing Credit Risk From Others, Net Of Collateral) (Detail) - Power [Member] $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($)Counterparty | ||
Derivative [Line Items] | ||
Current Exposure | $ 449 | |
Collateral held from counterparties | 95 | |
Net Credit Exposure With Counterparties After Applying Collateral | 354 | |
Number of Counterparties greater than 10% | 1 | |
Net Exposure of Counterparties greater than 10% | $ 219 | |
Number of active counterparties on credit risk derivatives | Counterparty | 149 | |
Investment Grade External Rating [Member] | ||
Derivative [Line Items] | ||
Credit exposure, percentage | 93.00% | |
Investment Grade [Member] | ||
Derivative [Line Items] | ||
Current Exposure | $ 423 | |
Collateral held from counterparties | 94 | |
Net Credit Exposure With Counterparties After Applying Collateral | 329 | |
Number of Counterparties greater than 10% | 1 | |
Net Exposure of Counterparties greater than 10% | 219 | [1] |
Non-Investment Grade [Member] | ||
Derivative [Line Items] | ||
Current Exposure | 26 | |
Collateral held from counterparties | 1 | |
Net Credit Exposure With Counterparties After Applying Collateral | 25 | |
Number of Counterparties greater than 10% | 0 | |
Net Exposure of Counterparties greater than 10% | 0 | |
Cash [Member] | ||
Derivative [Line Items] | ||
Collateral held from counterparties | 1 | |
Letter of Credit [Member] | ||
Derivative [Line Items] | ||
Collateral held from counterparties | $ 94 | |
[1] | Represents net exposure with PSE&G. |
Fair Value Measurements (PSEG's
Fair Value Measurements (PSEG's, Power's And PSE&G's Respective Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ 1 | $ (55) | |||
Total Mark-to-Market Derivative Assets | 187 | 319 | |||
Total Mark-to-Market Derivative (Liabilities) | (16) | (103) | |||
Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | 186 | 300 | [3] | ||
Total Mark-to-Market Derivative (Liabilities) | (11) | (92) | [3] | ||
Power [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Power [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
PSE&G [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 365 | 326 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 954 | 865 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 44 | 42 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 22 | 22 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 1 | 2 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 954 | 865 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 44 | 42 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 5 | 5 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 1 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 365 | 160 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 5 | 5 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | 0 | [4] | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 3 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 293 | 311 | ||
Significant Other Observable Inputs (Level 2) [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 227 | 177 | ||
Significant Other Observable Inputs (Level 2) [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 337 | 359 | ||
Significant Other Observable Inputs (Level 2) [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 66 | 60 | ||
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 37 | 48 | ||
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 91 | 81 | ||
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 3 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 293 | 311 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 227 | 177 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 337 | 359 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 16 | 14 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 9 | 12 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 23 | 20 | ||
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 13 | 12 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 7 | 9 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 18 | 16 | ||
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Interest Rate Swaps [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [5] | 0 | 0 | ||
Interest Rate Swaps [Member] | Significant Other Observable Inputs (Level 2) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [5] | 1 | 6 | ||
Interest Rate Swaps [Member] | Significant Unobservable Inputs (Level 3) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [5] | 0 | 0 | ||
Energy-Related Contracts [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 17 | 0 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 18 | 0 | ||
Energy-Related Contracts [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 17 | 0 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 18 | 0 | ||
Energy-Related Contracts [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 0 | 0 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 0 | 0 | ||
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 533 | 896 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 364 | (644) | ||
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 533 | 896 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 364 | 644 | ||
Energy-Related Contracts [Member] | Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 0 | 0 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | 0 | 0 | ||
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 7 | 25 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | (6) | (12) | ||
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 7 | 12 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | (1) | (1) | ||
Energy-Related Contracts [Member] | Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 0 | 13 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | (5) | (11) | ||
Cash and Cash Equivalents [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[4] | 0 | 0 | ||
Cash and Cash Equivalents [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[4] | 0 | 0 | ||
Assets [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (3) | (69) | |||
Assets [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[2] | 0 | |||
Assets [Member] | Interest Rate Swaps [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[5] | 0 | 0 | ||
Assets [Member] | Energy-Related Contracts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[6] | (371) | (608) | ||
Assets [Member] | Energy-Related Contracts [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [6] | (371) | (608) | [1] | |
Assets [Member] | Energy-Related Contracts [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[6] | 0 | 0 | ||
Other Liabilities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 4 | 14 | |||
Other Liabilities [Member] | Energy-Related Contracts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[6] | 372 | 553 | ||
Other Liabilities [Member] | Energy-Related Contracts [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[6] | 372 | 553 | ||
Other Liabilities [Member] | Energy-Related Contracts [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | [1],[6] | 0 | 0 | ||
Total Estimate Of Fair Value [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 365 | 326 | ||
Total Estimate Of Fair Value [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 957 | 865 | ||
Total Estimate Of Fair Value [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 293 | 311 | ||
Total Estimate Of Fair Value [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 227 | 177 | ||
Total Estimate Of Fair Value [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 337 | 359 | ||
Total Estimate Of Fair Value [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 44 | 42 | ||
Total Estimate Of Fair Value [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 22 | 22 | ||
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 66 | 60 | ||
Total Estimate Of Fair Value [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 37 | 48 | ||
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 91 | 81 | ||
Total Estimate Of Fair Value [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 1 | 2 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Equity Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 957 | 865 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Government Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 293 | 311 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 227 | 177 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Corporate Debt Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 337 | 359 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 44 | 42 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 5 | 5 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 16 | 14 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 9 | 12 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 23 | 20 | ||
