Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 19, 2016 | Jun. 30, 2015 | |
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
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 | 506,435,137 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 19,819,621,677 | ||
PSE&G [Member] | |||
Entity Information [Line Items] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
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, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Revenues | $ 10,415 | $ 10,886 | $ 9,968 |
Operating Expenses [Abstract] | |||
Energy Costs | 3,261 | 3,886 | 3,536 |
Operation and Maintenance | 2,978 | 3,150 | 2,887 |
Depreciation and Amortization | 1,214 | 1,227 | 1,178 |
Taxes Other Than Income Taxes | 0 | 0 | 68 |
Total Operating Expenses | 7,453 | 8,263 | 7,669 |
OPERATING INCOME | 2,962 | 2,623 | 2,299 |
Income from Equity Method Investments | 12 | 13 | 11 |
Other Income | 254 | 290 | 213 |
Other Deductions | (102) | (61) | (54) |
Other-than-Temporary-Impairments | 53 | 20 | 12 |
Interest Expense | (393) | (389) | (402) |
INCOME BEFORE INCOME TAXES | 2,680 | 2,456 | 2,055 |
Income Tax (Expense) Benefit | (1,001) | (938) | (812) |
Net Income | $ 1,679 | $ 1,518 | $ 1,243 |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | |||
BASIC | 505 | 506 | 506 |
DILUTED | 508 | 508 | 508 |
EARNINGS PER SHARE: | |||
NET INCOME, BASIC | $ 3.32 | $ 3 | $ 2.46 |
NET INCOME, DILUTED | $ 3.30 | $ 2.99 | $ 2.45 |
PSE&G [Member] | |||
Operating Revenues | $ 6,636 | $ 6,766 | $ 6,655 |
Operating Expenses [Abstract] | |||
Energy Costs | 2,722 | 2,909 | 2,841 |
Operation and Maintenance | 1,560 | 1,558 | 1,639 |
Depreciation and Amortization | 892 | 906 | 872 |
Taxes Other Than Income Taxes | 0 | 0 | 68 |
Total Operating Expenses | 5,174 | 5,373 | 5,420 |
OPERATING INCOME | 1,462 | 1,393 | 1,235 |
Other Income | 79 | 61 | 54 |
Other Deductions | (4) | (3) | (3) |
Interest Expense | (280) | (277) | (293) |
INCOME BEFORE INCOME TAXES | 1,257 | 1,174 | 993 |
Income Tax (Expense) Benefit | (470) | (449) | (381) |
Net Income | 787 | 725 | 612 |
Power [Member] | |||
Operating Revenues | 4,928 | 5,434 | 5,063 |
Operating Expenses [Abstract] | |||
Energy Costs | 2,150 | 2,747 | 2,496 |
Operation and Maintenance | 1,057 | 1,186 | 1,224 |
Depreciation and Amortization | 291 | 292 | 273 |
Total Operating Expenses | 3,498 | 4,225 | 3,993 |
OPERATING INCOME | 1,430 | 1,209 | 1,070 |
Income from Equity Method Investments | 14 | 14 | 16 |
Other Income | 169 | 222 | 154 |
Other Deductions | (72) | (52) | (49) |
Other-than-Temporary-Impairments | 53 | 20 | 12 |
Interest Expense | (121) | (122) | (116) |
INCOME BEFORE INCOME TAXES | 1,367 | 1,251 | 1,063 |
Income Tax (Expense) Benefit | (511) | (491) | (419) |
Net Income | $ 856 | $ 760 | $ 644 |
Consolidated Statements Of Comp
Consolidated Statements Of Comprehensive Income - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Net Income | $ 1,679 | $ 1,518 | $ 1,243 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | (27) | (27) | 55 |
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit for the years ended | (10) | 12 | (9) |
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended | 25 | (173) | 247 |
Other Comprehensive Income (Loss), net of tax | (12) | (188) | 293 |
Comprehensive Income | 1,667 | 1,330 | 1,536 |
PSE&G [Member] | |||
Net Income | 787 | 725 | 612 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | (1) | 1 | (1) |
Other Comprehensive Income (Loss), net of tax | (1) | 1 | (1) |
Comprehensive Income | 786 | 726 | 611 |
Power [Member] | |||
Net Income | 856 | 760 | 644 |
Other Comprehensive Income (Loss), net of tax | |||
Unrealized Gains (Losses) on Available-for-Sale Securities, net of tax (expense) benefit for the years ended | (25) | (30) | 57 |
Unrealized Gains (Losses) on Cash Flow Hedges, net of tax (expense) benefit for the years ended | (11) | 12 | (10) |
Pension/OPEB adjustment, net of tax (expense) benefit for the years ended | 24 | (147) | 218 |
Other Comprehensive Income (Loss), net of tax | (12) | (165) | 265 |
Comprehensive Income | $ 844 | $ 595 | $ 909 |
Consolidated Statements Of Com4
Consolidated Statements Of Comprehensive Income (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Available-for-Sale Securities, tax | $ 34 | $ 26 | $ (54) |
Change in Fair Value of Derivative Instruments, tax | 7 | (8) | 7 |
Pension/OPEB adjustment, tax | (18) | 120 | (172) |
PSE&G [Member] | |||
Available-for-Sale Securities, tax | 0 | 0 | 1 |
Power [Member] | |||
Available-for-Sale Securities, tax | 32 | 28 | (55) |
Change in Fair Value of Derivative Instruments, tax | 7 | (8) | 7 |
Pension/OPEB adjustment, tax | $ (16) | $ 101 | $ (151) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
CURRENT ASSETS | |||
Cash and Cash Equivalents | $ 394 | $ 402 | |
Accounts Receivable, net of allowances | 1,068 | 1,254 | |
Tax Receivable | 305 | 211 | |
Unbilled Revenues | 197 | 284 | |
Fuel | 463 | 538 | |
Materials and Supplies, net | 513 | 484 | |
Prepayments | 135 | 108 | |
Derivative Contracts | 242 | 240 | |
Deferred Income Taxes | 0 | 11 | |
Regulatory Assets | 164 | 323 | |
Regulatory Assets of Variable Interest Entities (VIEs) | 0 | 249 | |
Other | 13 | 15 | |
Total Current Assets | 3,494 | 4,119 | |
PROPERTY, PLANT AND EQUIPMENT | 35,494 | 32,196 | |
Less: Accumulated Depreciation and Amortization | (8,955) | (8,607) | |
Net Property, Plant and Equipment | 26,539 | 23,589 | |
NONCURRENT ASSETS | |||
Regulatory Assets | 3,196 | 3,192 | |
Long-Term Investments | 1,233 | 1,307 | |
Nuclear Decommissioning Trust (NDT) Fund | 1,754 | 1,780 | |
Long-Term Tax Receivable | 171 | 64 | |
Long-Term Receivable of VIEs | 495 | 580 | |
Other Special Funds | 227 | 212 | |
Goodwill | 16 | 16 | |
Other Intangibles | 102 | 84 | |
Derivative Contracts | 77 | 77 | |
Restricted Cash of VIEs | 0 | 24 | |
Other | 231 | 243 | |
Total Noncurrent Assets | 7,502 | 7,579 | |
Total Assets | 37,535 | 35,287 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 734 | 624 | |
Securitization Debt of VIEs Due Within One Year | 0 | 259 | |
Commercial Paper and Loans | 364 | 0 | |
Accounts Payable | 1,369 | 1,178 | |
Derivative Contracts | 76 | 132 | |
Accrued Interest | 96 | 95 | |
Accrued Taxes | 42 | 21 | |
Deferred Income Taxes | 0 | 173 | |
Clean Energy Program | 142 | 142 | |
Obligation to Return Cash Collateral | 128 | 121 | |
Regulatory Liabilities | 123 | 186 | |
Regulatory Liabilities of Consolidated VIEs | 42 | 0 | |
Other | 459 | 547 | |
Total Current Liabilities | 3,575 | 3,478 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 8,166 | 7,303 | |
Regulatory Liabilities | 175 | 258 | |
Regulatory Liabilities of VIEs | 0 | 39 | |
Asset Retirement Obligations | 679 | 743 | |
Other Postretirement Benefit (OPEB) Costs | 1,228 | 1,277 | |
OPEB Costs of Servco | 375 | 452 | |
Accrued Pension Costs | 487 | 440 | |
Accrued Pension Costs of Servco | 114 | 126 | |
Environmental Costs | 415 | 417 | |
Derivative Contracts | 27 | 33 | |
Long-Term Accrued Taxes | 212 | 208 | |
Other | 181 | 112 | |
Total Noncurrent Liabilities | $ 12,059 | $ 11,408 | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12) | |||
LONG-TERM DEBT | |||
Long-Term Debt | $ 8,834 | $ 8,215 | |
STOCKHOLDER'S EQUITY | |||
Common Stock | 4,915 | 4,876 | |
Treasury Stock, at cost | (671) | (635) | |
Retained Earnings | 9,117 | 8,227 | |
Accumulated Other Comprehensive Income (Loss) | (295) | (283) | |
Total Common Stockholders' Equity | 13,066 | 12,185 | |
Noncontrolling Interest | 1 | 1 | |
Total Stockholder's Equity | 13,067 | 12,186 | |
Total Capitalization | 21,901 | 20,401 | |
TOTAL LIABILITIES AND CAPITALIZATION | 37,535 | 35,287 | |
PSE&G [Member] | |||
CURRENT ASSETS | |||
Cash and Cash Equivalents | 198 | 310 | |
Accounts Receivable, net of allowances | 787 | 864 | |
Accounts Receivable-Affiliated Companies | 222 | 274 | |
Unbilled Revenues | 197 | 284 | |
Materials and Supplies, net | 148 | 133 | |
Prepayments | 31 | 42 | |
Derivative Contracts | 13 | 18 | |
Deferred Income Taxes | 0 | 24 | |
Regulatory Assets | 164 | 323 | |
Regulatory Assets of Variable Interest Entities (VIEs) | 0 | 249 | |
Other | 9 | 7 | |
Total Current Assets | 1,769 | 2,528 | |
PROPERTY, PLANT AND EQUIPMENT | 23,732 | 21,103 | |
Less: Accumulated Depreciation and Amortization | (5,504) | (5,183) | |
Net Property, Plant and Equipment | 18,228 | 15,920 | |
NONCURRENT ASSETS | |||
Regulatory Assets | 3,196 | 3,192 | |
Long-Term Investments | 330 | 348 | |
Other Special Funds | 49 | 53 | |
Derivative Contracts | 0 | 8 | |
Restricted Cash of VIEs | 0 | 24 | |
Other | 105 | 113 | |
Total Noncurrent Assets | 3,680 | 3,738 | |
Total Assets | 23,677 | 22,186 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 171 | 300 | |
Securitization Debt of VIEs Due Within One Year | 0 | 259 | |
Commercial Paper and Loans | 153 | 0 | |
Accounts Payable | 724 | 574 | |
Accounts Payable-Affiliated Companies | 292 | 379 | |
Accrued Interest | 70 | 68 | |
Deferred Income Taxes | 0 | 165 | |
Clean Energy Program | 142 | 142 | |
Obligation to Return Cash Collateral | 128 | 121 | |
Regulatory Liabilities | 123 | 186 | |
Regulatory Liabilities of Consolidated VIEs | 42 | 0 | |
Other | 297 | 381 | |
Total Current Liabilities | 2,142 | 2,575 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 5,181 | 4,575 | |
Regulatory Liabilities | 175 | 258 | |
Regulatory Liabilities of VIEs | 0 | 39 | |
Asset Retirement Obligations | 218 | 290 | |
Other Postretirement Benefit (OPEB) Costs | 937 | 967 | |
Accrued Pension Costs | 202 | 173 | |
Environmental Costs | 365 | 364 | |
Derivative Contracts | 11 | 0 | |
Long-Term Accrued Taxes | 109 | 116 | |
Other | 114 | 67 | |
Total Noncurrent Liabilities | $ 7,312 | $ 6,849 | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12) | |||
LONG-TERM DEBT | |||
Total Long-Term Debt | $ 6,650 | $ 5,975 | |
STOCKHOLDER'S EQUITY | |||
Common Stock | 892 | 892 | |
Contributed Capital | 695 | 695 | |
Basis Adjustment | 986 | 986 | |
Retained Earnings | 4,999 | 4,212 | |
Accumulated Other Comprehensive Income (Loss) | 1 | 2 | |
Total Stockholder's Equity | 7,573 | 6,787 | |
Total Capitalization | 14,223 | 12,762 | |
TOTAL LIABILITIES AND CAPITALIZATION | 23,677 | 22,186 | |
Power [Member] | |||
CURRENT ASSETS | |||
Cash and Cash Equivalents | 12 | 9 | |
Accounts Receivable, net of allowances | 217 | 334 | |
Accounts Receivable-Affiliated Companies | 276 | 313 | |
Short-Term Loan to Affiliate | 363 | 584 | |
Fuel | 463 | 538 | |
Materials and Supplies, net | 363 | 350 | |
Prepayments | 25 | 17 | |
Derivative Contracts | 223 | 207 | [1] |
Deferred Income Taxes | 0 | 0 | |
Other | 7 | 7 | |
Total Current Assets | 1,949 | 2,359 | |
PROPERTY, PLANT AND EQUIPMENT | 11,354 | 10,732 | |
Less: Accumulated Depreciation and Amortization | (3,227) | (3,217) | |
Net Property, Plant and Equipment | 8,127 | 7,515 | |
NONCURRENT ASSETS | |||
Long-Term Investments | 119 | 121 | |
Nuclear Decommissioning Trust (NDT) Fund | 1,754 | 1,780 | |
Other Special Funds | 55 | 49 | |
Goodwill | 16 | 16 | |
Other Intangibles | 102 | 84 | |
Derivative Contracts | 77 | 62 | [1] |
Other | 51 | 51 | |
Total Noncurrent Assets | 2,174 | 2,163 | |
Total Assets | 12,250 | 12,037 | |
CURRENT LIABILITIES | |||
Long-Term Debt Due Within One Year | 553 | 300 | |
Accounts Payable | 432 | 424 | |
Derivative Contracts | 76 | 132 | [1] |
Accounts Payable-Affiliated Companies | 33 | 118 | |
Accrued Interest | 25 | 27 | |
Deferred Income Taxes | 0 | 43 | |
Other | 107 | 140 | |
Total Current Liabilities | 1,226 | 1,184 | |
NONCURRENT LIABILITIES | |||
Deferred Income Taxes and Investment Tax Credits (ITC) | 2,347 | 2,065 | |
Asset Retirement Obligations | 457 | 450 | |
Other Postretirement Benefit (OPEB) Costs | 230 | 248 | |
Accrued Pension Costs | 166 | 153 | |
Derivative Contracts | 16 | 33 | [1] |
Long-Term Accrued Taxes | 35 | 41 | |
Other | 87 | 71 | |
Total Noncurrent Liabilities | $ 3,338 | $ 3,061 | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 12) | |||
LONG-TERM DEBT | |||
Total Long-Term Debt | $ 1,684 | $ 2,234 | |
STOCKHOLDER'S EQUITY | |||
Contributed Capital | 2,214 | 2,214 | |
Basis Adjustment | (986) | (986) | |
Retained Earnings | 5,014 | 4,558 | |
Accumulated Other Comprehensive Income (Loss) | (240) | (228) | |
Total Stockholder's Equity | 6,002 | 5,558 | |
TOTAL LIABILITIES AND CAPITALIZATION | $ 12,250 | $ 12,037 | |
[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, 2015 and 2014. 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, 2015 | Dec. 31, 2014 |
Accounts Receivable,allowances | $ 67 | $ 52 |
Common Stock, issued | 533,556,660 | 533,556,660 |
Common Stock, authorized | 1,000,000,000 | 1,000,000,000 |
Treasury Stock, Shares | 28,274,239 | 27,720,068 |
PSE&G [Member] | ||
Accounts Receivable,allowances | $ 67 | $ 52 |
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | $ 1,679 | $ 1,518 | $ 1,243 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 1,214 | 1,227 | 1,178 |
Amortization of Nuclear Fuel | 213 | 200 | 192 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | 685 | 515 | 270 |
Non-Cash Employee Benefit Plan Costs | 161 | 47 | 243 |
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes | 26 | (4) | 31 |
Net (Gain) Loss on Lease Investments | 0 | (3) | 2 |
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | (143) | (93) | 79 |
Change in Accrued Storm Costs | 12 | (3) | (90) |
Net Change in Regulatory Assets and Liabilities | (60) | 190 | 2 |
Cost of Removal | (120) | (98) | (93) |
Net Realized (Gains) Losses and (Income) Expense from NDT Fund | (38) | (166) | (104) |
Net Change in Certain Current Assets and Liabilities: | |||
Margin Deposits | 122 | (22) | (43) |
Tax Receivable | (94) | 30 | 19 |
Accrued Taxes | (91) | (156) | 81 |
Other Current Assets and Liabilities | 288 | (31) | 261 |
Employee Benefit Plan Funding and Related Payments | (109) | (95) | (231) |
Other | 174 | 104 | 118 |
Net Cash Provided By (Used In) Operating Activities | 3,919 | 3,160 | 3,158 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (3,863) | (2,820) | (2,811) |
Proceeds from Sale of Capital Leases and Investments | 14 | 25 | 50 |
Proceeds from Sale of Available-for-Sale Securities | 1,501 | 1,915 | 1,159 |
Investments in Available-for-Sale Securities | (1,552) | (1,934) | (1,170) |
Other | (42) | (78) | (29) |
Net Cash Provided By (Used In) Investing Activities | (3,942) | (2,892) | (2,801) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net Change in Commercial Paper and Loans | 364 | (60) | (203) |
Issuance of Long-Term Debt | 1,350 | 1,250 | 2,000 |
Redemption of Long-Term Debt | (600) | (500) | (1,025) |
Redemption of Securitization Debt | (259) | (237) | (226) |
Cash Dividend Paid | (789) | (748) | (728) |
Other | (51) | (64) | (61) |
Net Cash Provided By (Used In) Financing Activities | 15 | (359) | (243) |
Net Increase (Decrease) In Cash and Cash Equivalents | (8) | (91) | 114 |
Cash and Cash Equivalents at Beginning of Period | 402 | 493 | 379 |
Cash and Cash Equivalents at End of Period | 394 | 402 | 493 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | 447 | 538 | 241 |
Interest Paid, Net of Amounts Capitalized | 381 | 382 | 385 |
Accrued Property, Plant and Equipment Expenditures | 510 | 382 | 336 |
PSE&G [Member] | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | 787 | 725 | 612 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 892 | 906 | 872 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | 386 | 310 | 198 |
Non-Cash Employee Benefit Plan Costs | 95 | 27 | 156 |
Change in Accrued Storm Costs | 12 | (3) | (90) |
Net Change in Regulatory Assets and Liabilities | (60) | 190 | 2 |
Cost of Removal | (120) | (98) | (93) |
Net Change in Certain Current Assets and Liabilities: | |||
Accounts Receivable and Unbilled Revenues | 165 | 63 | (5) |
Fuel, Materials and Supplies | (15) | (18) | (1) |
Prepayments | 11 | (18) | 5 |
Accounts Payable | 45 | (3) | 19 |
Accounts Receivable/Payable-Affiliated Companies, net | 0 | (167) | 100 |
Other Current Assets and Liabilities | (29) | 6 | 40 |
Employee Benefit Plan Funding and Related Payments | (91) | (83) | (166) |
Other | 47 | (4) | (4) |
Net Cash Provided By (Used In) Operating Activities | 2,125 | 1,833 | 1,645 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (2,692) | (2,164) | (2,175) |
Proceeds from Sale of Available-for-Sale Securities | 21 | 103 | 38 |
Investments in Available-for-Sale Securities | (22) | (101) | (20) |
Solar Loan Investments | 11 | 7 | (15) |
Other | 11 | 0 | 0 |
Net Cash Provided By (Used In) Investing Activities | (2,671) | (2,155) | (2,172) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Net Change in Short-Term Debt | 153 | (60) | (203) |
Issuance of Long-Term Debt | 850 | 1,250 | 1,500 |
Redemption of Long-Term Debt | (300) | (500) | (725) |
Contributed Capital | 0 | 175 | 100 |
Redemption of Securitization Debt | (259) | (237) | (226) |
Other | (10) | (14) | (17) |
Net Cash Provided By (Used In) Financing Activities | 434 | 614 | 429 |
Net Increase (Decrease) In Cash and Cash Equivalents | (112) | 292 | (98) |
Cash and Cash Equivalents at Beginning of Period | 310 | 18 | 116 |
Cash and Cash Equivalents at End of Period | 198 | 310 | 18 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | (28) | 283 | 84 |
Interest Paid, Net of Amounts Capitalized | 261 | 259 | 275 |
Accrued Property, Plant and Equipment Expenditures | 396 | 292 | 246 |
Power [Member] | |||
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net Income | 856 | 760 | 644 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | |||
Depreciation and Amortization | 291 | 292 | 273 |
Amortization of Nuclear Fuel | 213 | 200 | 192 |
Provision for Deferred Income Taxes (Other than Leases) and ITC | 261 | 221 | 122 |