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 1 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Cash Equivalents | [4] | 365 | 160 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Equity Securities-Mutual Funds [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 5 | 5 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Govt Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 13 | 12 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trusts US Treasury Obligations [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 7 | 9 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Corporate [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 18 | 16 | ||
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Other Securities [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Measured on Recurring Basis, Investments | [2] | 0 | 0 | ||
Total Estimate Of Fair Value [Member] | Interest Rate Swaps [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [5] | 1 | 6 | ||
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 186 | 313 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | (16) | (103) | ||
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 186 | 300 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | (11) | (92) | ||
Total Estimate Of Fair Value [Member] | Energy-Related Contracts [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Total Mark-to-Market Derivative Assets | [6] | 0 | 13 | ||
Total Mark-to-Market Derivative (Liabilities) | [6] | $ (5) | $ (11) | ||
[1] | Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. All cash collateral received or posted that has been allocated to derivative positions, where the right of offset exists, has been offset in the Condensed Consolidated Balance Sheets. As of December 31, 2016, net cash collateral (received) paid of $1 million was netted against the corresponding net derivative contract positions. Of the $1 million of cash collateral as of December 31, 2016, $(3) million was netted against assets, and $4 million was netted against liabilities. As of December 31, 2015, net cash collateral (received) paid of $(55) million was netted against the corresponding net derivative contract positions. Of the $(55) million of cash collateral as of December 31, 2015, $(69) million was netted against assets and $14 million was netted against liabilities. | ||||
[2] | The fair value measurement table excludes cash of $1 million which is part of the NDT Fund, The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).Level 1—Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price. Certain open-ended mutual funds with mainly short-term investments are valued based on unadjusted quoted prices in active markets. The Rabbi Trust equity index fund is valued based on quoted prices in an active market.Level 2—NDT and Rabbi Trust fixed income securities include investment grade corporate bonds, collateralized mortgage obligations, asset-backed securities and certain government and US Treasury obligations or Federal Agency asset-backed securities and municipal bonds with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes and issuer spreads. The preferred stocks are not actively traded on a daily basis and therefore, are also priced using an evaluated pricing methodology. Certain short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield. | ||||
[3] | Substantially all of Power's and PSEG's derivative instruments are contracts subject to master netting agreements. Contracts not subject to master netting or similar agreements are immaterial and did not have any collateral posted or received as of December 31, 2016 and 2015. PSE&G does not have any derivative contracts subject to master netting or similar agreements. | ||||
[4] | Represents money market mutual funds. | ||||
[5] | Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. | ||||
[6] | Level 1—During 2016 a net fair value of $1 million relating to energy-related contracts was transferred from Level 2 into Level 1. These contracts represent natural gas futures contracts executed on NYMEX, and are being valued solely on settled pricing inputs which come directly from the exchange.Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using settled prices from an exchange, such as NYMEX, Intercontinental Exchange and Nodal Exchange, or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.Level 3—For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Quantitative Information About Level 3 Fair Value Measurements) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | $ 7 | $ 25 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (6) | (12) | |
PSE&G [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | 0 | 13 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (5) | (11) | |
Power [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | 7 | 12 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (1) | (1) | |
Forward Contracts [Member] | PSE&G [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | 0 | 13 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ (5) | $ (11) | |
Fair Value Measurements, Valuation Techniques | Discounted Cash Flow | Discounted Cash Flow | |
Fair Value Measurement With Significant Unobservable Inputs | Transportation Costs | Transportation Costs | |
Forward Contracts [Member] | Dekatherms [Member] | PSE&G [Member] | Minimum [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Transportation Costs | 0.60 | 0.60 | |
Forward Contracts [Member] | Dekatherms [Member] | PSE&G [Member] | Maximum [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Transportation Costs | 0.80 | 0.80 | |
Electric Load Contracts [Member] | Power [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | $ 7 | $ 11 | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ (1) | $ (1) | |
Fair Value Measurements, Valuation Techniques | Discounted Cash flow | Discounted Cash Flow | |
Fair Value Measurement With Significant Unobservable Inputs | Historic Load Variability | Historic Load Variability | |
Electric Load Contracts [Member] | Power [Member] | Minimum [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Historic Load Variability | 0.00% | 0.00% | |
Electric Load Contracts [Member] | Power [Member] | Maximum [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Historic Load Variability | 10.00% | 10.00% | |
Various [Member] | Power [Member] | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | |||
Assets, Fair Value Disclosure | $ 0 | [1] | $ 1 |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 0 | [1] | $ 0 |
[1] | Includes gas supply positions which were immaterial as of December 31, 2016. |
Fair Value Measurements (Change
Fair Value Measurements (Changes In Level 3 Assets And (Liabilities) Measured At Fair Value On A Recurring Basis) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Settlements | $ 21 | $ 20 | |||
Net Assets Measured At Fair Value On A Recurring Basis | 2,600 | 2,500 | |||
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3 | 1 | 13 | |||
Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Gains and losses attributable to changes in net derivative assets and liabilities, included in Operating Income | 13 | 20 | |||
Net Derivative Assets (Liabilities) [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 13 | $ 37 | |||
Opening Balance | 13 | ||||
Included in Income | [1] | 13 | 20 | ||
Included in Regulatory Assets/Liabilities | [2] | (7) | (24) | ||
Purchases, (Sales) | (3) | 0 | |||
Issuances (Settlements) | [3] | 21 | (20) | ||
Transfers In (Out) | 0 | 0 | |||
Closing Balance | 1 | 13 | |||
Net Derivative Assets (Liabilities) [Member] | Power [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 11 | 11 | |||
Opening Balance | 11 | ||||
Included in Income | [1] | 13 | 20 | ||
Included in Regulatory Assets/Liabilities | [2] | 0 | 0 | ||
Purchases, (Sales) | (3) | 0 | |||
Issuances (Settlements) | [3] | (21) | (20) | ||
Transfers In (Out) | 0 | 0 | |||
Closing Balance | 6 | 11 | |||
Net Derivative Assets (Liabilities) [Member] | PSE&G [Member] | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs | 2 | $ 26 | |||
Opening Balance | 2 | ||||
Included in Income | [1] | 0 | 0 | ||
Included in Regulatory Assets/Liabilities | (7) | (24) | [2] | ||
Purchases, (Sales) | 0 | 0 | |||
Issuances (Settlements) | [3] | 0 | 0 | ||
Transfers In (Out) | 0 | 0 | |||
Closing Balance | $ (5) | $ 2 | |||
[1] | PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $13 million and $20 million in Operating Income in 2016 and 2015, respectively. Of the $13 million in Operating Income in 2016 $(5) million is unrealized. The $20 million in Operating Income in 2015 is realized. | ||||
[2] | Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. | ||||
[3] | Represents $(21) million and $(20) million in settlements for derivative contracts in 2016 and 2015, respectively. |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Detail) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value Disclosures [Abstract] | ||
Net Assets Measured At Fair Value On A Recurring Basis | $ 2,600 | $ 2,500 |
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3 | $ 1 | $ 13 |
Stock Based Compensation (Accru
Stock Based Compensation (Accrual Adjustments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Compensation Cost included in Operation and Maintenance Expense | $ 29 | $ 34 | $ 32 |
Income Tax Benefit Recognized in Consolidated Statement of Operations | 12 | 14 | $ 13 |
Excess Tax Benefits | $ 4 | $ 3 |
Stock Based Compensation (Stock
Stock Based Compensation (Stock Option Activity) (Details) | 12 Months Ended |
Dec. 31, 2016USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Options, Beginning of Year | shares | 1,707,250 |
Options, Exercised | shares | 677,350 |
Options, Canceled/Forfeited | shares | 0 |
Options, End of Year | shares | 1,029,900 |
Options, Exercisable at End of Year | shares | 1,029,900 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |
Options, Beginning of Year, Weighted Average Exercise Price | $ / shares | $ 36 |
Options, Exercised, Weighted Average Exercise Price | $ / shares | 33.06 |
Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ / shares | 0 |
Options, End of Year, Weighted Average Exercise Price | $ / shares | 37.93 |
Options, Exercisable at End of Year, Weighted Average Exercise Price | $ / shares | $ 37.93 |
Options, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 2 years |
Options, Exercisable at End of Year, Weighted Average Remaining Years Contractual Term | 2 years |
Options, Outstanding at End of Year, Aggregate Intrinsic Value | $ | $ 7,640,178 |
Options, Exercisable at End of Year, Aggregate Intrinsic Value | $ | $ 7,640,178 |
Stock Based Compensation (Optio
Stock Based Compensation (Options Exercised) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Total Intrinsic Value of Options Exercised | $ 7 | $ 3 | $ 4 |
Cash Received from Options Exercised | 22 | 12 | 16 |
Tax Benefit Realized from Options Exercised | $ 1 | $ 0 | $ 0 |
Stock Based Compensation (Restr
Stock Based Compensation (Restricted Stock Units Activity) (Details) - Restricted Stock Units (RSUs) [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Shares, Outstanding at Beginning of Year | 408,507 | ||
Shares, Granted | 285,258 | ||
Shares, Vested | (362,098) | ||
Shares, Canceled | (9,471) | ||
Shares, Outstanding at End of Year | 322,196 | 408,507 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Shares, Outstanding at Beginning of Year, Weighted Average Grant Date Fair Value | $ 34.95 | ||
Shares, Granted, Weighted Average Grant Date Fair Value | 42.28 | $ 39.65 | $ 35.16 |
Shares, Vested, Weighted Average Grant Date Fair Value | 37.23 | ||
Shares, Canceled, Weighted Average Grant Date Fair Value | 39.67 | ||
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value | $ 38.75 | $ 34.95 | |
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 1 year | ||
Shares, Outstanding at End of Year, Aggregate Intrinsic Value | $ 14,137,960 |
Stock Based Compensation (Perfo
Stock Based Compensation (Performance Units Information) (Details) - Performance Units [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average period for recognizing unrecognized compensation cost | 1 year | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Shares, Outstanding at Beginning of Year | 403,961 | ||
Shares, Granted | 319,718 | ||
Shares, Vested | (301,554) | ||
Shares, Canceled | (28,313) | ||
Shares, Outstanding at End of Year | 393,812 | 403,961 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |||
Shares, Outstanding at Beginning of Year, Weighted Average Grant Date Fair Value | $ 40.42 | ||
Shares, Granted, Weighted Average Grant Date Fair Value | 45.97 | $ 41.32 | $ 38.94 |
Shares, Vested, Weighted Average Grant Date Fair Value | 41.22 | ||
Shares, Cancelled, Weighted Average Grant Date Fair Value | 42.04 | ||
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value | $ 44.20 | $ 40.42 | |
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 1 year 220 days | ||
Shares, Outstanding at End of Year, Aggregate Intrinsic Value | $ 17,280,471 |
Stock Based Compensation (Narra
Stock Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | 16,000,000 | |||
Stock options vested during period less than 1 million in 2013 and 2012 | ||||
Compensation expense | $ 1 | $ 1 | $ 1 | |
Percentage Of Fair Market Value Being Expected Purchase Price Of Employee Stock Purchase Plan | 95.00% | |||
Minimum Holding Period for Stock Purchased through Employee Stock Purchase Plan | 3 months | |||
Percentage Of Fair Market Value Being Expected Purchase Price Of Employee Stock Purchase Plan Non Represented | 90.00% | |||
Maximum Percentage Limit Of Base Pay For Employees For Purchasing Shares | 10.00% | |||
Shares issued under employee stock purchase plan | 262,763 | 250,499 | 207,248 | |
Shares issued under employee purchase plan, Average price per share | $ 40.70 | $ 36.66 | $ 36.07 | |
Various [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 15,000,000 | |||
Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Weighted average grant date fair value of granted shares | $ 42.28 | $ 39.65 | $ 35.16 | |
Unrecognized compensation cost related to stock options expected to be recognized | $ 4 | |||
Weighted average period for recognizing unrecognized compensation cost | 10 months | |||
Total intrinsic value of restricted stock units vested | $ 17 | $ 11 | $ 12 | |
Dividend equivalents accrued on stock units | 35,537 | |||
Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Weighted average grant date fair value of granted shares | $ 45.97 | $ 41.32 | $ 38.94 | |
Total intrinsic value of performance units vested | $ 17 | $ 13 | $ 6 | |
Unrecognized compensation cost related to stock options expected to be recognized | $ 13 | |||
Weighted average period for recognizing unrecognized compensation cost | 1 year | |||
Dividend equivalents accrued on stock units | 36,856 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 100.00% | |||
Employee Stock [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | 3,500,000 | |||
Minimum [Member] | Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period | 1 year | |||
Minimum [Member] | Restricted Stock Units (RSUs) [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options vesting period | 3 years | |||
Minimum [Member] | Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 0.00% | |||
Maximum [Member] | Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options vesting period | 4 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period | 10 years | |||
Maximum [Member] | Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options vesting period | 3 years | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage | 200.00% |
Other Income And Deductions (Sc
Other Income And Deductions (Schedule Of Other Income) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Components of Other Income [Roll Forward] | ||||
NDT Fund Gains, Interest, Dividend and Other Income | $ 96 | $ 138 | $ 219 | |
Allowance for Funds Used During Construction | 49 | 48 | 31 | |
Solar Loan Interest | 22 | 23 | 24 | |
Gain on Insurance Recovery | 28 | |||
Other | 24 | 17 | 16 | |
Total Other Income | 191 | 254 | 290 | |
PSE&G [Member] | ||||
Components of Other Income [Roll Forward] | ||||
NDT Fund Gains, Interest, Dividend and Other Income | 0 | 0 | 0 | |
Allowance for Funds Used During Construction | 49 | 48 | 31 | |
Solar Loan Interest | 22 | 23 | 24 | |
Gain on Insurance Recovery | 0 | |||
Other | 12 | 8 | 6 | |
Total Other Income | 83 | 79 | 61 | |
Power [Member] | ||||
Components of Other Income [Roll Forward] | ||||
NDT Fund Gains, Interest, Dividend and Other Income | 96 | 138 | 219 | |
Allowance for Funds Used During Construction | 0 | 0 | 0 | |
Solar Loan Interest | 0 | 0 | 0 | |
Gain on Insurance Recovery | 28 | |||
Other | 6 | 3 | 3 | |
Total Other Income | 102 | 169 | 222 | |
Other [Member] | ||||
Components of Other Income [Roll Forward] | ||||
NDT Fund Gains, Interest, Dividend and Other Income | [1] | 0 | 0 | 0 |
Allowance for Funds Used During Construction | [1] | 0 | 0 | 0 |
Solar Loan Interest | [1] | 0 | 0 | 0 |
Gain on Insurance Recovery | [1] | 0 | ||
Other | [1] | 6 | 6 | 7 |
Total Other Income | [1] | $ 6 | $ 6 | $ 7 |
[1] | Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Other Income And Deductions 133
Other Income And Deductions (Schedule Of Other Deductions) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | $ 40 | $ 45 | $ 31 | |
Other | 27 | 57 | 30 | |
Total Other Deductions | 67 | 102 | 61 | |
PSE&G [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | 0 | 0 | 0 | |
Other | 4 | 4 | 3 | |
Total Other Deductions | 4 | 4 | 3 | |
Power [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | 40 | 45 | 31 | |
Other | 17 | 27 | 21 | |
Total Other Deductions | 57 | 72 | 52 | |
Other [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | [1] | 0 | 0 | 0 |
Other | [1] | 6 | 26 | 6 |
Total Other Deductions | [1] | $ 6 | $ 26 | $ 6 |
[1] | Other consists of activity at PSEG (as parent company), Energy Holdings, Services, PSEG LI and intercompany eliminations. |
Income Taxes (Reconciliation Of