Interest Accretion on Asset Retirement Obligation | 26 | 30 | 23 |
Non-Cash Employee Benefit Plan Costs | 48 | 13 | 66 |
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives | (143) | (93) | 79 |
Net Realized (Gains) Losses and (Income) Expense from NDT Fund | (38) | (166) | (104) |
Net Change in Certain Current Assets and Liabilities: | |||
Fuel, Materials and Supplies | 62 | 19 | (8) |
Margin Deposits | 122 | (22) | (43) |
Accounts Receivable | 63 | (15) | (4) |
Accounts Payable | (46) | (59) | 28 |
Accounts Receivable/Payable-Affiliated Companies, net | (84) | 220 | 0 |
Other Current Assets and Liabilities | (36) | (6) | 72 |
Employee Benefit Plan Funding and Related Payments | (11) | (7) | (46) |
Other | 122 | 38 | 53 |
Net Cash Provided By (Used In) Operating Activities | 1,706 | 1,425 | 1,347 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Additions to Property, Plant and Equipment | (1,117) | (626) | (609) |
Proceeds from Sale of Available-for-Sale Securities | 1,422 | 1,557 | 1,084 |
Investments in Available-for-Sale Securities | (1,455) | (1,573) | (1,102) |
Short-Term Loan-Affiliated Company, net | 221 | 206 | (216) |
Other | (72) | (88) | (18) |
Net Cash Provided By (Used In) Investing Activities | (1,001) | (524) | (861) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Issuance of Long-Term Debt | 0 | 0 | 500 |
Redemption of Long-Term Debt | (300) | 0 | (300) |
Contributed Capital | 0 | 0 | 24 |
Cash Dividend Paid | (400) | (895) | (705) |
Other | (2) | (3) | (6) |
Net Cash Provided By (Used In) Financing Activities | (702) | (898) | (487) |
Net Increase (Decrease) In Cash and Cash Equivalents | 3 | 3 | (1) |
Cash and Cash Equivalents at Beginning of Period | 9 | 6 | 7 |
Cash and Cash Equivalents at End of Period | 12 | 9 | 6 |
Supplemental Disclosure of Cash Flow Information: | |||
Income Taxes Paid (Received) | 393 | 68 | 291 |
Interest Paid, Net of Amounts Capitalized | 116 | 119 | 106 |
Accrued Property, Plant and Equipment Expenditures | $ 114 | $ 91 | $ 90 |
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, 2012 | $ 10,781 | $ 4,833 | $ (607) | $ 6,942 | $ (388) | $ 1 | $ 5,175 | $ 892 | $ 420 | $ 986 | $ 2,875 | $ 2 | $ 5,630 | $ 2,190 | $ (986) | $ 4,754 | $ (328) |
Beginning Balance, shares at Dec. 31, 2012 | 534 | (28) | |||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||
Net Income | 1,243 | 1,243 | 612 | 612 | 644 | 644 | |||||||||||
Other Comprehensive Income (Loss), net of tax | |||||||||||||||||
Other Comprehensive Income (Loss), net of tax | 293 | 293 | 0 | (1) | (1) | 265 | 265 | ||||||||||
Comprehensive Income | 1,536 | 611 | 909 | ||||||||||||||
Contributed Capital | 100 | 100 | 24 | 24 | |||||||||||||
Cash Dividends on Common Stock | (728) | (728) | 0 | 0 | (705) | (705) | |||||||||||
Other | 20 | $ 28 | $ (8) | 0 | 0 | 0 | |||||||||||
Ending 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) |
Ending 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) | 1 | 1 | (165) | (165) | |||||||||||
Comprehensive Income | 1,330 | 726 | 595 | ||||||||||||||
Contributed Capital | 175 | 175 | 0 | ||||||||||||||
Cash Dividends on Common Stock | (748) | (748) | (895) | (895) | |||||||||||||
Other | (5) | $ 15 | $ (20) | ||||||||||||||
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 | 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) |
Consolidated Statements Of Sto9
Consolidated Statements Of Stockholders' Equity (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Other Comprehensive Income (Loss), tax | $ 23 | $ 138 | $ (219) |
PSE&G [Member] | |||
Other Comprehensive Income (Loss), tax | 0 | 0 | 1 |
Power [Member] | |||
Other Comprehensive Income (Loss), tax | $ 23 | $ 121 | $ (199) |
Organization, Basis Of Presenta
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
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, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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 3. 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 5. Regulatory Assets and Liabilities . Derivative Financial Instruments Each company uses derivative financial instruments to manage risk pursuant to its business plans and prudent practices. Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a fair value hedge, along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge are recorded 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 normal purchases or sales, changes in fair value are recorded in current period earnings. Many contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement. For additional information regarding derivative financial instruments, see Note 15. 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 normal purchases or sales or as cash flow or fair value hedges of other positions. See Note 15. 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 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 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 3. 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: 2015 2014 2013 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.46 % 2.47 % 2.48 % 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— 19 years to 79 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Taxes Other Than Income Taxes Excise taxes and the transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. Effective January 1, 2014, the TEFA was eliminated. For the year ended December 31, 2013 , $74 million and $68 million of the TEFA were included in Operating Revenues and Taxes Other Than Income Taxes, respectively, in the Consolidated Statements of Operations. 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, 2015 , 2014 and 2013 were as follows: AFUDC/IDC Capitalized 2015 2014 2013 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 65 8.01 % $ 44 8.09 % $ 34 8.11 % Power $ 27 5.14 % $ 24 5.14 % $ 23 5.36 % 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 19. Income Taxes for further discussion. Impairment of Long-Lived Assets In accordance with GAAP, 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, 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. 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 or that meet the normal purchases and normal sales exemption. 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. 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) (except credit losses on debt securities which are recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 8. 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 11. 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, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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 3. 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 5. Regulatory Assets and Liabilities . Derivative Financial Instruments Each company uses derivative financial instruments to manage risk pursuant to its business plans and prudent practices. Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a fair value hedge, along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge are recorded 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 normal purchases or sales, changes in fair value are recorded in current period earnings. Many contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement. For additional information regarding derivative financial instruments, see Note 15. 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 normal purchases or sales or as cash flow or fair value hedges of other positions. See Note 15. 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 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 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 3. 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: 2015 2014 2013 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.46 % 2.47 % 2.48 % 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— 19 years to 79 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Taxes Other Than Income Taxes Excise taxes and the transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. Effective January 1, 2014, the TEFA was eliminated. For the year ended December 31, 2013 , $74 million and $68 million of the TEFA were included in Operating Revenues and Taxes Other Than Income Taxes, respectively, in the Consolidated Statements of Operations. 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, 2015 , 2014 and 2013 were as follows: AFUDC/IDC Capitalized 2015 2014 2013 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 65 8.01 % $ 44 8.09 % $ 34 8.11 % Power $ 27 5.14 % $ 24 5.14 % $ 23 5.36 % 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 19. Income Taxes for further discussion. Impairment of Long-Lived Assets In accordance with GAAP, 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, 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. 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 or that meet the normal purchases and normal sales exemption. 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. 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) (except credit losses on debt securities which are recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 8. 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 11. 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, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy transacting functions primarily in the Northeast and Mid-Atlantic United States through its principal direct wholly owned subsidiaries. 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 3. 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 5. Regulatory Assets and Liabilities . Derivative Financial Instruments Each company uses derivative financial instruments to manage risk pursuant to its business plans and prudent practices. Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a fair value hedge, along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge are recorded 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 normal purchases or sales, changes in fair value are recorded in current period earnings. Many contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement. For additional information regarding derivative financial instruments, see Note 15. 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 normal purchases or sales or as cash flow or fair value hedges of other positions. See Note 15. 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 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 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 3. 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: 2015 2014 2013 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.46 % 2.47 % 2.48 % 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— 19 years to 79 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years Taxes Other Than Income Taxes Excise taxes and the transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. Effective January 1, 2014, the TEFA was eliminated. For the year ended December 31, 2013 , $74 million and $68 million of the TEFA were included in Operating Revenues and Taxes Other Than Income Taxes, respectively, in the Consolidated Statements of Operations. 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, 2015 , 2014 and 2013 were as follows: AFUDC/IDC Capitalized 2015 2014 2013 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 65 8.01 % $ 44 8.09 % $ 34 8.11 % Power $ 27 5.14 % $ 24 5.14 % $ 23 5.36 % 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 19. Income Taxes for further discussion. Impairment of Long-Lived Assets In accordance with GAAP, 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, 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. 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 or that meet the normal purchases and normal sales exemption. 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. 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) (except credit losses on debt securities which are recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 8. 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 11. 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, 2015 | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Adopted in 2015 Simplifying the Presentation of Debt Issuance Costs This standard was issued to simplify presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The update is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued; therefore, PSEG has elected to early adopt these amendments in the fourth quarter of 2015 on a retrospective basis and therefore reclassified debt issuance costs in the 2014 Consolidated Balance Sheets. Unamortized debt issuance costs for PSE&G and Power were $41 million and $8 million , respectively, as of December 31, 2015 and $37 million and $9 million , respectively, as of December 31, 2014. Balance Sheet Classification of Deferred Taxes This standard was issued to reduce complexity in the presentation of deferred taxes. The new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early application is permitted as of the beginning of an interim or annual reporting period and the guidance may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. PSEG has elected to early adopt the guidance as of the fourth quarter of 2015 and to apply it prospectively. Prior periods were not retrospectively adjusted. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 update was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements. 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 and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of 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 accounting standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted for fiscal years or interim periods for which financial statements have not been issued. 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 would recognize a lease asset and corresponding lease obligation. A lessee would 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 would 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. The accounting 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. |
PSE&G [Member] | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Adopted in 2015 Simplifying the Presentation of Debt Issuance Costs This standard was issued to simplify presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The update is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued; therefore, PSEG has elected to early adopt these amendments in the fourth quarter of 2015 on a retrospective basis and therefore reclassified debt issuance costs in the 2014 Consolidated Balance Sheets. Unamortized debt issuance costs for PSE&G and Power were $41 million and $8 million , respectively, as of December 31, 2015 and $37 million and $9 million , respectively, as of December 31, 2014. Balance Sheet Classification of Deferred Taxes This standard was issued to reduce complexity in the presentation of deferred taxes. The new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early application is permitted as of the beginning of an interim or annual reporting period and the guidance may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. PSEG has elected to early adopt the guidance as of the fourth quarter of 2015 and to apply it prospectively. Prior periods were not retrospectively adjusted. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 update was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements. 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 and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of 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 accounting standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted for fiscal years or interim periods for which financial statements have not been issued. 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 would recognize a lease asset and corresponding lease obligation. A lessee would 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 would 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. The accounting 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. |
Power [Member] | |
New Accounting Pronouncement [Line Items] | |
Recent Accounting Standards [Text Block] | Recent Accounting Standards New Standards Adopted in 2015 Simplifying the Presentation of Debt Issuance Costs This standard was issued to simplify presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The update is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued; therefore, PSEG has elected to early adopt these amendments in the fourth quarter of 2015 on a retrospective basis and therefore reclassified debt issuance costs in the 2014 Consolidated Balance Sheets. Unamortized debt issuance costs for PSE&G and Power were $41 million and $8 million , respectively, as of December 31, 2015 and $37 million and $9 million , respectively, as of December 31, 2014. Balance Sheet Classification of Deferred Taxes This standard was issued to reduce complexity in the presentation of deferred taxes. The new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early application is permitted as of the beginning of an interim or annual reporting period and the guidance may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. PSEG has elected to early adopt the guidance as of the fourth quarter of 2015 and to apply it prospectively. Prior periods were not retrospectively adjusted. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 update was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements. 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 and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of 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 accounting standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted for fiscal years or interim periods for which financial statements have not been issued. 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 would recognize a lease asset and corresponding lease obligation. A lessee would 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 would 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. The accounting 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. |
Variable Interest Entities (VIE
Variable Interest Entities (VIEs) | 12 Months Ended |
Dec. 31, 2015 | |
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 is pledged as collateral to a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are 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 remain with these VIEs. 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 2015 and 2014 , Servco recorded $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 is pledged as collateral to a trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are 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 remain with these VIEs. 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 2015 and 2014 , Servco recorded $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, 2015 | |
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, 2015 and 2014 is detailed below: 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 Power Other PSEG Consolidated Millions 2014 Transmission and Distribution: Electric Transmission $ 5,845 $ — $ — $ 5,845 Electric Distribution 7,295 — — 7,295 Gas Transmission 89 — — 89 Gas Distribution 5,479 — — 5,479 Construction Work in Progress 1,304 — — 1,304 Plant Held for Future Use 15 — — 15 Other 401 — — 401 Total Transmission and Distribution 20,428 — — 20,428 Generation: Fossil Production — 6,964 — 6,964 Nuclear Production — 1,751 — 1,751 Nuclear Fuel in Service — 889 — 889 Other Production-Solar 521 314 — 835 Construction Work in Progress — 714 — 714 Total Generation 521 10,632 — 11,153 Other 154 100 361 615 Total $ 21,103 $ 10,732 $ 361 $ 32,196 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. All amounts reflect the share of PSE&G’s and Power’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2015 2014 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 166 $ 72 $ 162 $ 69 Power: Coal Generating: Conemaugh 23 % $ 404 $ 154 $ 397 $ 142 Keystone 23 % $ 408 $ 163 $ 396 $ 151 Nuclear Generating: Peach Bottom 50 % $ 1,219 $ 262 $ 1,087 $ 236 Salem 57 % $ 990 $ 276 $ 916 $ 236 Nuclear Support Facilities Various $ 226 $ 60 $ 218 $ 49 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 24 $ 41 $ 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, 2015 and 2014 is detailed below: 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 Power Other PSEG Consolidated Millions 2014 Transmission and Distribution: Electric Transmission $ 5,845 $ — $ — $ 5,845 Electric Distribution 7,295 — — 7,295 Gas Transmission 89 — — 89 Gas Distribution 5,479 — — 5,479 Construction Work in Progress 1,304 — — 1,304 Plant Held for Future Use 15 — — 15 Other 401 — — 401 Total Transmission and Distribution 20,428 — — 20,428 Generation: Fossil Production — 6,964 — 6,964 Nuclear Production — 1,751 — 1,751 Nuclear Fuel in Service — 889 — 889 Other Production-Solar 521 314 — 835 Construction Work in Progress — 714 — 714 Total Generation 521 10,632 — 11,153 Other 154 100 361 615 Total $ 21,103 $ 10,732 $ 361 $ 32,196 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. All amounts reflect the share of PSE&G’s and Power’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2015 2014 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 166 $ 72 $ 162 $ 69 Power: Coal Generating: Conemaugh 23 % $ 404 $ 154 $ 397 $ 142 Keystone 23 % $ 408 $ 163 $ 396 $ 151 Nuclear Generating: Peach Bottom 50 % $ 1,219 $ 262 $ 1,087 $ 236 Salem 57 % $ 990 $ 276 $ 916 $ 236 Nuclear Support Facilities Various $ 226 $ 60 $ 218 $ 49 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 24 $ 41 $ 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, 2015 and 2014 is detailed below: 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 Power Other PSEG Consolidated Millions 2014 Transmission and Distribution: Electric Transmission $ 5,845 $ — $ — $ 5,845 Electric Distribution 7,295 — — 7,295 Gas Transmission 89 — — 89 Gas Distribution 5,479 — — 5,479 Construction Work in Progress 1,304 — — 1,304 Plant Held for Future Use 15 — — 15 Other 401 — — 401 Total Transmission and Distribution 20,428 — — 20,428 Generation: Fossil Production — 6,964 — 6,964 Nuclear Production — 1,751 — 1,751 Nuclear Fuel in Service — 889 — 889 Other Production-Solar 521 314 — 835 Construction Work in Progress — 714 — 714 Total Generation 521 10,632 — 11,153 Other 154 100 361 615 Total $ 21,103 $ 10,732 $ 361 $ 32,196 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. All amounts reflect the share of PSE&G’s and Power’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses. As of December 31, 2015 2014 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 166 $ 72 $ 162 $ 69 Power: Coal Generating: Conemaugh 23 % $ 404 $ 154 $ 397 $ 142 Keystone 23 % $ 408 $ 163 $ 396 $ 151 Nuclear Generating: Peach Bottom 50 % $ 1,219 $ 262 $ 1,087 $ 236 Salem 57 % $ 990 $ 276 $ 916 $ 236 Nuclear Support Facilities Various $ 226 $ 60 $ 218 $ 49 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 24 $ 41 $ 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, 2015 | |
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 and 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, 2015 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, 2015 2014 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Stranded Costs (including $249 in 2014 related to VIEs) — 412 Through December 2015 (2) Underrecovered Electric Energy Costs—Basic Generation Service 11 — Annual filing for recovery (1) (2) Weather Normalization Clause (WNC) 10 — Annual filing for recovery (2) Solar and Energy Efficiency Recovery Charges (Green Program Recovery Charges (GPRC)) 1 13 Annual filing for recovery (1) (2) Other — 5 Various Total Current Regulatory Assets $ 164 $ 572 Noncurrent Pension and OPEB Costs $ 1,270 $ 1,265 Various Deferred Income Taxes 467 473 Various Manufactured Gas Plant (MGP) Remediation Costs 431 434 Various (2) Storm Damage Deferrals 233 245 To be determined Remediation Adjustment Charge (RAC) (Other SBC) 174 164 Through 2022 (1) (2) Conditional Asset Retirement Obligation 152 138 Various Electric Transmission Cost of Removal 133 91 Through depreciation rates GPRC 104 134 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 67 74 Over remaining debt life Mark-to-Market (MTM) Contracts 63 75 Through 2017 Other 102 99 Various Total Noncurrent Regulatory Assets $ 3,196 $ 3,192 Total Regulatory Assets $ 3,360 $ 3,764 As of December 31, 2015 2014 Recovery/Refund Period Millions Regulatory Liabilities Current Stranded Costs (including $42 in 2015 related to VIEs) $ 64 $ — Through December 2016 (2) GPRC 36 6 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 31 13 Various (1) (2) FERC Formula Rate True-up 19 — Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 13 28 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 1 46 Annual filing for recovery (1) (2) WNC — 31 Annual filing for recovery (2) Deferred Income Taxes — 28 Various Overrecovered Electric Energy Costs— Basic Generation Service — 21 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 1 13 Annual filing for recovery (1) (2) Total Current Regulatory Liabilities $ 165 $ 186 Noncurrent Electric Distribution Cost of Removal $ 122 $ 133 Through depreciation rates FERC Formula Rate True-up 49 26 Annual filing for recovery (1) (2) Stranded Costs (including $39 in 2014 related to VIEs) — 134 Through December 2016 (2) Other 4 4 Various Total Noncurrent Regulatory Liabilities $ 175 $ 297 Total Regulatory Liabilities $ 340 $ 483 (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 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 contracts. 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 2016. Once the rates are measured, they are recovered through the SBC. • NGC: These costs represent the difference between rate payer collections and the cost of non-utility generation netted against amounts realized from selling that energy at market rates through PJM. • Overrecovered Electric Energy Costs: These costs represent the overrecovered amounts associated with Basic Generation Service (BGS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric 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 BGS, interest is accrued on both overrecovered and underrecovered balances. • 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 2015. As of December 31, 2015, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for future recovery under a BPU Order received in September 2014. • Stranded Costs: This reflects the overrecovered balance of costs, which were recovered through the securitization transition charges authorized by the BPU in irrevocable financing orders and collected by PSE&G, as servicer on behalf of Transition Funding and Transition Funding II, respectively. Collected funds are remitted to Transition Funding and Transition Funding II and are 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 remain. Transition Funding and Transition Funding II are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G's electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G's transition costs related to deregulation, as approved by the BPU. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with Stranded Costs and expects to fully refund these liabilities in 2016. • 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 2015 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Energy Strong Recovery Filing —In February 2015, the BPU approved PSE&G's initial Energy Strong filing to recover in base rates an estimated annual electric revenue increase of $1 million effective March 1, 2015. This increase represents capitalized Energy Strong electric investment costs in service through November 30, 2014. In August 2015, the BPU approved PSE&G's second Energy Strong petition to recover in base rates an estimated annual revenue increases in electric revenues of $6 million and gas revenues of $17 million effective September 1, 2015. These increases represent a return on investment and recovery of Energy Strong capitalized investment costs placed in service from December 1, 2014 through May 31, 2015 for electric and from June 1, 2014 through May 31, 2015 for gas. In September 2015, PSE&G filed an 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, 2015 through November 30, 2015. In February 2016, the BPU approved PSE&G’s request for an annualized increase in electric revenue requirements of $10 million with rates effective March 1, 2016. • BGSS —In January 2015 and March 2015, PSE&G filed letters with the BPU to provide self-implementing bill credits for February, March and April 2015. When combined with the January 2015 bill credit filed with the BPU in 2014, a total of $243 million was returned to customers for the period January 1 to April 30, 2015. In April 2015, the BPU issued an Order approving PSE&G’s BGSS rate of 45 cents per therm which had been implemented on October 1, 2014 as final. In June 2015, PSE&G made its Annual BGSS Filing with the BPU requesting a reduction of $70 million in annual BGSS revenues. In September 2015, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 45 cents to 40 cents per therm effective October 1, 2015. In February 2016, the BPU issued an Order approving PSE&G’s BGSS rate of 40 cents per therm as final. In November, 2015, PSE&G filed with the BPU for a self-implementing three-month bill credit of 25 cents per therm for the months of December 2015 and January and February 2016. The bill credits are estimated to provide approximately $155 million to customers. The specific amount returned will depend on actual usage over that period. • WNC —On April 15, 2015, the BPU approved PSE&G's final filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2013 through May 31, 2014). Effective October 1, 2014, PSEG commenced returning $45 million in revenues to its customers during the 2014-2015 Winter Period (October 1, 2014 through May 31, 2015). In September 2015, the BPU approved PSE&G's filing on a provisional basis with respect to excess revenues collected during the colder than normal 2014-2015 Winter Period. Effective October 1, 2015, PSE&G commenced returning $40 million in revenues to its customers during the 2015-2016 Winter Period (October 1, 2015 through May 31, 2016). In January 2016, the BPU gave final approval to the provisional rates. • Solar and Energy Efficiency - GPRC and Solar Pilot Recovery Charges (SPRC) —In April 2015, the BPU approved PSE&G’s petition for an EEE Extension II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows PSE&G to extend the subprogram offerings under the same clause recovery process as its existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and an allowance for $12 million of additional administrative expenses over the next 15 years. The EEE Extension II Program was added as a ninth component of the GPRC rate effective May 1, 2015. In July of each year, PSE&G files for annual recovery for its Green Program investments which include a return on its investment and recovery of expenses. In May 2015, the BPU approved PSE&G’s July 2014 filing requesting recovery of costs and investments in the first eight combined components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. In July 2015, PSE&G filed its annual GPRC and SPRC cost recovery petitions with the BPU, requesting recovery of costs and investments for the first eight combined components of the electric and gas GPRC, as well as the electric SPRC. The filings proposed rates for the period October 1, 2015 through September 30, 2016 designed to recover approximately $66 million and $10 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU approved programs. In September 2015, the BPU approved the July 2015 filings on a provisional basis, with new rates effective October 1, 2015. In November 2015, PSE&G filed updated costs with the BPU. In January 2016, the BPU gave final approval for rates set to recover adjusted amounts based on this update of approximately $57 million and $8 million in electric and gas revenues, respectively, on an annual basis with rates effective February 1, 2016. • Transmission Formula Rate Filings —In June 2015, PSE&G filed its 2014 true-up adjustment pertaining to its formula rates in effect for 2014, which resulted in an adjustment of $19 million less than the 2014 originally filed revenues. The adjustment was primarily due to the impact of bonus depreciation and lower interest rates which PSE&G had recognized in its Consolidated Statement of Operations for the year ended December 31, 2014. In accordance with PSE&G’s formula rate protocols this Rate Year 2014 true-up adjustment has been incorporated into PSE&G's Annual Formula Rate Update for the 2016 Rate Year. The 2016 Annual Formula Rate Update was filed with FERC in October 2015 and provides for $146 million in increased annual transmission revenues effective January 1, 2016. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. The adjustment for 2016 will include the impact of the extension of bonus depreciation, which was enacted after our 2016 filing was made. This adjustment will be incorporated with the 2016 true-up adjustments filed in 2017 and will be incorporated into PSE&G’s Annual Formula Rate Update for the 2017 Rate Year. • RAC —In August 2015, the BPU approved PSE&G's filing with respect to its RAC 22 petition allowing recovery of $85 million effective September 1, 2015 related to net Manufactured Gas Plant expenditures from August 1, 2013 through July 31, 2014. • USF/Lifeline —In September 2015, the BPU approved rates set to recover costs incurred under the USF/Lifeline energy assistance programs effective October 1, 2015. • SBC and NGC —In May 2015, PSE&G filed a petition to recover approximately $311 million in actual SBC and NGC costs incurred through December 31, 2014 under its Energy Efficiency & Renewable Energy Programs, Social Programs and NGC. In January 2016, the BPU approved PSE&G’s petition with rates effective February 1, 2016. |