Income Taxes (Reconciliation Of Reported Income Tax Expense) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Income Taxes [Line Items] | |||||||||||||
Net Income | $ (98) | [1] | $ 327 | $ 187 | $ 471 | $ 309 | [1] | $ 439 | $ 345 | $ 586 | |||
Net Income | $ 887 | $ 1,679 | $ 1,518 | ||||||||||
Federal | (74) | 243 | 335 | ||||||||||
State | 61 | 85 | 58 | ||||||||||
Total Current | (13) | 328 | 393 | ||||||||||
Federal | 311 | 540 | 262 | ||||||||||
State | 28 | 104 | 260 | ||||||||||
Total Deferred | 339 | 644 | 522 | ||||||||||
Investment tax credit | 85 | 29 | 23 | ||||||||||
Total Income Tax | 411 | 1,001 | 938 | ||||||||||
Pre-Tax Income | 1,298 | 2,680 | 2,456 | ||||||||||
Tax Computed at Statutory Rate @ 35% | 454 | 938 | 860 | ||||||||||
State Income Taxes (net of federal income tax) | 56 | 129 | 145 | ||||||||||
Uncertain Tax Positions | (31) | 7 | (9) | ||||||||||
Manufacturing Deduction | (17) | (10) | (16) | ||||||||||
Nuclear Decommissioning Trust | 3 | 7 | 14 | ||||||||||
Plant-Related Items | (20) | (20) | (13) | ||||||||||
Tax Credits | (25) | (13) | (14) | ||||||||||
Audit Settlement | 0 | 0 | (12) | ||||||||||
Nuclear Decommissiong Tax Carryback | 0 | (33) | 0 | ||||||||||
Other | (9) | (4) | (17) | ||||||||||
Sub-Total | (43) | 63 | 78 | ||||||||||
Income Tax Provision | $ 411 | $ 1,001 | $ 938 | ||||||||||
Effective income tax rate | 31.70% | 37.40% | 38.20% | ||||||||||
PSE&G [Member] | |||||||||||||
Income Taxes [Line Items] | |||||||||||||
Net Income | 193 | 255 | 179 | 262 | 156 | 222 | 167 | 242 | |||||
Net Income | $ 889 | $ 787 | $ 725 | ||||||||||
Federal | (153) | 32 | 124 | ||||||||||
State | 10 | 52 | 16 | ||||||||||
Total Current | (143) | 84 | 140 | ||||||||||
Federal | 551 | 325 | 214 | ||||||||||
State | 102 | 52 | 84 | ||||||||||
Total Deferred | 653 | 377 | 298 | ||||||||||
Investment tax credit | 5 | 9 | 11 | ||||||||||
Total Income Tax | 515 | 470 | 449 | ||||||||||
Pre-Tax Income | 1,404 | 1,257 | 1,174 | ||||||||||
Tax Computed at Statutory Rate @ 35% | 491 | 440 | 411 | ||||||||||
State Income Taxes (net of federal income tax) | 72 | 67 | 65 | ||||||||||
Uncertain Tax Positions | (18) | (14) | 0 | ||||||||||
Plant-Related Items | (20) | (20) | (13) | ||||||||||
Tax Credits | (7) | (6) | (7) | ||||||||||
Audit Settlement | 0 | 0 | 1 | ||||||||||
Other | (3) | 3 | (8) | ||||||||||
Sub-Total | 24 | 30 | 38 | ||||||||||
Income Tax Provision | $ 515 | $ 470 | $ 449 | ||||||||||
Effective income tax rate | 36.70% | 37.40% | 38.20% | ||||||||||
Power [Member] | |||||||||||||
Income Taxes [Line Items] | |||||||||||||
Net Income | $ (302) | [1] | $ 139 | $ (11) | $ 192 | $ 149 | [1] | $ 206 | $ 166 | $ 335 | |||
Net Income | $ 18 | $ 856 | $ 760 | ||||||||||
Federal | 107 | 220 | 231 | ||||||||||
State | 40 | 30 | 39 | ||||||||||
Total Current | 147 | 250 | 270 | ||||||||||
Federal | (222) | 189 | 163 | ||||||||||
State | (68) | 52 | 48 | ||||||||||
Total Deferred | (290) | 241 | 211 | ||||||||||
Investment tax credit | 82 | 20 | 10 | ||||||||||
Total Income Tax | (61) | 511 | 491 | ||||||||||
Pre-Tax Income | (43) | 1,367 | 1,251 | ||||||||||
Tax Computed at Statutory Rate @ 35% | (15) | 478 | 438 | ||||||||||
State Income Taxes (net of federal income tax) | (18) | 59 | 58 | ||||||||||
Uncertain Tax Positions | 9 | 22 | (8) | ||||||||||
Manufacturing Deduction | (17) | (10) | (16) | ||||||||||
Nuclear Decommissioning Trust | 3 | 7 | 15 | ||||||||||
Tax Credits | (18) | (7) | (6) | ||||||||||
Audit Settlement | 0 | 0 | (4) | ||||||||||
Nuclear Decommissiong Tax Carryback | 0 | (33) | 0 | ||||||||||
Other | (5) | (5) | 14 | ||||||||||
Sub-Total | (46) | 33 | 53 | ||||||||||
Income Tax Provision | $ (61) | $ 511 | $ 491 | ||||||||||
Effective income tax rate | 141.90% | 37.40% | 39.20% | ||||||||||
[1] | The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
Income Taxes (Deferred Income T
Income Taxes (Deferred Income Tax) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Income Taxes [Line Items] | ||
OPEB | $ 283 | $ 256 |
Related to Uncertain Tax Positions | 155 | 160 |
Deferred Tax Assets - Securitization Overcollection | 0 | 27 |
Total Noncurrent Assets | 438 | 443 |
Plant-Related Items | 6,593 | 6,174 |
New Jersey Corporate Business Tax | 674 | 615 |
Leasing Activities | 565 | 612 |
Pension Costs | 197 | 218 |
AROs and NDT Fund | 398 | 393 |
Taxes Recoverable Through Future Rate (net) | 208 | 191 |
Deferred Tax Liabilities, Other | 212 | 244 |
Total Non-Current Liabilities | 8,847 | 8,447 |
Accumulated Deferred Investment Tax Credit | 249 | 162 |
Net Total Noncurrent Deferred Income Taxes and ITC | 8,658 | 8,166 |
Deferred Tax Liabilities, Net, Noncurrent | 8,409 | 8,004 |
PSE&G [Member] | ||
Income Taxes [Line Items] | ||
OPEB | 189 | 164 |
Deferred Tax Assets - Securitization Overcollection | 0 | 27 |
Total Noncurrent Assets | 189 | 191 |
Plant-Related Items | 4,983 | 4,435 |
New Jersey Corporate Business Tax | 385 | 312 |
Conservation Costs | 33 | 40 |
Pension Costs | 252 | 262 |
Taxes Recoverable Through Future Rate (net) | 208 | 191 |
Deferred Tax Liabilities, Other | 118 | 54 |
Total Non-Current Liabilities | 5,979 | 5,294 |
Accumulated Deferred Investment Tax Credit | 83 | 78 |
Net Total Noncurrent Deferred Income Taxes and ITC | 5,873 | 5,181 |
Deferred Tax Liabilities, Net, Noncurrent | 5,790 | 5,103 |
Power [Member] | ||
Income Taxes [Line Items] | ||
Contractual Liabilities & Environmental Costs | 18 | 18 |
Related to Uncertain Tax Positions | 53 | 47 |
Other | 76 | 0 |
Total Noncurrent Assets | 215 | 121 |
Plant-Related Items | 1,605 | 1,736 |
New Jersey Corporate Business Tax | 214 | 243 |
AROs and NDT Fund | 400 | 395 |
Deferred Tax Liabilities, Other | 0 | 10 |
Total Non-Current Liabilities | 2,219 | 2,384 |
Accumulated Deferred Investment Tax Credit | 166 | 84 |
Net Total Noncurrent Deferred Income Taxes and ITC | 2,170 | 2,347 |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Pensions | 68 | 56 |
Deferred Tax Liabilities, Net, Noncurrent | $ 2,004 | $ 2,263 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Detail) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Line Items] | |
Bonus depreciation for tax purposes | 50.00% |
Current ITC rate for qualified property | 30.00% |
Bonus Depreciation for Tax Purposes 2018 | 40.00% |
Bonus Depreciation for Tax Purposes 2019 | 30.00% |
2020 ITC rate for qualified property | 26.00% |
2021 ITC rate for qualified property | 22.00% |
PSEG [Member] | |
Income Taxes [Line Items] | |
Federal income tax rate | 35.00% |
Effective Income Tax Rate Reconciliation, State and Local Income Taxes | 9.00% |
Income Taxes (Unrecognized Tax
Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | $ 386 | $ 332 | $ 478 |
Increases as a Result of Positions Taken in a Prior Period | 12 | 87 | 82 |
Decreases as a Result of Positions Taken in a Prior Period | (62) | (50) | (190) |
Increases as a Result of Positions Taken during the Current Period | 19 | 28 | 30 |
Decreases as a Result of Positions Taken during the Current Period | 0 | (1) | (8) |
Decreases as a Result of Settlements with Taxing Authorities | 0 | (10) | (60) |
Decreases due to Lapses of Applicable Statute of Limitations | (27) | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 328 | 386 | 332 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (200) | (264) | (225) |
Regulatory Asset-Unrecognized Tax Benefits | (31) | (27) | (27) |
Amount of unrecognized tax benefits that would affect the effective tax rate | 97 | 95 | 80 |
Power [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | 111 | 70 | 156 |
Increases as a Result of Positions Taken in a Prior Period | 6 | 28 | 17 |
Decreases as a Result of Positions Taken in a Prior Period | (1) | (6) | (80) |
Increases as a Result of Positions Taken during the Current Period | 12 | 23 | 9 |
Decreases as a Result of Positions Taken during the Current Period | 0 | 0 | (8) |
Decreases as a Result of Settlements with Taxing Authorities | 0 | (4) | (24) |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 128 | 111 | 70 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (74) | (68) | (52) |
Regulatory Asset-Unrecognized Tax Benefits | 0 | 0 | 0 |
Amount of unrecognized tax benefits that would affect the effective tax rate | 54 | 43 | 18 |
PSE&G [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | 181 | 165 | 208 |
Increases as a Result of Positions Taken in a Prior Period | 3 | 55 | 65 |
Decreases as a Result of Positions Taken in a Prior Period | (23) | (43) | (92) |
Increases as a Result of Positions Taken during the Current Period | 6 | 5 | 16 |
Decreases as a Result of Positions Taken during the Current Period | 0 | (1) | 0 |
Decreases as a Result of Settlements with Taxing Authorities | 0 | 0 | (32) |
Decreases due to Lapses of Applicable Statute of Limitations | (27) | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 140 | 181 | 165 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (106) | (162) | (138) |
Regulatory Asset-Unrecognized Tax Benefits | (31) | (27) | (27) |
Amount of unrecognized tax benefits that would affect the effective tax rate | 3 | (8) | 0 |
Energy Holdings [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | 93 | 95 | 110 |
Increases as a Result of Positions Taken in a Prior Period | 2 | 4 | 0 |
Decreases as a Result of Positions Taken in a Prior Period | (38) | (1) | (18) |
Increases as a Result of Positions Taken during the Current Period | 0 | 0 | 5 |
Decreases as a Result of Positions Taken during the Current Period | 0 | 0 | 0 |
Decreases as a Result of Settlements with Taxing Authorities | 0 | (5) | (2) |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 57 | 93 | 95 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (20) | (34) | (35) |
Regulatory Asset-Unrecognized Tax Benefits | 0 | 0 | 0 |
Amount of unrecognized tax benefits that would affect the effective tax rate | $ 37 | $ 59 | $ 60 |
Income Taxes (Interest And Pena
Income Taxes (Interest And Penalties Related To Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | $ 59 | $ 66 | $ 69 |
PSE&G [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | 22 | 20 | 15 |
Power [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | 17 | 6 | 9 |
Energy Holdings [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | $ 20 | $ 40 | $ 45 |
Income Taxes (Possible Decrease
Income Taxes (Possible Decrease In Total Unrecognized Tax Benefits Including Interest) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | $ 14 |
Power [Member] | |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | 3 |
PSE&G [Member] | |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | $ 7 |
Income Taxes (Description Of In
Income Taxes (Description Of Income Tax Years By Material Jurisdictions) (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Federal [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2011-2015 |
Federal [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Federal [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
New Jersey [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2006-2015 |
New Jersey [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
New Jersey [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2011-2015 |
Pennsylvania [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2006-2015 |
Pennsylvania [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Pennsylvania [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2007-2015 |
Connecticut [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2007-2015 |
Connecticut [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Connecticut [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Texas [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2008-2015 |
Texas [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Texas [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
California [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2006-2015 |
California [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
California [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
New York [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2014-2015 |
New York [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2014-2015 |
New York [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Accumulated Other Comprehens141
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Changes in AOCI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | $ (295) | $ (283) | $ (95) |
Other Comprehensive Income before Reclassifications | (3) | (30) | (135) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 35 | 18 | (53) |
Net Current Period Other Comprehensive Income (Loss) | 32 | (12) | (188) |
Ending Balance | (263) | (295) | (283) |
Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (240) | (228) | (63) |
Other Comprehensive Income before Reclassifications | (3) | (27) | (110) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 32 | 15 | (55) |
Net Current Period Other Comprehensive Income (Loss) | 29 | (12) | (165) |
Ending Balance | (211) | (240) | (228) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 0 | 10 | (2) |
Other Comprehensive Income before Reclassifications | 2 | 2 | 7 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 0 | (12) | 5 |
Net Current Period Other Comprehensive Income (Loss) | 2 | (10) | 12 |
Ending Balance | 2 | 0 | 10 |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 0 | 11 | (1) |
Other Comprehensive Income before Reclassifications | 0 | 1 | 7 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 0 | (12) | 5 |
Net Current Period Other Comprehensive Income (Loss) | 0 | (11) | 12 |
Ending Balance | 0 | 0 | 11 |
Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (386) | (411) | (238) |
Other Comprehensive Income before Reclassifications | (45) | (7) | (184) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 33 | 32 | 11 |
Net Current Period Other Comprehensive Income (Loss) | (12) | 25 | (173) |
Ending Balance | (398) | (386) | (411) |
Accumulated Defined Benefit Plans Adjustment [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (327) | (351) | (204) |
Other Comprehensive Income before Reclassifications | (42) | (4) | (156) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 29 | 28 | 9 |
Net Current Period Other Comprehensive Income (Loss) | (13) | 24 | (147) |
Ending Balance | (340) | (327) | (351) |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 91 | 118 | 145 |
Other Comprehensive Income before Reclassifications | 40 | (25) | 42 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 2 | (2) | (69) |
Net Current Period Other Comprehensive Income (Loss) | 42 | (27) | (27) |
Ending Balance | 133 | 91 | 118 |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 87 | 112 | 142 |
Other Comprehensive Income before Reclassifications | 39 | (24) | 39 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 3 | (1) | (69) |
Net Current Period Other Comprehensive Income (Loss) | 42 | (25) | (30) |
Ending Balance | $ 129 | $ 87 | $ 112 |
Accumulated Other Comprehens142
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Reclassifications out of AOCI) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax | $ (62) | $ (28) | $ 108 |
Amount Reclassified from Accumulated Other Comprehensive Income, Tax | 27 | 10 | (55) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (35) | (18) | 53 |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (6) | 8 | 135 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 4 | (6) | (66) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 2 | (2) | (69) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (2) | 2 | 69 |
Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Pension and OPEB Plans, Pre-Tax | (56) | (56) | (18) |
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax | 23 | 24 | 7 |
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax | (33) | (32) | (11) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (33) | (32) | (11) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax | 0 | 20 | (9) |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 0 | 12 | (5) |
Operating Revenues [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax | 20 | (9) | |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | (4) | |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | |
Operation and Maintenance Expense [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amortization of Prior Service (Cost) Credit, Pre-Tax | 12 | 12 | (10) |
Amortization of Prior Service (Cost) Credit, Tax | (5) | (3) | (4) |
Amortization of Prior Service (Cost) Credit, After-Tax | 7 | 9 | 6 |
Amortization of Actuarial Loss, Pre-Tax | (68) | (68) | 28 |
Amortization of Actuarial Loss, Tax | (28) | (27) | (11) |
Amortization of Actuarial Loss, After-Tax | (40) | (41) | (17) |
Other Income [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | 59 | 100 | 181 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (29) | (52) | 89 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 30 | 48 | 92 |
Other Deductions [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (37) | (39) | (26) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 19 | 20 | (13) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (18) | (19) | (13) |
Other-Than-Temporary Impairments [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (28) | (53) | (20) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 14 | 26 | (10) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 14 | 27 | 10 |
Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax | (54) | (22) | 109 |
Amount Reclassified from Accumulated Other Comprehensive Income, Tax | 22 | 7 | (54) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (32) | (15) | 55 |
Power [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (6) | 7 | 134 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 3 | (6) | (65) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 3 | (1) | (69) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (3) | 1 | 69 |