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 and 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, 2015 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, 2015 2014 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Stranded Costs (including $249 in 2014 related to VIEs) — 412 Through December 2015 (2) Underrecovered Electric Energy Costs—Basic Generation Service 11 — Annual filing for recovery (1) (2) Weather Normalization Clause (WNC) 10 — Annual filing for recovery (2) Solar and Energy Efficiency Recovery Charges (Green Program Recovery Charges (GPRC)) 1 13 Annual filing for recovery (1) (2) Other — 5 Various Total Current Regulatory Assets $ 164 $ 572 Noncurrent Pension and OPEB Costs $ 1,270 $ 1,265 Various Deferred Income Taxes 467 473 Various Manufactured Gas Plant (MGP) Remediation Costs 431 434 Various (2) Storm Damage Deferrals 233 245 To be determined Remediation Adjustment Charge (RAC) (Other SBC) 174 164 Through 2022 (1) (2) Conditional Asset Retirement Obligation 152 138 Various Electric Transmission Cost of Removal 133 91 Through depreciation rates GPRC 104 134 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 67 74 Over remaining debt life Mark-to-Market (MTM) Contracts 63 75 Through 2017 Other 102 99 Various Total Noncurrent Regulatory Assets $ 3,196 $ 3,192 Total Regulatory Assets $ 3,360 $ 3,764 As of December 31, 2015 2014 Recovery/Refund Period Millions Regulatory Liabilities Current Stranded Costs (including $42 in 2015 related to VIEs) $ 64 $ — Through December 2016 (2) GPRC 36 6 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 31 13 Various (1) (2) FERC Formula Rate True-up 19 — Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 13 28 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 1 46 Annual filing for recovery (1) (2) WNC — 31 Annual filing for recovery (2) Deferred Income Taxes — 28 Various Overrecovered Electric Energy Costs— Basic Generation Service — 21 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 1 13 Annual filing for recovery (1) (2) Total Current Regulatory Liabilities $ 165 $ 186 Noncurrent Electric Distribution Cost of Removal $ 122 $ 133 Through depreciation rates FERC Formula Rate True-up 49 26 Annual filing for recovery (1) (2) Stranded Costs (including $39 in 2014 related to VIEs) — 134 Through December 2016 (2) Other 4 4 Various Total Noncurrent Regulatory Liabilities $ 175 $ 297 Total Regulatory Liabilities $ 340 $ 483 (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 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 contracts. 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 2016. Once the rates are measured, they are recovered through the SBC. • NGC: These costs represent the difference between rate payer collections and the cost of non-utility generation netted against amounts realized from selling that energy at market rates through PJM. • Overrecovered Electric Energy Costs: These costs represent the overrecovered amounts associated with Basic Generation Service (BGS), as approved by the BPU. Pursuant to BPU requirements, PSE&G serves as the supplier of last resort for electric 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 BGS, interest is accrued on both overrecovered and underrecovered balances. • 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 2015. As of December 31, 2015, this includes the $220 million of storm costs, net of insurance recoveries, primarily as a result of Hurricane Irene and Superstorm Sandy, approved for future recovery under a BPU Order received in September 2014. • Stranded Costs: This reflects the overrecovered balance of costs, which were recovered through the securitization transition charges authorized by the BPU in irrevocable financing orders and collected by PSE&G, as servicer on behalf of Transition Funding and Transition Funding II, respectively. Collected funds are remitted to Transition Funding and Transition Funding II and are 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 remain. Transition Funding and Transition Funding II are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G's electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G's transition costs related to deregulation, as approved by the BPU. Effective January 1, 2016, PSE&G commenced refunding the overcollections from customers associated with Stranded Costs and expects to fully refund these liabilities in 2016. • 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 2015 regulatory orders received and currently pending rate filings with FERC and the BPU by PSE&G are as follows: • Energy Strong Recovery Filing —In February 2015, the BPU approved PSE&G's initial Energy Strong filing to recover in base rates an estimated annual electric revenue increase of $1 million effective March 1, 2015. This increase represents capitalized Energy Strong electric investment costs in service through November 30, 2014. In August 2015, the BPU approved PSE&G's second Energy Strong petition to recover in base rates an estimated annual revenue increases in electric revenues of $6 million and gas revenues of $17 million effective September 1, 2015. These increases represent a return on investment and recovery of Energy Strong capitalized investment costs placed in service from December 1, 2014 through May 31, 2015 for electric and from June 1, 2014 through May 31, 2015 for gas. In September 2015, PSE&G filed an 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, 2015 through November 30, 2015. In February 2016, the BPU approved PSE&G’s request for an annualized increase in electric revenue requirements of $10 million with rates effective March 1, 2016. • BGSS —In January 2015 and March 2015, PSE&G filed letters with the BPU to provide self-implementing bill credits for February, March and April 2015. When combined with the January 2015 bill credit filed with the BPU in 2014, a total of $243 million was returned to customers for the period January 1 to April 30, 2015. In April 2015, the BPU issued an Order approving PSE&G’s BGSS rate of 45 cents per therm which had been implemented on October 1, 2014 as final. In June 2015, PSE&G made its Annual BGSS Filing with the BPU requesting a reduction of $70 million in annual BGSS revenues. In September 2015, the BPU approved a Stipulation in this matter on a provisional basis and the BGSS rate was reduced from approximately 45 cents to 40 cents per therm effective October 1, 2015. In February 2016, the BPU issued an Order approving PSE&G’s BGSS rate of 40 cents per therm as final. In November, 2015, PSE&G filed with the BPU for a self-implementing three-month bill credit of 25 cents per therm for the months of December 2015 and January and February 2016. The bill credits are estimated to provide approximately $155 million to customers. The specific amount returned will depend on actual usage over that period. • WNC —On April 15, 2015, the BPU approved PSE&G's final filing with respect to excess revenues collected during the colder than normal 2013-2014 Winter Period (October 1, 2013 through May 31, 2014). Effective October 1, 2014, PSEG commenced returning $45 million in revenues to its customers during the 2014-2015 Winter Period (October 1, 2014 through May 31, 2015). In September 2015, the BPU approved PSE&G's filing on a provisional basis with respect to excess revenues collected during the colder than normal 2014-2015 Winter Period. Effective October 1, 2015, PSE&G commenced returning $40 million in revenues to its customers during the 2015-2016 Winter Period (October 1, 2015 through May 31, 2016). In January 2016, the BPU gave final approval to the provisional rates. • Solar and Energy Efficiency - GPRC and Solar Pilot Recovery Charges (SPRC) —In April 2015, the BPU approved PSE&G’s petition for an EEE Extension II Program to extend three EEE subprograms (multi-family, direct install and hospital efficiency). The Order allows PSE&G to extend the subprogram offerings under the same clause recovery process as its existing EEE Program and allows for $95 million of additional capital expenditures over the next three years and an allowance for $12 million of additional administrative expenses over the next 15 years. The EEE Extension II Program was added as a ninth component of the GPRC rate effective May 1, 2015. In July of each year, PSE&G files for annual recovery for its Green Program investments which include a return on its investment and recovery of expenses. In May 2015, the BPU approved PSE&G’s July 2014 filing requesting recovery of costs and investments in the first eight combined components of the electric and gas GPRC for the period October 1, 2014 through September 30, 2015. In July 2015, PSE&G filed its annual GPRC and SPRC cost recovery petitions with the BPU, requesting recovery of costs and investments for the first eight combined components of the electric and gas GPRC, as well as the electric SPRC. The filings proposed rates for the period October 1, 2015 through September 30, 2016 designed to recover approximately $66 million and $10 million in electric and gas revenues, respectively, on an annual basis associated with PSE&G's implementation of these BPU approved programs. In September 2015, the BPU approved the July 2015 filings on a provisional basis, with new rates effective October 1, 2015. In November 2015, PSE&G filed updated costs with the BPU. In January 2016, the BPU gave final approval for rates set to recover adjusted amounts based on this update of approximately $57 million and $8 million in electric and gas revenues, respectively, on an annual basis with rates effective February 1, 2016. • Transmission Formula Rate Filings —In June 2015, PSE&G filed its 2014 true-up adjustment pertaining to its formula rates in effect for 2014, which resulted in an adjustment of $19 million less than the 2014 originally filed revenues. The adjustment was primarily due to the impact of bonus depreciation and lower interest rates which PSE&G had recognized in its Consolidated Statement of Operations for the year ended December 31, 2014. In accordance with PSE&G’s formula rate protocols this Rate Year 2014 true-up adjustment has been incorporated into PSE&G's Annual Formula Rate Update for the 2016 Rate Year. The 2016 Annual Formula Rate Update was filed with FERC in October 2015 and provides for $146 million in increased annual transmission revenues effective January 1, 2016. Each year, transmission revenues are adjusted to reflect items such as updating estimates used in the filing with actual data. The adjustment for 2016 will include the impact of the extension of bonus depreciation, which was enacted after our 2016 filing was made. This adjustment will be incorporated with the 2016 true-up adjustments filed in 2017 and will be incorporated into PSE&G’s Annual Formula Rate Update for the 2017 Rate Year. • RAC —In August 2015, the BPU approved PSE&G's filing with respect to its RAC 22 petition allowing recovery of $85 million effective September 1, 2015 related to net Manufactured Gas Plant expenditures from August 1, 2013 through July 31, 2014. • USF/Lifeline —In September 2015, the BPU approved rates set to recover costs incurred under the USF/Lifeline energy assistance programs effective October 1, 2015. • SBC and NGC —In May 2015, PSE&G filed a petition to recover approximately $311 million in actual SBC and NGC costs incurred through December 31, 2014 under its Energy Efficiency & Renewable Energy Programs, Social Programs and NGC. In January 2016, the BPU approved PSE&G’s petition with rates effective February 1, 2016. |
Long-Term Investments
Long-Term Investments | 12 Months Ended |
Dec. 31, 2015 | |
Long-Term Investments [Line Items] | |
Long-Term Investments [Text Block] | Long-Term Investments Long-Term Investments as of December 31, 2015 and 2014 included the following: As of December 31, 2015 2014 Millions PSE&G Life Insurance and Supplemental Benefits $ 150 $ 156 Solar Loans 175 187 Other Investments 5 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 119 121 Energy Holdings Lease Investments 784 836 Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) — 2 Total Long-Term Investments $ 1,233 $ 1,307 (A) During the three years ended December 31, 2015 , 2014 and 2013 , the amount of dividends from these investments was $16 million , $17 million and $11 million , respectively. Leases Energy Holdings 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. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 2014 Millions Lease Receivables (net of Non-Recourse Debt) $ 631 $ 691 Estimated Residual Value of Leased Assets 519 525 Total Investment in Rental Receivables 1,150 1,216 Unearned and Deferred Income (366 ) (380 ) Gross Investments in Leases 784 836 Deferred Tax Liabilities (724 ) (738 ) Net Investments in Leases $ 60 $ 98 The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2015 2014 2013 Millions Pre-Tax Income (Loss) from Leases $ 12 $ 24 $ 11 Income Tax Expense (Benefit) on Pre-Tax Income from Leases $ 5 $ 32 $ 6 Equity Method Investments Power had the following equity method investments as of December 31, 2015 : Name As of December 31, 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 16 PA 23% Conemaugh Fuels, LLC $ 14 PA 23% PennEast Pipeline $ 5 PA 12% Kalaeloa $ 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, 2015 and 2014 included the following: As of December 31, 2015 2014 Millions PSE&G Life Insurance and Supplemental Benefits $ 150 $ 156 Solar Loans 175 187 Other Investments 5 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 119 121 Energy Holdings Lease Investments 784 836 Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) — 2 Total Long-Term Investments $ 1,233 $ 1,307 (A) During the three years ended December 31, 2015 , 2014 and 2013 , the amount of dividends from these investments was $16 million , $17 million and $11 million , respectively. Leases Energy Holdings 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. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 2014 Millions Lease Receivables (net of Non-Recourse Debt) $ 631 $ 691 Estimated Residual Value of Leased Assets 519 525 Total Investment in Rental Receivables 1,150 1,216 Unearned and Deferred Income (366 ) (380 ) Gross Investments in Leases 784 836 Deferred Tax Liabilities (724 ) (738 ) Net Investments in Leases $ 60 $ 98 The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2015 2014 2013 Millions Pre-Tax Income (Loss) from Leases $ 12 $ 24 $ 11 Income Tax Expense (Benefit) on Pre-Tax Income from Leases $ 5 $ 32 $ 6 Equity Method Investments Power had the following equity method investments as of December 31, 2015 : Name As of December 31, 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 16 PA 23% Conemaugh Fuels, LLC $ 14 PA 23% PennEast Pipeline $ 5 PA 12% Kalaeloa $ 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, 2015 and 2014 included the following: As of December 31, 2015 2014 Millions PSE&G Life Insurance and Supplemental Benefits $ 150 $ 156 Solar Loans 175 187 Other Investments 5 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 119 121 Energy Holdings Lease Investments 784 836 Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) — 2 Total Long-Term Investments $ 1,233 $ 1,307 (A) During the three years ended December 31, 2015 , 2014 and 2013 , the amount of dividends from these investments was $16 million , $17 million and $11 million , respectively. Leases Energy Holdings 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. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 2014 Millions Lease Receivables (net of Non-Recourse Debt) $ 631 $ 691 Estimated Residual Value of Leased Assets 519 525 Total Investment in Rental Receivables 1,150 1,216 Unearned and Deferred Income (366 ) (380 ) Gross Investments in Leases 784 836 Deferred Tax Liabilities (724 ) (738 ) Net Investments in Leases $ 60 $ 98 The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2015 2014 2013 Millions Pre-Tax Income (Loss) from Leases $ 12 $ 24 $ 11 Income Tax Expense (Benefit) on Pre-Tax Income from Leases $ 5 $ 32 $ 6 Equity Method Investments Power had the following equity method investments as of December 31, 2015 : Name As of December 31, 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 16 PA 23% Conemaugh Fuels, LLC $ 14 PA 23% PennEast Pipeline $ 5 PA 12% Kalaeloa $ 84 HI 50% |
Financing Receivables
Financing Receivables | 12 Months Ended |
Dec. 31, 2015 | |
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 6. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Credit Risk Profile Based on Payment Activity As of December 31, Consumer Loans 2015 2014 Millions Commercial/Industrial $ 177 $ 188 Residential 12 13 $ 189 $ 201 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $60 million as of December 31, 2015 and $98 million as of December 31, 2014 (See Note 6. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected below, 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 and Poor's (S&P) as of December 31, 2015 As of December 31, 2015 Millions AA $ 17 BBB+ - BBB- 316 BB- 134 CCC+ 164 $ 631 The “BB-” and the "CCC+" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2015 , the gross investment in the leases of such assets, net of non-recourse debt, was $573 million , ( $(30) 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 $ 84 64 % 1,044 Coal BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Conemaugh Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Shawville Station Units 1, 2, 3 and 4 PA $ 113 100 % 603 Coal CCC+ NRG REMA, LLC The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. 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 attempt to 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 investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay 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. If 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 (IRS). Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which 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 the quality and condition of assets under lease. NRG REMA, LLC (NRG) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the summer of 2016 with the ability to use natural gas. |