Power [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Pension and OPEB Plans, Pre-Tax | (48) | (49) | (16) |
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax | 19 | 21 | 7 |
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax | (29) | (28) | (9) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (29) | (28) | (9) |
Power [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax | 20 | (9) | |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 0 | 12 | (5) |
Power [Member] | Operating Revenues [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Cash Flow Hedges, Pre-Tax | 20 | (9) | |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | (4) | |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | |
Power [Member] | Operation and Maintenance Expense [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amortization of Prior Service (Cost) Credit, Pre-Tax | 11 | 11 | (9) |
Amortization of Prior Service (Cost) Credit, Tax | (5) | (3) | (4) |
Amortization of Prior Service (Cost) Credit, After-Tax | 6 | 8 | 5 |
Amortization of Actuarial Loss, Pre-Tax | (59) | (60) | 25 |
Amortization of Actuarial Loss, Tax | (24) | (24) | (11) |
Amortization of Actuarial Loss, After-Tax | (35) | (36) | (14) |
Power [Member] | Other Income [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | 55 | 98 | 178 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (28) | (51) | 87 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 27 | 47 | 91 |
Power [Member] | Other Deductions [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (33) | (38) | (24) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 17 | 19 | (12) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (16) | (19) | (12) |
Power [Member] | Other-Than-Temporary Impairments [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from AOCI for Available for Sale Securities, Pre-Tax | (28) | (53) | (20) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 14 | 26 | (10) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | $ 14 | $ 27 | $ 10 |
Earnings Per Share (EPS) And143
Earnings Per Share (EPS) And Dividends (Basic And Diluted Earnings Per Share Computation) (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings Per Share, Diluted [Line Items] | |||||||||||
Net Income | $ 887 | $ 1,679 | $ 1,518 | ||||||||
Effect of Stock Based Compensation Awards, Basic | 0 | 0 | 0 | ||||||||
Total Shares, Basic | 505,000 | 505,000 | 505,000 | 505,000 | 505,000 | 505,000 | 506,000 | 506,000 | 505,000 | 505,000 | 506,000 |
Effect of Stock Based Compensation Awards, Diluted | 3,000 | 3,000 | 2,000 | ||||||||
Total Shares, Diluted | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 | 508,000 |
Weighted Average Common Shares Outstanding Before Various Effects Basic | 505,000 | 505,000 | 506,000 | ||||||||
Weighted Average Common Shares Outstanding Before Various Effects Diluted | 505,000 | 505,000 | 506,000 | ||||||||
Earnings Per Share, Basic | $ (0.19) | $ 0.65 | $ 0.37 | $ 0.93 | $ 0.61 | $ 0.87 | $ 0.68 | $ 1.16 | $ 1.76 | $ 3.32 | $ 3 |
Earnings Per Share, Diluted | $ (0.19) | $ 0.64 | $ 0.37 | $ 0.93 | $ 0.60 | $ 0.87 | $ 0.68 | $ 1.15 | $ 1.75 | $ 3.30 | $ 2.99 |
Stock Options Excluded from Weighted Average Common Shares used for diluted EPS | 400 | 500 | 400 |
Earnings Per Share (EPS) And144
Earnings Per Share (EPS) And Dividends (Dividend Payments On Common Stock) (Detail) - USD ($) $ / shares in Units, $ in Millions | Feb. 21, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Earnings Per Share, Diluted [Line Items] | ||||
Dividend Payments on Common Stock, Per Share | $ 1.64 | $ 1.56 | $ 1.48 | |
Dividend Payments on Common Stock | $ 830 | $ 789 | $ 748 | |
Subsequent Event [Member] | ||||
Earnings Per Share, Diluted [Line Items] | ||||
Common stock dividends per share | $ 0.43 |
Financial Information By Bus145
Financial Information By Business Segments (Financial Information By Business Segments) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Segment Reporting Information [Line Items] | ||||||||||||
Operating Revenues | $ 2,090 | $ 2,450 | $ 1,905 | $ 2,616 | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 9,061 | $ 10,415 | $ 10,886 | |
Depreciation and Amortization | 1,476 | 1,214 | 1,227 | |||||||||
Operating Income (Loss) | (175) | $ 577 | $ 347 | $ 827 | 532 | $ 814 | $ 568 | $ 1,048 | 1,576 | 2,962 | 2,623 | |
Income from Equity Method Investments | 11 | 12 | 13 | |||||||||
Interest Income | 30 | 31 | 30 | |||||||||
Interest Expense | (385) | (393) | (389) | |||||||||
Income (Loss) before Income Taxes | 1,298 | 2,680 | 2,456 | |||||||||
Income Tax Expense (Benefit) | 411 | 1,001 | 938 | |||||||||
Net Income (Loss) | 887 | 1,679 | 1,518 | |||||||||
Gross Additions to Long-Lived Assets | 4,199 | 3,863 | 2,820 | |||||||||
Total Assets | 40,070 | 37,535 | 40,070 | 37,535 | 35,287 | |||||||
Investments in Equity Method Subsidiaries | 102 | 119 | 102 | 119 | 123 | |||||||
Retained Earnings [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Net Income (Loss) | 887 | 1,679 | 1,518 | |||||||||
Operating Segments [Member] | Power [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating Revenues | 4,023 | 4,928 | 5,434 | |||||||||
Depreciation and Amortization | 881 | 291 | 292 | |||||||||
Operating Income (Loss) | 13 | 1,430 | 1,209 | |||||||||
Income from Equity Method Investments | 11 | 14 | 14 | |||||||||
Interest Income | 4 | 2 | 1 | |||||||||
Interest Expense | (84) | (121) | (122) | |||||||||
Income (Loss) before Income Taxes | (43) | 1,367 | 1,251 | |||||||||
Income Tax Expense (Benefit) | (61) | 511 | 491 | |||||||||
Net Income (Loss) | 18 | 856 | 760 | |||||||||
Gross Additions to Long-Lived Assets | 1,343 | 1,117 | 626 | |||||||||
Total Assets | 12,193 | 12,250 | 12,193 | 12,250 | 12,037 | |||||||
Investments in Equity Method Subsidiaries | 102 | 119 | 102 | 119 | 121 | |||||||
Operating Segments [Member] | PSE&G [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating Revenues | 6,221 | 6,636 | 6,766 | |||||||||
Depreciation and Amortization | 565 | 892 | 906 | |||||||||
Operating Income (Loss) | 1,614 | 1,462 | 1,393 | |||||||||
Income from Equity Method Investments | 0 | 0 | 0 | |||||||||
Interest Income | 24 | 25 | 26 | |||||||||
Interest Expense | (289) | (280) | (277) | |||||||||
Income (Loss) before Income Taxes | 1,404 | 1,257 | 1,174 | |||||||||
Income Tax Expense (Benefit) | 515 | 470 | 449 | |||||||||
Net Income (Loss) | 889 | 787 | 725 | |||||||||
Gross Additions to Long-Lived Assets | 2,816 | 2,692 | 2,164 | |||||||||
Total Assets | 26,288 | 23,677 | 26,288 | 23,677 | 22,186 | |||||||
Investments in Equity Method Subsidiaries | 0 | 0 | 0 | 0 | 0 | |||||||
Operating Segments [Member] | Other [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating Revenues | [1] | 370 | 462 | 455 | ||||||||
Depreciation and Amortization | [1] | 30 | 31 | 29 | ||||||||
Operating Income (Loss) | [1] | (51) | 70 | 21 | ||||||||
Income from Equity Method Investments | [1] | 0 | (2) | (1) | ||||||||
Interest Income | [1] | 4 | 33 | 25 | ||||||||
Interest Expense | [1] | (14) | (21) | (12) | ||||||||
Income (Loss) before Income Taxes | [1] | (63) | 56 | 31 | ||||||||
Income Tax Expense (Benefit) | [1] | (43) | 20 | (2) | ||||||||
Net Income (Loss) | [1] | (20) | 36 | 33 | ||||||||
Gross Additions to Long-Lived Assets | [1] | 40 | 54 | 30 | ||||||||
Total Assets | [1] | 2,373 | 2,810 | 2,373 | 2,810 | 2,799 | ||||||
Investments in Equity Method Subsidiaries | [1] | 0 | 0 | 0 | 0 | 2 | ||||||
Eliminations [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Operating Revenues | [2] | (1,553) | (1,611) | (1,769) | ||||||||
Depreciation and Amortization | [2] | 0 | 0 | 0 | ||||||||
Operating Income (Loss) | [2] | 0 | 0 | 0 | ||||||||
Income from Equity Method Investments | [2] | 0 | 0 | 0 | ||||||||
Interest Income | [2] | (2) | (29) | (22) | ||||||||
Interest Expense | [2] | 2 | 29 | 22 | ||||||||
Income (Loss) before Income Taxes | [2] | 0 | 0 | 0 | ||||||||
Income Tax Expense (Benefit) | [2] | 0 | 0 | 0 | ||||||||
Net Income (Loss) | [2] | 0 | 0 | |||||||||
Gross Additions to Long-Lived Assets | [2] | 0 | 0 | 0 | ||||||||
Total Assets | [2] | (784) | (1,202) | (784) | (1,202) | (1,735) | ||||||
Investments in Equity Method Subsidiaries | [2] | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | ||||||
[1] | Includes amounts applicable to Energy Holdings and PSEG LI, which are below the quantitative threshold for separate disclosure as reportable segments. Other also includes amounts applicable to PSEG (parent corporation) and Services. | |||||||||||
[2] | Intercompany eliminations primarily relate to intercompany transactions between PSE&G and Power. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between PSE&G and Power, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between PSE&G and Power, see Note 24. Related-Party Transactions. |
Related-Party Transactions (Sch
Related-Party Transactions (Schedule Of Related Party Transactions, Revenue) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
PSE&G [Member] | ||||
Related Party Transaction [Line Items] | ||||
Billings from Power through BGSS and BGS | [1] | $ 1,587 | $ 1,630 | $ 1,771 |
Administrative Billings from Services | [2] | 312 | 274 | 248 |
Total Expense Billings from Affiliates | 1,899 | 1,904 | 2,019 | |
Power [Member] | ||||
Related Party Transaction [Line Items] | ||||
Administrative Billings from Services | [2] | $ 179 | $ 187 | $ 165 |
[1] | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. | |||
[2] | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. |
Related-Party Transactions (147
Related-Party Transactions (Schedule Of Related Party Transactions, Receivables) (Detail) - Power [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Receivable from PSE&G through BGS and BGSS Contracts | [1] | $ 193 | $ 212 |
Receivable from (Payable to) Services | [2] | (25) | (33) |
Accounts Payable-Affiliated Companies | (25) | (33) | |
Receivable from (Payable to) PSEG | [3] | 12 | 64 |
Accounts Receivable-Affilated Companies, net | 205 | 276 | |
Short-Term Loan to Affiliate (Demand Note to PSEG) | [4] | 87 | 363 |
Working Capital Advances to Services | [5] | 17 | 17 |
Accounts Payable, Related Parties, Noncurrent | $ 77 | $ 35 | |
[1] | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. | ||
[2] | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. | ||
[3] | PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. | ||
[4] | Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. | ||
[5] | PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. |
Related-Party Transactions Rela
Related-Party Transactions Related-Party Revenues and Expenses (Details) - Power [Member] - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Related Party Transaction [Line Items] | ||||
Billings To PSE&G through BGSS and BGS | [1] | $ 1,587 | $ 1,630 | $ 1,771 |
Administrative Billings from Services | [2] | $ 179 | $ 187 | $ 165 |
[1] | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. | |||
[2] | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. |
Related-Party Transactions (149
Related-Party Transactions (Schedule Of Related Party Transactions, Payables) (Detail) - PSE&G [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | |||
Payable to Power through BGS and BGSS Contracts | [1] | $ (193) | $ (212) |
Receivable from (Payable to) Services | [2] | (67) | (80) |
Receivable from (Payable to) PSEG | [3] | 76 | 222 |
Accounts Payable-Affiliated Companies | 260 | 292 | |
Working Capital Advances to Services | [4] | 33 | 33 |
Long-Term Accrued Taxes Receivable (Payable) | $ (130) | $ (109) | |
[1] | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. In addition, Power and PSE&G provide certain technical services for each other generally at cost in compliance with FERC and BPU affiliate rules. | ||
[2] | Services provides and bills administrative services to PSE&G and Power at cost. In addition, PSE&G and Power have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. | ||
[3] | PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. | ||
[4] | PSE&G and Power have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on PSE&G’s and Power’s Consolidated Balance Sheets. |
Selected Quarterly Data (Schedu
Selected Quarterly Data (Schedule Of Selected Quarterly Data) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Schedule of Quarterly Data [Line Items] | |||||||||||||
Operating Revenues | $ 2,090 | $ 2,450 | $ 1,905 | $ 2,616 | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 9,061 | $ 10,415 | $ 10,886 | ||
Operating Income (Loss) | (175) | 577 | 347 | 827 | 532 | 814 | 568 | 1,048 | 1,576 | 2,962 | 2,623 | ||
Net Income (Loss) | $ (98) | [1] | $ 327 | $ 187 | $ 471 | $ 309 | [1] | $ 439 | $ 345 | $ 586 | |||
Net Income (Loss) | $ 887 | $ 1,679 | $ 1,518 | ||||||||||
Basic | 505 | 505 | 505 | 505 | 505 | 505 | 506 | 506 | 505 | 505 | 506 | ||
Diluted | 508 | 508 | 508 | 508 | 508 | 508 | 508 | 508 | 508 | 508 | 508 | ||
Earnings Per Share, Basic | $ (0.19) | $ 0.65 | $ 0.37 | $ 0.93 | $ 0.61 | $ 0.87 | $ 0.68 | $ 1.16 | $ 1.76 | $ 3.32 | $ 3 | ||
Earnings Per Share, Diluted | $ (0.19) | $ 0.64 | $ 0.37 | $ 0.93 | $ 0.60 | $ 0.87 | $ 0.68 | $ 1.15 | $ 1.75 | $ 3.30 | $ 2.99 | ||
PSE&G [Member] | |||||||||||||
Schedule of Quarterly Data [Line Items] | |||||||||||||
Operating Revenues | $ 1,475 | $ 1,684 | $ 1,350 | $ 1,712 | $ 1,402 | $ 1,766 | $ 1,466 | $ 2,002 | $ 6,221 | $ 6,636 | $ 6,766 | ||
Operating Income (Loss) | 369 | 450 | 333 | 462 | 287 | 404 | 320 | 451 | 1,614 | 1,462 | 1,393 | ||
Net Income (Loss) | 193 | 255 | 179 | 262 | 156 | 222 | 167 | 242 | |||||
Net Income (Loss) | 889 | 787 | 725 | ||||||||||
Power [Member] | |||||||||||||
Schedule of Quarterly Data [Line Items] | |||||||||||||
Operating Revenues | 921 | 1,075 | 714 | 1,313 | 1,082 | 1,096 | 1,025 | 1,725 | 4,023 | 4,928 | 5,434 | ||
Operating Income (Loss) | (556) | 238 | (12) | 343 | 227 | 391 | 228 | 584 | 13 | 1,430 | 1,209 | ||
Net Income (Loss) | $ (302) | [1] | $ 139 | $ (11) | $ 192 | $ 149 | [1] | $ 206 | $ 166 | $ 335 | |||
Net Income (Loss) | $ 18 | $ 856 | $ 760 | ||||||||||
[1] | The decreases in Operating Income at PSEG consolidated and Power in the fourth quarter 2016 as compared to the same quarter in 2015 were primarily due to costs related to closing the coal/gas Hudson and Mercer units and higher MTM losses in 2016. |
Guarantees Of Debt (Schedule Of
Guarantees Of Debt (Schedule Of Financial Statements Of Guarantors) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | $ 2,090 | $ 2,450 | $ 1,905 | $ 2,616 | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 9,061 | $ 10,415 | $ 10,886 | |
Operating Expenses | 7,485 | 7,453 | 8,263 | |||||||||
Operating Income (Loss) | (175) | 577 | 347 | 827 | 532 | 814 | 568 | 1,048 | 1,576 | 2,962 | 2,623 | |
Equity Earnings (Losses) of Subsidiaries | 11 | 12 | 13 | |||||||||
Other Income | 191 | 254 | 290 | |||||||||
Other Deductions | (67) | (102) | (61) | |||||||||
Other-than-Temporary-Impairments | (28) | (53) | (20) | |||||||||
Interest Expense | (385) | (393) | (389) | |||||||||
Income Tax Benefit (Expense) | (411) | (1,001) | (938) | |||||||||
Net Income | 887 | 1,679 | 1,518 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 3,311 | 3,919 | 3,160 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (4,248) | (3,942) | (2,892) | |||||||||
Net Cash Provided By (Used In) Financing Activities | 966 | 15 | (359) | |||||||||
Current Assets | 3,254 | 3,494 | 3,254 | 3,494 | ||||||||
Property, Plant and Equipment, net | 29,286 | 26,539 | 29,286 | 26,539 | ||||||||
Noncurrent Assets | 7,530 | 7,502 | 7,530 | 7,502 | ||||||||
Total Assets | 40,070 | 37,535 | 40,070 | 37,535 | 35,287 | |||||||
Current Liabilities | 3,276 | 3,575 | 3,276 | 3,575 | ||||||||
Noncurrent Liabilities | 12,769 | 12,059 | 12,769 | 12,059 | ||||||||
Total Long-Term Debt | 10,895 | 8,834 | 10,895 | 8,834 | ||||||||
Member's Equity | 13,130 | 13,067 | 13,130 | 13,067 | 12,186 | $ 11,609 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | 40,070 | 37,535 | 40,070 | 37,535 | ||||||||
Power [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | 921 | 1,075 | 714 | 1,313 | 1,082 | 1,096 | 1,025 | 1,725 | 4,023 | 4,928 | 5,434 | |
Operating Expenses | 4,010 | 3,498 | 4,225 | |||||||||
Operating Income (Loss) | (556) | $ 238 | $ (12) | $ 343 | 227 | $ 391 | $ 228 | $ 584 | 13 | 1,430 | 1,209 | |
Equity Earnings (Losses) of Subsidiaries | 11 | 14 | 14 | |||||||||
Other Income | 102 | 169 | 222 | |||||||||
Other Deductions | (57) | (72) | (52) | |||||||||
Other-than-Temporary-Impairments | (28) | (53) | (20) | |||||||||
Interest Expense | (84) | (121) | (122) | |||||||||
Income Tax Benefit (Expense) | 61 | (511) | (491) | |||||||||
Net Income | 18 | 856 | 760 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 1,255 | 1,706 | 1,425 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (1,147) | (1,001) | (524) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (109) | (702) | (898) | |||||||||
Current Assets | 1,460 | 1,949 | 1,460 | 1,949 | ||||||||
Property, Plant and Equipment, net | 8,520 | 8,127 | 8,520 | 8,127 | ||||||||
Noncurrent Assets | 2,213 | 2,174 | 2,213 | 2,174 | ||||||||
Total Assets | 12,193 | 12,250 | 12,193 | 12,250 | ||||||||
Current Liabilities | 680 | 1,226 | 680 | 1,226 | ||||||||
Noncurrent Liabilities | 3,332 | 3,338 | 3,332 | 3,338 | ||||||||
Total Long-Term Debt | 2,382 | 1,684 | 2,382 | 1,684 | ||||||||
Member's Equity | 5,799 | 6,002 | 5,799 | 6,002 | 5,558 | $ 5,858 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | 12,193 | 12,250 | 12,193 | 12,250 | ||||||||
Power Senior Notes [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | 4,023 | 4,928 | 5,434 | |||||||||
Operating Expenses | 4,010 | 3,498 | 4,225 | |||||||||
Operating Income (Loss) | 13 | 1,430 | 1,209 | |||||||||
Equity Earnings (Losses) of Subsidiaries | 11 | 14 | 14 | |||||||||
Other Income | 102 | 169 | 222 | |||||||||
Other Deductions | (57) | (72) | (52) | |||||||||
Other-than-Temporary-Impairments | (28) | (53) | (20) | |||||||||