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 6. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Credit Risk Profile Based on Payment Activity As of December 31, Consumer Loans 2015 2014 Millions Commercial/Industrial $ 177 $ 188 Residential 12 13 $ 189 $ 201 Energy Holdings Energy Holdings had a net investment in domestic energy and real estate assets subject to leveraged lease accounting of $60 million as of December 31, 2015 and $98 million as of December 31, 2014 (See Note 6. Long-Term Investments ). The corresponding receivables associated with the lease portfolio are reflected below, 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 and Poor's (S&P) as of December 31, 2015 As of December 31, 2015 Millions AA $ 17 BBB+ - BBB- 316 BB- 134 CCC+ 164 $ 631 The “BB-” and the "CCC+" ratings in the preceding table represent lease receivables related to coal-fired assets in Illinois and Pennsylvania, respectively. As of December 31, 2015 , the gross investment in the leases of such assets, net of non-recourse debt, was $573 million , ( $(30) 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 $ 84 64 % 1,044 Coal BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Conemaugh Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Shawville Station Units 1, 2, 3 and 4 PA $ 113 100 % 603 Coal CCC+ NRG REMA, LLC The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. 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 attempt to 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 investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay 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. If 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 (IRS). Although all lease payments are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which 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 the quality and condition of assets under lease. NRG REMA, LLC (NRG) notified PJM that it deactivated the coal-fired units at the Shawville generating facility in June 2015 and has disclosed that it expects to return the Shawville units to service in the summer of 2016 with the ability to use natural gas. |
Available-for-Sale Securities
Available-for-Sale Securities | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 was approximately $429 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government Obligations 483 8 (3 ) 488 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 685 $ 220 $ (8 ) $ 897 Debt Securities Government Obligations 430 9 (1 ) 438 Other Debt Securities 333 9 (3 ) 339 Total Debt Securities 763 18 (4 ) 777 Other Securities 106 — — 106 Total NDT Available-for-Sale Securities $ 1,554 $ 238 $ (12 ) $ 1,780 These 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, 2015 As of December 31, 2014 Millions Accounts Receivable $ 17 $ 10 Accounts Payable $ 10 $ 2 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, 2015 As of December 31, 2014 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) $ 151 $ (13 ) $ 1 $ — $ 162 $ (8 ) $ 1 $ — Debt Securities Government Obligations (B) 245 (2 ) 19 (1 ) 95 — 28 (1 ) Other Debt Securities (C) 222 (7 ) 36 (3 ) 99 (1 ) 30 (2 ) Total Debt Securities 467 (9 ) 55 (4 ) 194 (1 ) 58 (3 ) NDT Available-for-Sale Securities $ 618 $ (22 ) $ 56 $ (4 ) $ 356 $ (9 ) $ 59 $ (3 ) (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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Sales (A) $ 1,397 $ 1,448 $ 1,070 Net Realized Gains (Losses): Gross Realized Gains $ 97 $ 177 $ 112 Gross Realized Losses (37 ) (23 ) (26 ) Net Realized Gains (Losses) on NDT Fund $ 60 $ 154 $ 86 (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 $86 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG's and Power’s Consolidated Balance Sheets as of December 31, 2015 . The available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 16 1 - 5 years 209 6 - 10 years 200 11 - 15 years 57 16 - 20 years 49 Over 20 years 316 Total NDT Available-for-Sale Debt Securities $ 847 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 2015 , other-than-temporary impairments of $53 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government Obligations 108 1 (1 ) 108 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 11 $ — $ 23 Debt Securities Government Obligations 89 2 — 91 Other Debt Securities 74 1 — 75 Total Debt Securities 163 3 — 166 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 177 $ 14 $ — $ 191 These 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 show in the following table. As of December 31, 2015 As of December 31, 2014 Millions Accounts Receivable $ 1 $ 1 Accounts Payable $ — $ — 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, 2015 As of December 31, 2014 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 Obligations (B) 53 (1 ) 2 — 2 — — — Other Debt Securities (C) 46 (1 ) 9 — 24 — — — Total Debt Securities 99 (2 ) 11 — 26 — — — Rabbi Trust Available-for-Sale Securities $ 99 $ (2 ) $ 11 $ — $ 26 $ — $ — $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is 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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Rabbi Trust Sales (A) $ 104 $ 467 $ 89 Net Realized Gains (Losses): Gross Realized Gains $ 3 $ 4 $ 4 Gross Realized Losses (2 ) (3 ) (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, 2015 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 3 1 - 5 years 49 6 - 10 years 44 11 - 15 years 5 16 - 20 years 8 Over 20 years 80 Total Rabbi Trust Available-for-Sale Debt Securities $ 189 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 2015 , 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, 2015 As of December 31, 2014 Millions PSE&G $ 42 $ 41 Power 52 45 Other 119 105 Total Rabbi Trust Available-for-Sale Securities $ 213 $ 191 |
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, 2015 was approximately $429 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government Obligations 483 8 (3 ) 488 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 685 $ 220 $ (8 ) $ 897 Debt Securities Government Obligations 430 9 (1 ) 438 Other Debt Securities 333 9 (3 ) 339 Total Debt Securities 763 18 (4 ) 777 Other Securities 106 — — 106 Total NDT Available-for-Sale Securities $ 1,554 $ 238 $ (12 ) $ 1,780 These 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, 2015 As of December 31, 2014 Millions Accounts Receivable $ 17 $ 10 Accounts Payable $ 10 $ 2 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, 2015 As of December 31, 2014 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) $ 151 $ (13 ) $ 1 $ — $ 162 $ (8 ) $ 1 $ — Debt Securities Government Obligations (B) 245 (2 ) 19 (1 ) 95 — 28 (1 ) Other Debt Securities (C) 222 (7 ) 36 (3 ) 99 (1 ) 30 (2 ) Total Debt Securities 467 (9 ) 55 (4 ) 194 (1 ) 58 (3 ) NDT Available-for-Sale Securities $ 618 $ (22 ) $ 56 $ (4 ) $ 356 $ (9 ) $ 59 $ (3 ) (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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Sales (A) $ 1,397 $ 1,448 $ 1,070 Net Realized Gains (Losses): Gross Realized Gains $ 97 $ 177 $ 112 Gross Realized Losses (37 ) (23 ) (26 ) Net Realized Gains (Losses) on NDT Fund $ 60 $ 154 $ 86 (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 $86 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG's and Power’s Consolidated Balance Sheets as of December 31, 2015 . The available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 16 1 - 5 years 209 6 - 10 years 200 11 - 15 years 57 16 - 20 years 49 Over 20 years 316 Total NDT Available-for-Sale Debt Securities $ 847 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 2015 , other-than-temporary impairments of $53 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government Obligations 108 1 (1 ) 108 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 11 $ — $ 23 Debt Securities Government Obligations 89 2 — 91 Other Debt Securities 74 1 — 75 Total Debt Securities 163 3 — 166 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 177 $ 14 $ — $ 191 These 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 show in the following table. As of December 31, 2015 As of December 31, 2014 Millions Accounts Receivable $ 1 $ 1 Accounts Payable $ — $ — 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, 2015 As of December 31, 2014 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 Obligations (B) 53 (1 ) 2 — 2 — — — Other Debt Securities (C) 46 (1 ) 9 — 24 — — — Total Debt Securities 99 (2 ) 11 — 26 — — — Rabbi Trust Available-for-Sale Securities $ 99 $ (2 ) $ 11 $ — $ 26 $ — $ — $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is 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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Rabbi Trust Sales (A) $ 104 $ 467 $ 89 Net Realized Gains (Losses): Gross Realized Gains $ 3 $ 4 $ 4 Gross Realized Losses (2 ) (3 ) (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, 2015 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 3 1 - 5 years 49 6 - 10 years 44 11 - 15 years 5 16 - 20 years 8 Over 20 years 80 Total Rabbi Trust Available-for-Sale Debt Securities $ 189 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 2015 , 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, 2015 As of December 31, 2014 Millions PSE&G $ 42 $ 41 Power 52 45 Other 119 105 Total Rabbi Trust Available-for-Sale Securities $ 213 $ 191 |
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, 2015 was approximately $429 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government Obligations 483 8 (3 ) 488 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 685 $ 220 $ (8 ) $ 897 Debt Securities Government Obligations 430 9 (1 ) 438 Other Debt Securities 333 9 (3 ) 339 Total Debt Securities 763 18 (4 ) 777 Other Securities 106 — — 106 Total NDT Available-for-Sale Securities $ 1,554 $ 238 $ (12 ) $ 1,780 These 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, 2015 As of December 31, 2014 Millions Accounts Receivable $ 17 $ 10 Accounts Payable $ 10 $ 2 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, 2015 As of December 31, 2014 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) $ 151 $ (13 ) $ 1 $ — $ 162 $ (8 ) $ 1 $ — Debt Securities Government Obligations (B) 245 (2 ) 19 (1 ) 95 — 28 (1 ) Other Debt Securities (C) 222 (7 ) 36 (3 ) 99 (1 ) 30 (2 ) Total Debt Securities 467 (9 ) 55 (4 ) 194 (1 ) 58 (3 ) NDT Available-for-Sale Securities $ 618 $ (22 ) $ 56 $ (4 ) $ 356 $ (9 ) $ 59 $ (3 ) (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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the NDT Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Sales (A) $ 1,397 $ 1,448 $ 1,070 Net Realized Gains (Losses): Gross Realized Gains $ 97 $ 177 $ 112 Gross Realized Losses (37 ) (23 ) (26 ) Net Realized Gains (Losses) on NDT Fund $ 60 $ 154 $ 86 (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 $86 million (after-tax) are included in Accumulated Other Comprehensive Loss on PSEG's and Power’s Consolidated Balance Sheets as of December 31, 2015 . The available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 16 1 - 5 years 209 6 - 10 years 200 11 - 15 years 57 16 - 20 years 49 Over 20 years 316 Total NDT Available-for-Sale Debt Securities $ 847 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 2015 , other-than-temporary impairments of $53 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government Obligations 108 1 (1 ) 108 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 11 $ — $ 23 Debt Securities Government Obligations 89 2 — 91 Other Debt Securities 74 1 — 75 Total Debt Securities 163 3 — 166 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 177 $ 14 $ — $ 191 These 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 show in the following table. As of December 31, 2015 As of December 31, 2014 Millions Accounts Receivable $ 1 $ 1 Accounts Payable $ — $ — 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, 2015 As of December 31, 2014 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 Obligations (B) 53 (1 ) 2 — 2 — — — Other Debt Securities (C) 46 (1 ) 9 — 24 — — — Total Debt Securities 99 (2 ) 11 — 26 — — — Rabbi Trust Available-for-Sale Securities $ 99 $ (2 ) $ 11 $ — $ 26 $ — $ — $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is 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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . The proceeds from the sales of and the net realized gains on securities in the Rabbi Trust Fund were: Years Ended December 31, 2015 2014 2013 Millions Proceeds from Rabbi Trust Sales (A) $ 104 $ 467 $ 89 Net Realized Gains (Losses): Gross Realized Gains $ 3 $ 4 $ 4 Gross Realized Losses (2 ) (3 ) (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, 2015 . The Rabbi Trust available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 3 1 - 5 years 49 6 - 10 years 44 11 - 15 years 5 16 - 20 years 8 Over 20 years 80 Total Rabbi Trust Available-for-Sale Debt Securities $ 189 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 2015 , 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, 2015 As of December 31, 2014 Millions PSE&G $ 42 $ 41 Power 52 45 Other 119 105 Total Rabbi Trust Available-for-Sale Securities $ 213 $ 191 |
Goodwill And Other Intangibles
Goodwill And Other Intangibles | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill [Line Items] | |
Goodwill And Other Intangibles | Goodwill and Other Intangibles As of December 31, 2015 and 2014 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment as of October 31, 2015 and concluded that goodwill was not impaired. No events occurred subsequent to that date which would require a further review of goodwill for impairment. In addition to goodwill, as of December 31, 2015 and 2014 , Power had intangible assets of $ 102 million and $ 84 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, 2015 , 2014 and 2013 were as follows: Years Ended December 31, 2015 2014 2013 Millions Emissions Expense $ 13 $ 10 $ 6 Renewable Energy Expense $ 91 $ 59 $ 26 |
Power [Member] | |
Goodwill [Line Items] | |
Goodwill And Other Intangibles | Goodwill and Other Intangibles As of December 31, 2015 and 2014 , Power had goodwill of $ 16 million related to the Bethlehem Energy Center facility. Power conducted an annual review for goodwill impairment as of October 31, 2015 and concluded that goodwill was not impaired. No events occurred subsequent to that date which would require a further review of goodwill for impairment. In addition to goodwill, as of December 31, 2015 and 2014 , Power had intangible assets of $ 102 million and $ 84 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, 2015 , 2014 and 2013 were as follows: Years Ended December 31, 2015 2014 2013 Millions Emissions Expense $ 13 $ 10 $ 6 Renewable Energy Expense $ 91 $ 59 $ 26 |
Asset Retirement Obligations (A
Asset Retirement Obligations (AROs) | 12 Months Ended |
Dec. 31, 2015 | |
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 8. 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 2014 and 2015 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2014 $ 677 $ 274 $ 400 $ 3 Liabilities Settled (2 ) (2 ) — — Liabilities Incurred 23 3 20 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 15 15 — — ARO Liability as of December 31, 2014 $ 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 (A) Not reflected as expense in Consolidated Statements of Operations During 2015, PSE&G recorded a reduction to its ARO liabilities primarily due to the impact of lower inflation rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations. During 2015, Power recorded a reduction to its ARO liabilities, primarily due to changes in the inflation and discount rates and changes in assumptions related to the weighted probabilities for nuclear AROs partially offset by increases in estimated costs to decommission our nuclear units pursuant to our most recent cost study. These changes did not result in any material impact in Power's Consolidated Statement of Operations. |
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 8. 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 2014 and 2015 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2014 $ 677 $ 274 $ 400 $ 3 Liabilities Settled (2 ) (2 ) — — Liabilities Incurred 23 3 20 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 15 15 — — ARO Liability as of December 31, 2014 $ 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 (A) Not reflected as expense in Consolidated Statements of Operations During 2015, PSE&G recorded a reduction to its ARO liabilities primarily due to the impact of lower inflation rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations. During 2015, Power recorded a reduction to its ARO liabilities, primarily due to changes in the inflation and discount rates and changes in assumptions related to the weighted probabilities for nuclear AROs partially offset by increases in estimated costs to decommission our nuclear units pursuant to our most recent cost study. These changes did not result in any material impact in Power's Consolidated Statement of Operations. |
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 8. 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 2014 and 2015 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2014 $ 677 $ 274 $ 400 $ 3 Liabilities Settled (2 ) (2 ) — — Liabilities Incurred 23 3 20 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 15 15 — — ARO Liability as of December 31, 2014 $ 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 (A) Not reflected as expense in Consolidated Statements of Operations During 2015, PSE&G recorded a reduction to its ARO liabilities primarily due to the impact of lower inflation rates. These changes had no impact in PSE&G’s Consolidated Statement of Operations. During 2015, Power recorded a reduction to its ARO liabilities, primarily due to changes in the inflation and discount rates and changes in assumptions related to the weighted probabilities for nuclear AROs partially offset by increases in estimated costs to decommission our nuclear units pursuant to our most recent cost study. These changes did not result in any material impact in Power's Consolidated Statement of Operations. |
Pension, OPEB and Savings Plans
Pension, OPEB and Savings Plans | 12 Months Ended |
Dec. 31, 2015 | |
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 several 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. At the end of 2015, 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 will be reflected prospectively. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,722 $ 4,812 $ 1,638 $ 1,414 Service Cost 123 104 22 18 Interest Cost 234 234 67 69 Actuarial (Gain) Loss (B) (289 ) 838 (45 ) 210 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Benefit Obligation at End of Year (A) (B) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,293 $ 5,116 $ 361 $ 319 Actual Return on Plan Assets (11 ) 433 (1 ) 28 Employer Contributions 25 10 84 87 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Fair Value of Assets at End of Year $ 5,039 $ 5,293 $ 374 $ 361 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ 14 $ 21 $ — $ — Current Accrued Benefit Cost (10 ) (10 ) (10 ) — Noncurrent Accrued Benefit Cost (487 ) (440 ) (1,228 ) (1,277 ) Amounts Recognized $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C) Prior Service Cost $ (83 ) $ (102 ) $ (25 ) $ (39 ) Net Actuarial Loss 1,710 1,724 438 495 Total $ 1,627 $ 1,622 $ 413 $ 456 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013. (C) Includes $ 658 million ($ 386 million , after-tax) and $ 702 million ($ 411 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2015 and 2014 , respectively. The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. As of December 31, 2015 , PSEG had funded approximately 91% of its projected benefit obligation. This percentage does not include $ 213 million of assets in the Rabbi Trust as of December 31, 2015 which were used partially to fund the nonqualified pension plans. As of December 31, 2015 , the nonqualified pension plans included in the projected benefit obligation in the above table were $159 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 $ 5.4 billion as of December 31, 2015 and $ 5.5 billion as of December 31, 2014 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2015 , 2014 and 2013 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 123 $ 104 $ 116 $ 22 $ 18 21 Interest Cost 234 234 215 67 69 63 Expected Return on Plan Assets (414 ) (399 ) (348 ) (31 ) (26 ) (21 ) Amortization of Net Prior Service Cost (19 ) (18 ) (19 ) (14 ) (14 ) (14 ) Actuarial Loss 150 56 188 43 23 42 Net Periodic Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 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, 2015 2014 2013 2015 2014 2013 Millions PSE&G $ 40 $ (19 ) $ 91 $ 55 $ 46 $ 65 Power 21 (7 ) 43 27 20 23 Other 13 3 18 5 4 3 Total Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2015 2014 2015 2014 Millions Net Actuarial (Gain) Loss in Current Period $ 136 $ 803 $ (14 ) $ 208 Amortization of Net Actuarial Gain (Loss) (150 ) (56 ) (43 ) (23 ) Amortization of Prior Service Credit 19 18 14 14 Total $ 5 $ 765 $ (43 ) $ 199 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2016 are as follows: Pension Benefits Other Benefits 2016 2016 Millions Actuarial (Gain) Loss $ 158 $ 40 Prior Service Cost $ (18 ) $ (14 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.20 % 5.00 % 4.20 % 4.21 % 5.01 % 4.20 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 4.61 % 4.61 % 3.61 % 4.61 % 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 7.75 % 7.40 % 7.83 % Ultimate Rate 4.75 % 5.00 % 5.00 % Year Ultimate Rate Reached 2025 2022 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 12 $ 13 $ 12 Postretirement Benefit Obligation $ 194 $ 201 $ 161 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (10 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (160 ) $ (165 ) $ (134 ) Plan Assets All the investments of pension plans 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 16. 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, 2015 , 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ 103 $ 102 $ 1 $ — Common Stocks (B) Commingled-United States 1,980 1,980 — — Commingled-International 987 987 — — Other 816 816 — — Bonds (C) Government (United States & Foreign) 602 — 602 — Other 906 — 906 — Private Equity (D) 19 — — 19 Total $ 5,413 $ 3,885 $ 1,509 $ 19 Recurring Fair Value Measurements as of December 31, 2014 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) $ 153 $ 92 $ 61 $ — Common Stocks (B) Commingled-United States 2,292 2,292 — — Commingled-International 1,005 1,005 — — Other 727 727 — — Bonds (C) Government (United States & Foreign) 509 — 509 — Other 943 — 943 — Private Equity (D) 25 — — 25 Total $ 5,654 $ 4,116 $ 1,513 $ 25 (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) Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). (D) Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3). Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2015 and 2014 are as follows: Balance as of January 1, 2015 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2015 Millions Private Equity $ 25 $ (10 ) $ — $ 1 $ 3 $ 19 Balance as of January 1, 2014 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2014 Millions Private Equity $ 25 $ (5 ) $ — $ 3 $ 2 $ 25 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 2015 2014 Equity Securities 70 % 71 % Fixed Income Securities 28 26 Other Investments 2 3 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 8.00% as of December 31, 2015 and will remain unchanged for 2016 . 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 $21 million into its qualified pension plans and $14 million into its OPEB plan, respectively, during 2016 . 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 2016 $ 285 $ 81 2017 295 84 2018 305 87 2019 317 91 2020 329 95 2021-2025 1,818 518 Total $ 3,349 $ 956 401(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. 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, 2015 2014 2013 Millions PSE&G $ 22 $ 20 $ 19 Power 12 11 10 Other 5 5 4 Total Employer Matching Contributions $ 39 $ 36 $ 33 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 3. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 195 $ — $ 452 $ — Service Cost 26 20 17 13 Interest Cost 9 7 21 17 Actuarial (Gain) Loss (20 ) 42 (114 ) 107 Gross Benefits Paid — — (1 ) — Plan Amendments 1 126 — 315 Benefit Obligation at End of Year (A) $ 211 $ 195 $ 375 $ 452 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 69 $ — $ — $ — Actual Return on Plan Assets (2 ) 2 — — Employer Contributions 30 67 1 — Gross Benefits Paid — — (1 ) — Fair Value of Assets at End of Year $ 97 $ 69 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (114 ) $ (126 ) $ (375 ) $ (452 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (114 ) $ (126 ) N/A N/A OPEB Costs of Servco N/A N/A (375 ) (452 ) Amounts Recognized (B) $ (114 ) $ (126 ) $ (375 ) $ (452 ) (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 Sheet. 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 2015 and 2014 were $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2015 . The OPEB-related revenues earned and costs incurred in 2015 and 2014 were immaterial. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2015 2014 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.92 % 4.50 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.33 % Ultimate Rate 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (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 16. 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ — $ — $ — $ — Common Stocks (B) Commingled-United States 68 68 — — Bonds (C) Other 29 — 29 — Total $ 97 $ 68 $ 29 $ — Recurring Fair Value Measurements as of December 31, 2014 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) $ 1 $ — $ 1 $ — Common Stocks (B) Commingled-United States 48 48 — — Bonds (C) Other 20 — 20 — Total $ 69 $ 48 $ 21 $ — (A) Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Wherever possible, fair values of equity investments in commingled stock funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily 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 2015 2014 Equity Securities 71 % 70 % Fixed Income Securities 29 29 Other Investments — 1 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% as of December 31, 2015 and will remain unchanged for 2016 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2016 . 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 2016 $ 1 $ 3 2017 2 5 2018 3 7 2019 4 8 2020 6 10 2021-2025 60 80 Total $ 76 $ 113 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, 2015, 2014 and 2013 were immaterial 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 several 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. At the end of 2015, 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 will be reflected prospectively. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,722 $ 4,812 $ 1,638 $ 1,414 Service Cost 123 104 22 18 Interest Cost 234 234 67 69 Actuarial (Gain) Loss (B) (289 ) 838 (45 ) 210 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Benefit Obligation at End of Year (A) (B) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,293 $ 5,116 $ 361 $ 319 Actual Return on Plan Assets (11 ) 433 (1 ) 28 Employer Contributions 25 10 84 87 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Fair Value of Assets at End of Year $ 5,039 $ 5,293 $ 374 $ 361 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ 14 $ 21 $ — $ — Current Accrued Benefit Cost (10 ) (10 ) (10 ) — Noncurrent Accrued Benefit Cost (487 ) (440 ) (1,228 ) (1,277 ) Amounts Recognized $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C) Prior Service Cost $ (83 ) $ (102 ) $ (25 ) $ (39 ) Net Actuarial Loss 1,710 1,724 438 495 Total $ 1,627 $ 1,622 $ 413 $ 456 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013. (C) Includes $ 658 million ($ 386 million , after-tax) and $ 702 million ($ 411 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2015 and 2014 , respectively. The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. As of December 31, 2015 , PSEG had funded approximately 91% of its projected benefit obligation. This percentage does not include $ 213 million of assets in the Rabbi Trust as of December 31, 2015 which were used partially to fund the nonqualified pension plans. As of December 31, 2015 , the nonqualified pension plans included in the projected benefit obligation in the above table were $159 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 $ 5.4 billion as of December 31, 2015 and $ 5.5 billion as of December 31, 2014 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2015 , 2014 and 2013 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 123 $ 104 $ 116 $ 22 $ 18 21 Interest Cost 234 234 215 67 69 63 Expected Return on Plan Assets (414 ) (399 ) (348 ) (31 ) (26 ) (21 ) Amortization of Net Prior Service Cost (19 ) (18 ) (19 ) (14 ) (14 ) (14 ) Actuarial Loss 150 56 188 43 23 42 Net Periodic Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 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, 2015 2014 2013 2015 2014 2013 Millions PSE&G $ 40 $ (19 ) $ 91 $ 55 $ 46 $ 65 Power 21 (7 ) 43 27 20 23 Other 13 3 18 5 4 3 Total Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2015 2014 2015 2014 Millions Net Actuarial (Gain) Loss in Current Period $ 136 $ 803 $ (14 ) $ 208 Amortization of Net Actuarial Gain (Loss) (150 ) (56 ) (43 ) (23 ) Amortization of Prior Service Credit 19 18 14 14 Total $ 5 $ 765 $ (43 ) $ 199 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2016 are as follows: Pension Benefits Other Benefits 2016 2016 Millions Actuarial (Gain) Loss $ 158 $ 40 Prior Service Cost $ (18 ) $ (14 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.20 % 5.00 % 4.20 % 4.21 % 5.01 % 4.20 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 4.61 % 4.61 % 3.61 % 4.61 % 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 7.75 % 7.40 % 7.83 % Ultimate Rate 4.75 % 5.00 % 5.00 % Year Ultimate Rate Reached 2025 2022 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 12 $ 13 $ 12 Postretirement Benefit Obligation $ 194 $ 201 $ 161 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (10 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (160 ) $ (165 ) $ (134 ) Plan Assets All the investments of pension plans 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 16. 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, 2015 , 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ 103 $ 102 $ 1 $ — Common Stocks (B) Commingled-United States 1,980 1,980 — — Commingled-International 987 987 — — Other 816 816 — — Bonds (C) Government (United States & Foreign) 602 — 602 — Other 906 — 906 — Private Equity (D) 19 — — 19 Total $ 5,413 $ 3,885 $ 1,509 $ 19 Recurring Fair Value Measurements as of December 31, 2014 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) $ 153 $ 92 $ 61 $ — Common Stocks (B) Commingled-United States 2,292 2,292 — — Commingled-International 1,005 1,005 — — Other 727 727 — — Bonds (C) Government (United States & Foreign) 509 — 509 — Other 943 — 943 — Private Equity (D) 25 — — 25 Total $ 5,654 $ 4,116 $ 1,513 $ 25 (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) Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). (D) Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3). Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2015 and 2014 are as follows: Balance as of January 1, 2015 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2015 Millions Private Equity $ 25 $ (10 ) $ — $ 1 $ 3 $ 19 Balance as of January 1, 2014 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2014 Millions Private Equity $ 25 $ (5 ) $ — $ 3 $ 2 $ 25 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 2015 2014 Equity Securities 70 % 71 % Fixed Income Securities 28 26 Other Investments 2 3 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 8.00% as of December 31, 2015 and will remain unchanged for 2016 . 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 $21 million into its qualified pension plans and $14 million into its OPEB plan, respectively, during 2016 . 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 2016 $ 285 $ 81 2017 295 84 2018 305 87 2019 317 91 2020 329 95 2021-2025 1,818 518 Total $ 3,349 $ 956 401(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. 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, 2015 2014 2013 Millions PSE&G $ 22 $ 20 $ 19 Power 12 11 10 Other 5 5 4 Total Employer Matching Contributions $ 39 $ 36 $ 33 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 3. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 195 $ — $ 452 $ — Service Cost 26 20 17 13 Interest Cost 9 7 21 17 Actuarial (Gain) Loss (20 ) 42 (114 ) 107 Gross Benefits Paid — — (1 ) — Plan Amendments 1 126 — 315 Benefit Obligation at End of Year (A) $ 211 $ 195 $ 375 $ 452 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 69 $ — $ — $ — Actual Return on Plan Assets (2 ) 2 — — Employer Contributions 30 67 1 — Gross Benefits Paid — — (1 ) — Fair Value of Assets at End of Year $ 97 $ 69 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (114 ) $ (126 ) $ (375 ) $ (452 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (114 ) $ (126 ) N/A N/A OPEB Costs of Servco N/A N/A (375 ) (452 ) Amounts Recognized (B) $ (114 ) $ (126 ) $ (375 ) $ (452 ) (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 Sheet. 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 2015 and 2014 were $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2015 . The OPEB-related revenues earned and costs incurred in 2015 and 2014 were immaterial. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2015 2014 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.92 % 4.50 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.33 % Ultimate Rate 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (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 16. 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ — $ — $ — $ — Common Stocks (B) Commingled-United States 68 68 — — Bonds (C) Other 29 — 29 — Total $ 97 $ 68 $ 29 $ — Recurring Fair Value Measurements as of December 31, 2014 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) $ 1 $ — $ 1 $ — Common Stocks (B) Commingled-United States 48 48 — — Bonds (C) Other 20 — 20 — Total $ 69 $ 48 $ 21 $ — (A) Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Wherever possible, fair values of equity investments in commingled stock funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily 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 2015 2014 Equity Securities 71 % 70 % Fixed Income Securities 29 29 Other Investments — 1 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% as of December 31, 2015 and will remain unchanged for 2016 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2016 . 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 2016 $ 1 $ 3 2017 2 5 2018 3 7 2019 4 8 2020 6 10 2021-2025 60 80 Total $ 76 $ 113 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, 2015, 2014 and 2013 were immaterial 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 several 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. At the end of 2015, 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 will be reflected prospectively. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,722 $ 4,812 $ 1,638 $ 1,414 Service Cost 123 104 22 18 Interest Cost 234 234 67 69 Actuarial (Gain) Loss (B) (289 ) 838 (45 ) 210 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Benefit Obligation at End of Year (A) (B) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,293 $ 5,116 $ 361 $ 319 Actual Return on Plan Assets (11 ) 433 (1 ) 28 Employer Contributions 25 10 84 87 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Fair Value of Assets at End of Year $ 5,039 $ 5,293 $ 374 $ 361 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ 14 $ 21 $ — $ — Current Accrued Benefit Cost (10 ) (10 ) (10 ) — Noncurrent Accrued Benefit Cost (487 ) (440 ) (1,228 ) (1,277 ) Amounts Recognized $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C) Prior Service Cost $ (83 ) $ (102 ) $ (25 ) $ (39 ) Net Actuarial Loss 1,710 1,724 438 495 Total $ 1,627 $ 1,622 $ 413 $ 456 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013. (C) Includes $ 658 million ($ 386 million , after-tax) and $ 702 million ($ 411 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2015 and 2014 , respectively. The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. As of December 31, 2015 , PSEG had funded approximately 91% of its projected benefit obligation. This percentage does not include $ 213 million of assets in the Rabbi Trust as of December 31, 2015 which were used partially to fund the nonqualified pension plans. As of December 31, 2015 , the nonqualified pension plans included in the projected benefit obligation in the above table were $159 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 $ 5.4 billion as of December 31, 2015 and $ 5.5 billion as of December 31, 2014 . The following table provides the components of net periodic benefit cost for the years ended December 31, 2015 , 2014 and 2013 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 123 $ 104 $ 116 $ 22 $ 18 21 Interest Cost 234 234 215 67 69 63 Expected Return on Plan Assets (414 ) (399 ) (348 ) (31 ) (26 ) (21 ) Amortization of Net Prior Service Cost (19 ) (18 ) (19 ) (14 ) (14 ) (14 ) Actuarial Loss 150 56 188 43 23 42 Net Periodic Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 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, 2015 2014 2013 2015 2014 2013 Millions PSE&G $ 40 $ (19 ) $ 91 $ 55 $ 46 $ 65 Power 21 (7 ) 43 27 20 23 Other 13 3 18 5 4 3 Total Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets: Pension OPEB 2015 2014 2015 2014 Millions Net Actuarial (Gain) Loss in Current Period $ 136 $ 803 $ (14 ) $ 208 Amortization of Net Actuarial Gain (Loss) (150 ) (56 ) (43 ) (23 ) Amortization of Prior Service Credit 19 18 14 14 Total $ 5 $ 765 $ (43 ) $ 199 Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2016 are as follows: Pension Benefits Other Benefits 2016 2016 Millions Actuarial (Gain) Loss $ 158 $ 40 Prior Service Cost $ (18 ) $ (14 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.20 % 5.00 % 4.20 % 4.21 % 5.01 % 4.20 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 4.61 % 4.61 % 3.61 % 4.61 % 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 7.75 % 7.40 % 7.83 % Ultimate Rate 4.75 % 5.00 % 5.00 % Year Ultimate Rate Reached 2025 2022 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 12 $ 13 $ 12 Postretirement Benefit Obligation $ 194 $ 201 $ 161 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (10 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (160 ) $ (165 ) $ (134 ) Plan Assets All the investments of pension plans 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 16. 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, 2015 , 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ 103 $ 102 $ 1 $ — Common Stocks (B) Commingled-United States 1,980 1,980 — — Commingled-International 987 987 — — Other 816 816 — — Bonds (C) Government (United States & Foreign) 602 — 602 — Other 906 — 906 — Private Equity (D) 19 — — 19 Total $ 5,413 $ 3,885 $ 1,509 $ 19 Recurring Fair Value Measurements as of December 31, 2014 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) $ 153 $ 92 $ 61 $ — Common Stocks (B) Commingled-United States 2,292 2,292 — — Commingled-International 1,005 1,005 — — Other 727 727 — — Bonds (C) Government (United States & Foreign) 509 — 509 — Other 943 — 943 — Private Equity (D) 25 — — 25 Total $ 5,654 $ 4,116 $ 1,513 $ 25 (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) Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). (D) Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3). Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2015 and 2014 are as follows: Balance as of January 1, 2015 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2015 Millions Private Equity $ 25 $ (10 ) $ — $ 1 $ 3 $ 19 Balance as of January 1, 2014 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2014 Millions Private Equity $ 25 $ (5 ) $ — $ 3 $ 2 $ 25 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 2015 2014 Equity Securities 70 % 71 % Fixed Income Securities 28 26 Other Investments 2 3 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 8.00% as of December 31, 2015 and will remain unchanged for 2016 . 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 $21 million into its qualified pension plans and $14 million into its OPEB plan, respectively, during 2016 . 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 2016 $ 285 $ 81 2017 295 84 2018 305 87 2019 317 91 2020 329 95 2021-2025 1,818 518 Total $ 3,349 $ 956 401(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. 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, 2015 2014 2013 Millions PSE&G $ 22 $ 20 $ 19 Power 12 11 10 Other 5 5 4 Total Employer Matching Contributions $ 39 $ 36 $ 33 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 3. 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 195 $ — $ 452 $ — Service Cost 26 20 17 13 Interest Cost 9 7 21 17 Actuarial (Gain) Loss (20 ) 42 (114 ) 107 Gross Benefits Paid — — (1 ) — Plan Amendments 1 126 — 315 Benefit Obligation at End of Year (A) $ 211 $ 195 $ 375 $ 452 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 69 $ — $ — $ — Actual Return on Plan Assets (2 ) 2 — — Employer Contributions 30 67 1 — Gross Benefits Paid — — (1 ) — Fair Value of Assets at End of Year $ 97 $ 69 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (114 ) $ (126 ) $ (375 ) $ (452 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (114 ) $ (126 ) N/A N/A OPEB Costs of Servco N/A N/A (375 ) (452 ) Amounts Recognized (B) $ (114 ) $ (126 ) $ (375 ) $ (452 ) (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 Sheet. 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 2015 and 2014 were $30 million and $67 million , respectively. Servco has contributed its entire planned contribution amount to its pension plan trusts during 2015 . The OPEB-related revenues earned and costs incurred in 2015 and 2014 were immaterial. The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2015 2014 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.92 % 4.50 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.33 % Ultimate Rate 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (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 16. 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, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ — $ — $ — $ — Common Stocks (B) Commingled-United States 68 68 — — Bonds (C) Other 29 — 29 — Total $ 97 $ 68 $ 29 $ — Recurring Fair Value Measurements as of December 31, 2014 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) $ 1 $ — $ 1 $ — Common Stocks (B) Commingled-United States 48 48 — — Bonds (C) Other 20 — 20 — Total $ 69 $ 48 $ 21 $ — (A) Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Wherever possible, fair values of equity investments in commingled stock funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily 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 2015 2014 Equity Securities 71 % 70 % Fixed Income Securities 29 29 Other Investments — 1 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% as of December 31, 2015 and will remain unchanged for 2016 . This expected return was determined based on the study discussed above, including a premium for active management. Plan Contributions Servco plans to contribute $28 million into its pension plan during 2016 . 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 2016 $ 1 $ 3 2017 2 5 2018 3 7 2019 4 8 2020 6 10 2021-2025 60 80 Total $ 76 $ 113 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, 2015, 2014 and 2013 were immaterial 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, 2015 | |
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. 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. 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 • all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. 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 face value of outstanding guarantees, current exposure and margin positions as of December 31, 2015 and 2014 are shown below: As of December 31, 2015 As of December 31, 2014 Millions Face Value of Outstanding Guarantees $ 1,734 $ 1,814 Exposure under Current Guarantees $ 172 $ 273 Letters of Credit Margin Posted $ 122 $ 159 Letters of Credit Margin Received $ 192 $ 40 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (15 ) $ (13 ) Net Broker Balance Deposited (Received) $ (5 ) $ 115 In the Event Power were to Lose its Investment Grade Rating Additional Collateral that could be Required $ 864 $ 945 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,215 $ 3,495 Additional Amounts Posted Other Letters of Credit $ 51 $ 45 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 15. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P and Moody’s ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have 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 further 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. This agreement and the work undertaken pursuant to the action agreement will not affect the ultimate remedy that the EPA will select for the remediation of the 17 -mile stretch of the lower Passaic River. 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 . PSEG’s share of the cost of that effort is approximately three percent . The remaining CPG members 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 EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.3 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the lower eight miles of the river bank-to-bank and installing an engineered cap. The estimated cost in the revised draft FFS for the EPA's preferred alternative is $1.7 billion on a discounted basis. No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS. The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period for the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others. The CPG, which consisted of 54 members as of December 31, 2015 , 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 $163 million , which the CPG continues to incur. Of the estimated $163 million , as of December 31, 2015 , the CPG had spent approximately $147 million , of which PSEG's total share was approximately $10 million . The draft FS sets forth various alternatives for remediating the lower Passaic River. The draft FS sets 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 . 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 ranges from approximately $518 million to $772 million . No provisional cost allocation has been made by the CPG for the work contemplated by the draft FS. However, based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's and Power's estimates of their 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. The EPA will consider the comments received on its revised draft FFS and is expected to consider the CPG’s RI/FS prior to issuing a Record of Decision (ROD) of a selected remedy for the lower Passaic River. 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 is finalized, (ii) a final remedy is determined by the EPA or through litigation, (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 our 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 $431 million and $499 million through 2021, including its $10 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 $431 million as of December 31, 2015 . Of this amount, $76 million was recorded in Other Current Liabilities and $355 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $431 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. 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 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit was subject to a public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015. On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule. State permitting decisions could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion , of which Power’s share would have been approximately $575 million . The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. 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 the BH3 within five years of the effective date of the final permit. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in the summer of 2016 indicating a potential retirement date for BH3 by summer 2021, which is four years earlier than the current estimated useful life ending in 2025. If the permit is not issued and the conditions below are not met, Power will seek to operate BH3 through the current estimated useful life. 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, which 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 will seek to operate BH3 through the current estimated useful life. If either the permit renewal is received, or all the conditions precedent in the CEBA occur, a triggering event will be deemed to have occurred and Power will test its New England generating fleet for impairment at that time. The New England generation fleet currently has a net book value of approximately $210 million . In February 2016, the proposed generating facility was awarded a capacity obligation. Construction is expected to commence in 2017, with operations 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. Steam Electric Effluent Guidelines On September 30, 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 Mercer and Bridgeport Harbor stations 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 which 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, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial 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, 2016 is $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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 2013 2014 2015 2016 36-Month Terms Ending May 2016 May 2017 May 2018 May 2019 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $92.18 $97.39 $99.54 $96.38 (A) Prices set in the 2016 BGS auction will become effective on June 1, 2016 when the 2013 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 23. 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 estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom. Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations. Power also has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available, Power can use the gas to supply its fossil generating stations. As of December 31, 2015 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2020 Millions Nuclear Fuel Uranium $ 475 Enrichment $ 394 Fabrication $ 204 Natural Gas $ 1,023 Coal $ 300 Regulatory Proceedings FERC Compliance In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. During the three month period ended March 31, 2014 , based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time. In September 2014, FERC Staff initiated a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has and is continuing to respond to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedi |
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. 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. 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 • all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. 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 face value of outstanding guarantees, current exposure and margin positions as of December 31, 2015 and 2014 are shown below: As of December 31, 2015 As of December 31, 2014 Millions Face Value of Outstanding Guarantees $ 1,734 $ 1,814 Exposure under Current Guarantees $ 172 $ 273 Letters of Credit Margin Posted $ 122 $ 159 Letters of Credit Margin Received $ 192 $ 40 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (15 ) $ (13 ) Net Broker Balance Deposited (Received) $ (5 ) $ 115 In the Event Power were to Lose its Investment Grade Rating Additional Collateral that could be Required $ 864 $ 945 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,215 $ 3,495 Additional Amounts Posted Other Letters of Credit $ 51 $ 45 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 15. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P and Moody’s ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have 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 further 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. This agreement and the work undertaken pursuant to the action agreement will not affect the ultimate remedy that the EPA will select for the remediation of the 17 -mile stretch of the lower Passaic River. 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 . PSEG’s share of the cost of that effort is approximately three percent . The remaining CPG members 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 EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.3 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the lower eight miles of the river bank-to-bank and installing an engineered cap. The estimated cost in the revised draft FFS for the EPA's preferred alternative is $1.7 billion on a discounted basis. No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS. The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period for the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others. The CPG, which consisted of 54 members as of December 31, 2015 , 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 $163 million , which the CPG continues to incur. Of the estimated $163 million , as of December 31, 2015 , the CPG had spent approximately $147 million , of which PSEG's total share was approximately $10 million . The draft FS sets forth various alternatives for remediating the lower Passaic River. The draft FS sets 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 . 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 ranges from approximately $518 million to $772 million . No provisional cost allocation has been made by the CPG for the work contemplated by the draft FS. However, based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's and Power's estimates of their 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. The EPA will consider the comments received on its revised draft FFS and is expected to consider the CPG’s RI/FS prior to issuing a Record of Decision (ROD) of a selected remedy for the lower Passaic River. 