Interest Expense | (84) | (121) | (122) | |||||||||
Income Tax Benefit (Expense) | 61 | (511) | (491) | |||||||||
Net Income | 18 | 856 | 760 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 47 | 844 | 595 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 1,255 | 1,706 | 1,425 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (1,147) | (1,001) | (524) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (109) | (702) | (898) | |||||||||
Current Assets | 1,460 | 1,949 | 1,460 | 1,949 | ||||||||
Property, Plant and Equipment, net | 8,520 | 8,127 | 8,520 | 8,127 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | 0 | 0 | ||||||||
Noncurrent Assets | 2,213 | 2,174 | 2,213 | 2,174 | ||||||||
Total Assets | 12,193 | 12,250 | 12,193 | 12,250 | ||||||||
Current Liabilities | 680 | 1,226 | 680 | 1,226 | ||||||||
Noncurrent Liabilities | 3,332 | 3,338 | 3,332 | 3,338 | ||||||||
Total Long-Term Debt | 2,382 | 1,684 | 2,382 | 1,684 | ||||||||
Member's Equity | 5,799 | 6,002 | 5,799 | 6,002 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 12,193 | 12,250 | 12,193 | 12,250 | ||||||||
Power Senior Notes [Member] | Guarantor Subsidiaries [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | 3,971 | 4,883 | 5,390 | |||||||||
Operating Expenses | 3,962 | 3,451 | 4,175 | |||||||||
Operating Income (Loss) | 9 | 1,432 | 1,215 | |||||||||
Equity Earnings (Losses) of Subsidiaries | (3) | (4) | (5) | |||||||||
Other Income | 120 | 174 | 222 | |||||||||
Other Deductions | (39) | (45) | (32) | |||||||||
Other-than-Temporary-Impairments | (28) | (53) | (20) | |||||||||
Interest Expense | (40) | (39) | (35) | |||||||||
Income Tax Benefit (Expense) | (11) | (574) | (558) | |||||||||
Net Income | 8 | 891 | 787 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 50 | 855 | 768 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 1,442 | 2,089 | 1,674 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (707) | (1,519) | (856) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (736) | (571) | (818) | |||||||||
Current Assets | 1,593 | 1,912 | 1,593 | 1,912 | ||||||||
Property, Plant and Equipment, net | 6,145 | 6,502 | 6,145 | 6,502 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 344 | 346 | 344 | 346 | ||||||||
Noncurrent Assets | 2,016 | 1,959 | 2,016 | 1,959 | ||||||||
Total Assets | 10,098 | 10,719 | 10,098 | 10,719 | ||||||||
Current Liabilities | 3,752 | 3,866 | 3,752 | 3,866 | ||||||||
Noncurrent Liabilities | 2,398 | 2,597 | 2,398 | 2,597 | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | 3,948 | 4,256 | 3,948 | 4,256 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 10,098 | 10,719 | 10,098 | 10,719 | ||||||||
Power Senior Notes [Member] | Non-Guarantor Subsidiaries [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | 173 | 179 | 153 | |||||||||
Operating Expenses | 161 | 169 | 143 | |||||||||
Operating Income (Loss) | 12 | 10 | 10 | |||||||||
Equity Earnings (Losses) of Subsidiaries | 11 | 14 | 14 | |||||||||
Other Income | 0 | 0 | 0 | |||||||||
Other Deductions | 0 | 0 | 0 | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | (18) | (19) | (19) | |||||||||
Income Tax Benefit (Expense) | 20 | 6 | 2 | |||||||||
Net Income | 25 | 11 | 7 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 25 | 11 | 7 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 323 | 80 | 76 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (789) | (430) | (42) | |||||||||
Net Cash Provided By (Used In) Financing Activities | 466 | 354 | (32) | |||||||||
Current Assets | 152 | 364 | 152 | 364 | ||||||||
Property, Plant and Equipment, net | 2,320 | 1,542 | 2,320 | 1,542 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | 0 | 0 | ||||||||
Noncurrent Assets | 129 | 136 | 129 | 136 | ||||||||
Total Assets | 2,601 | 2,042 | 2,601 | 2,042 | ||||||||
Current Liabilities | 1,454 | 1,076 | 1,454 | 1,076 | ||||||||
Noncurrent Liabilities | 502 | 375 | 502 | 375 | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | 645 | 591 | 645 | 591 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 2,601 | 2,042 | 2,601 | 2,042 | ||||||||
Power Senior Notes [Member] | Power Parent [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | 0 | 0 | 0 | |||||||||
Operating Expenses | 8 | 12 | 16 | |||||||||
Operating Income (Loss) | (8) | (12) | (16) | |||||||||
Equity Earnings (Losses) of Subsidiaries | 36 | 906 | 799 | |||||||||
Other Income | 71 | 48 | 34 | |||||||||
Other Deductions | (18) | (27) | (20) | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | (115) | (116) | (102) | |||||||||
Income Tax Benefit (Expense) | 52 | 57 | 65 | |||||||||
Net Income | 18 | 856 | 760 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 47 | 844 | 595 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 97 | 571 | 577 | |||||||||
Net Cash Provided By (Used In) Investing Activities | 60 | (366) | 148 | |||||||||
Net Cash Provided By (Used In) Financing Activities | (157) | (205) | (724) | |||||||||
Current Assets | 4,412 | 4,501 | 4,412 | 4,501 | ||||||||
Property, Plant and Equipment, net | 55 | 83 | 55 | 83 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 4,249 | 4,501 | 4,249 | 4,501 | ||||||||
Noncurrent Assets | 168 | 155 | 168 | 155 | ||||||||
Total Assets | 8,884 | 9,240 | 8,884 | 9,240 | ||||||||
Current Liabilities | 171 | 1,112 | 171 | 1,112 | ||||||||
Noncurrent Liabilities | 532 | 442 | 532 | 442 | ||||||||
Total Long-Term Debt | 2,382 | 1,684 | 2,382 | 1,684 | ||||||||
Member's Equity | 5,799 | 6,002 | 5,799 | 6,002 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 8,884 | 9,240 | 8,884 | 9,240 | ||||||||
Consolidation, Eliminations [Member] | Power Senior Notes [Member] | ||||||||||||
Guarantees of Debt [Line Items] | ||||||||||||
Operating Revenues | (121) | (134) | (109) | |||||||||
Operating Expenses | (121) | (134) | (109) | |||||||||
Operating Income (Loss) | 0 | 0 | 0 | |||||||||
Equity Earnings (Losses) of Subsidiaries | (33) | (902) | (794) | |||||||||
Other Income | (89) | (53) | (34) | |||||||||
Other Deductions | 0 | 0 | 0 | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | 89 | 53 | 34 | |||||||||
Income Tax Benefit (Expense) | 0 | 0 | 0 | |||||||||
Net Income | (33) | (902) | (794) | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | (75) | (866) | (775) | |||||||||
Net Cash Provided By (Used In) Operating Activities | (607) | (1,034) | (902) | |||||||||
Net Cash Provided By (Used In) Investing Activities | 289 | 1,314 | 226 | |||||||||
Net Cash Provided By (Used In) Financing Activities | 318 | (280) | $ 676 | |||||||||
Current Assets | (4,697) | (4,828) | (4,697) | (4,828) | ||||||||
Property, Plant and Equipment, net | 0 | 0 | 0 | 0 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | (4,593) | (4,847) | (4,593) | (4,847) | ||||||||
Noncurrent Assets | (100) | (76) | (100) | (76) | ||||||||
Total Assets | (9,390) | (9,751) | (9,390) | (9,751) | ||||||||
Current Liabilities | (4,697) | (4,828) | (4,697) | (4,828) | ||||||||
Noncurrent Liabilities | (100) | (76) | (100) | (76) | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | (4,593) | (4,847) | (4,593) | (4,847) | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ (9,390) | $ (9,751) | $ (9,390) | $ (9,751) |
Valuation And Qualifying Acc152
Valuation And Qualifying Accounts (Schedule Of Valuation And Qualifying Accounts) (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Allowance For Doubtful Accounts [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | $ 67 | $ 52 | $ 56 | |||
Additions, Charged to cost and expenses | 85 | 101 | 86 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [1] | 84 | 86 | 90 | ||
Balance at End of Period | 68 | 67 | 52 | |||
Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 11 | 15 | 8 | |||
Additions, Charged to cost and expenses | 32 | 2 | 9 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [2] | 6 | 6 | 2 | ||
Balance at End of Period | 37 | 11 | 15 | |||
PSE&G [Member] | Allowance For Doubtful Accounts [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 67 | 52 | 56 | |||
Additions, Charged to cost and expenses | 85 | 101 | 86 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [3] | 84 | 86 | 90 | ||
Balance at End of Period | 68 | 67 | 52 | |||
PSE&G [Member] | Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 1 | 2 | 0 | |||
Additions, Charged to cost and expenses | 0 | 0 | 2 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | 1 | [2] | 1 | [2] | 0 | |
Balance at End of Period | 0 | 1 | 2 | |||
Power [Member] | Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 10 | 13 | 8 | |||
Additions, Charged to cost and expenses | 32 | 2 | 7 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [4] | 5 | 5 | 2 | ||
Balance at End of Period | $ 37 | $ 10 | $ 13 | |||
[1] | Accounts Receivable written off. | |||||
[2] | Reduced reserve to appropriate level and to remove obsolete inventory. | |||||
[3] | Accounts Receivable written off. | |||||
[4] | Reduced reserve to appropriate level and to remove obsolete inventory. |