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 is finalized, (ii) a final remedy is determined by the EPA or through litigation, (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 our 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 $431 million and $499 million through 2021, including its $10 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 $431 million as of December 31, 2015 . Of this amount, $76 million was recorded in Other Current Liabilities and $355 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $431 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. 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 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit was subject to a public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015. On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule. State permitting decisions could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion , of which Power’s share would have been approximately $575 million . The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. 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 the BH3 within five years of the effective date of the final permit. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in the summer of 2016 indicating a potential retirement date for BH3 by summer 2021, which is four years earlier than the current estimated useful life ending in 2025. If the permit is not issued and the conditions below are not met, Power will seek to operate BH3 through the current estimated useful life. 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, which 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 will seek to operate BH3 through the current estimated useful life. If either the permit renewal is received, or all the conditions precedent in the CEBA occur, a triggering event will be deemed to have occurred and Power will test its New England generating fleet for impairment at that time. The New England generation fleet currently has a net book value of approximately $210 million . In February 2016, the proposed generating facility was awarded a capacity obligation. Construction is expected to commence in 2017, with operations 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. Steam Electric Effluent Guidelines On September 30, 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 Mercer and Bridgeport Harbor stations 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 which 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, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial 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, 2016 is $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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 2013 2014 2015 2016 36-Month Terms Ending May 2016 May 2017 May 2018 May 2019 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $92.18 $97.39 $99.54 $96.38 (A) Prices set in the 2016 BGS auction will become effective on June 1, 2016 when the 2013 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 23. 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 estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom. Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations. Power also has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available, Power can use the gas to supply its fossil generating stations. As of December 31, 2015 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2020 Millions Nuclear Fuel Uranium $ 475 Enrichment $ 394 Fabrication $ 204 Natural Gas $ 1,023 Coal $ 300 Regulatory Proceedings FERC Compliance In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. During the three month period ended March 31, 2014 , based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time. In September 2014, FERC Staff initiated a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has and is continuing to respond to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedi |
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. 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. 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 • all 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. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted. Power is subject to • counterparty collateral calls related to commodity contracts, and • certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. 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 face value of outstanding guarantees, current exposure and margin positions as of December 31, 2015 and 2014 are shown below: As of December 31, 2015 As of December 31, 2014 Millions Face Value of Outstanding Guarantees $ 1,734 $ 1,814 Exposure under Current Guarantees $ 172 $ 273 Letters of Credit Margin Posted $ 122 $ 159 Letters of Credit Margin Received $ 192 $ 40 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (15 ) $ (13 ) Net Broker Balance Deposited (Received) $ (5 ) $ 115 In the Event Power were to Lose its Investment Grade Rating Additional Collateral that could be Required $ 864 $ 945 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,215 $ 3,495 Additional Amounts Posted Other Letters of Credit $ 51 $ 45 As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 15. 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 the event of a deterioration of Power’s credit rating to below investment grade, which would represent a three level downgrade from its current S&P and Moody’s ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above. In addition to amounts for outstanding guarantees, current exposure and margin positions, PSEG and Power have 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 further 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. This agreement and the work undertaken pursuant to the action agreement will not affect the ultimate remedy that the EPA will select for the remediation of the 17 -mile stretch of the lower Passaic River. 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 . PSEG’s share of the cost of that effort is approximately three percent . The remaining CPG members 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 EPA’s estimated costs to remediate the lower eight miles of the Passaic River range from $365 million for a targeted remedy to $3.3 billion for a deep dredge of this portion of the Passaic River. The EPA also identified in the revised draft FFS its preferred alternative, which would involve dredging the lower eight miles of the river bank-to-bank and installing an engineered cap. The estimated cost in the revised draft FFS for the EPA's preferred alternative is $1.7 billion on a discounted basis. No provisional cost allocation has been made by the CPG for the work contemplated by the revised draft FFS, and the work contemplated by the revised draft FFS is not subject to the CPG’s cost sharing allocation agreed to in connection with the removal work for River Mile 10.9 or in connection with the conduct of the RI/FS. The revised draft FFS was subject to a public comment period, and remains subject to the EPA’s response to comments submitted, a design phase and at least an estimated five years for completion of the work. The public comment period for the revised draft FFS closed on August 21, 2014. Over 300 comments were submitted by a variety of entities potentially impacted by the revised draft FFS, including the CPG, individual companies, municipalities, public officials, citizens groups, Amtrak, NJ Transit and others. The CPG, which consisted of 54 members as of December 31, 2015 , 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 $163 million , which the CPG continues to incur. Of the estimated $163 million , as of December 31, 2015 , the CPG had spent approximately $147 million , of which PSEG's total share was approximately $10 million . The draft FS sets forth various alternatives for remediating the lower Passaic River. The draft FS sets 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 . 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 ranges from approximately $518 million to $772 million . No provisional cost allocation has been made by the CPG for the work contemplated by the draft FS. However, based on (i) the low end of the range of the current estimates of costs to remediate, (ii) PSE&G's and Power's estimates of their 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. The EPA will consider the comments received on its revised draft FFS and is expected to consider the CPG’s RI/FS prior to issuing a Record of Decision (ROD) of a selected remedy for the lower Passaic River. 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 is finalized, (ii) a final remedy is determined by the EPA or through litigation, (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 our 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 $431 million and $499 million through 2021, including its $10 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 $431 million as of December 31, 2015 . Of this amount, $76 million was recorded in Other Current Liabilities and $355 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $431 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. 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 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. On June 30, 2015, the NJDEP issued a draft permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system with certain required system modifications. The draft permit was subject to a public notice and comment period. The NJDEP may make revisions before issuing the final permit expected during the first half of 2016. Power participated in the NJDEP’s August 5, 2015 public hearing and submitted comments on the draft permit on September 18, 2015. On May 19, 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. On August 15, 2014, the EPA established October 14, 2014 as the effective date for each state to implement the provisions of the rule going forward when considering the renewal of permits for existing facilities on a case by case basis. On September 5, 2014, several environmental non-governmental groups and certain energy industry groups filed motions to litigate the provisions of the rule. This case is pending at the U.S. Second Circuit Court of Appeals. In two related actions on October 17, 2014 and November 20, 2014, several environmental non-governmental groups initiated challenges to the endangered species act provisions of the 316 (b) rule. Power is unable to determine the ultimate impact of these actions on the implementation of the rule. State permitting decisions could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities, and could result in acceleration of decommissioning activities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion , of which Power’s share would have been approximately $575 million . The filing has not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. 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 the BH3 within five years of the effective date of the final permit. Based on current discussions with the CTDEEP, if the proposal is accepted, a final permit could be issued in the summer of 2016 indicating a potential retirement date for BH3 by summer 2021, which is four years earlier than the current estimated useful life ending in 2025. If the permit is not issued and the conditions below are not met, Power will seek to operate BH3 through the current estimated useful life. 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, which 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 will seek to operate BH3 through the current estimated useful life. If either the permit renewal is received, or all the conditions precedent in the CEBA occur, a triggering event will be deemed to have occurred and Power will test its New England generating fleet for impairment at that time. The New England generation fleet currently has a net book value of approximately $210 million . In February 2016, the proposed generating facility was awarded a capacity obligation. Construction is expected to commence in 2017, with operations 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. Steam Electric Effluent Guidelines On September 30, 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 Mercer and Bridgeport Harbor stations 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 which 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, are residential and smaller commercial and industrial customers (BGS-Residential Small Commercial Pricing (RSCP)). The second category are larger customers that exceed a BPU-established load (kW) threshold (BGS-Commercial and Industrial 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, 2016 is $335.33 per MW-day, replacing the BGS-CIEP auction year price ending May 31, 2016 of $272.78 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 2013 2014 2015 2016 36-Month Terms Ending May 2016 May 2017 May 2018 May 2019 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $92.18 $97.39 $99.54 $96.38 (A) Prices set in the 2016 BGS auction will become effective on June 1, 2016 when the 2013 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 23. 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 estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2017 and a significant portion through 2020 at Salem, Hope Creek and Peach Bottom. Power has various long-term fuel purchase commitments for coal through 2018 to support its fossil generation stations. Power also has various multi-year contracts for natural gas and firm transportation and storage capacity for natural gas that are primarily used to meet its obligations to PSE&G. When there is excess delivery capacity available, Power can use the gas to supply its fossil generating stations. As of December 31, 2015 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2020 Millions Nuclear Fuel Uranium $ 475 Enrichment $ 394 Fabrication $ 204 Natural Gas $ 1,023 Coal $ 300 Regulatory Proceedings FERC Compliance In the first quarter of 2014, Power discovered that it incorrectly calculated certain components of its cost-based bids for its New Jersey fossil generating units in the PJM energy market. Upon discovery of the errors, PSEG retained outside counsel to assist in the conduct of an investigation into the matter and self-reported the errors. As the internal investigation proceeded, additional pricing errors in the bids were identified. It was further determined that the quantity of energy that Power offered into the energy market for its fossil peaking units differed from the amount for which Power was compensated in the capacity market for those units. PSEG informed FERC, PJM and the PJM Independent Market Monitor (IMM) of these additional issues, corrected the identified errors, and modified the bid quantities for Power’s peaking units. Power continues to implement procedures to help mitigate the risk of similar issues occurring in the future. During the three month period ended March 31, 2014 , based upon its best estimate available at the time, Power recorded a charge to income in the amount of $25 million related to this matter. No additional charges to income have been recorded for this matter since that time. In September 2014, FERC Staff initiated a preliminary, non-public staff investigation into the matter and issued data requests covering a period from 2002 through the date of the self-report. This investigation is ongoing. Since that time, Power has and is continuing to respond to data requests from FERC Staff, including recent data requests in which Power has recalculated certain of its energy bids in PJM for a five year period, and may receive additional data requests or other fact finding. The FERC Staff investigation is still in the fact finding stage and there is considerable uncertainty around FERC's response to PSEG's legal arguments and the amount of disgorgement or other remedi |
Schedule Of Consolidated Debt
Schedule Of Consolidated Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Instrument [Line Items] | |
Schedule Of Consolidated Debt | Schedule of Consolidated Debt Long-Term Debt As of December 31, Maturity 2015 2014 Millions PSEG (Parent) Term Loan: Variable 2017 $ 500 $ — Total Term Loan 500 — Fair Value of Swaps (A) 6 22 Amounts Due Within One Year (6 ) (8 ) Unamortized Discount Related to Debt Exchange (B) — (8 ) Total Long-Term Debt of PSEG (Parent) $ 500 $ 6 ` As of December 31, Maturity 2015 2014 Millions PSE&G First and Refunding Mortgage Bonds (C): 6.75% 2016 $ 171 $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 320 320 Pollution Control Bonds (C): Floating Rate (D) 2033 50 50 Floating Rate (D) 2046 50 50 Total Pollution Control Bonds 100 100 Medium-Term Notes (MTNs) (C): 2.70% 2015 — 300 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 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 — 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 — 4.15% 2045 250 — Total MTNs 6,459 5,909 Principal Amount Outstanding 6,879 6,329 Amounts Due Within One Year (171 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (58 ) (54 ) Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II) $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Transition Funding (PSE&G) Securitization Bonds: 6.89% 2014-2015 $ — $ 251 Principal Amount Outstanding — 251 Amounts Due Within One Year — (251 ) Total Securitization Debt of Transition Funding — — Transition Funding II (PSE&G) Securitization Bonds: 4.57% 2014-2015 — 8 Principal Amount Outstanding — 8 Amounts Due Within One Year — (8 ) Total Securitization Debt of Transition Funding II — — Total Long-Term Debt of PSE&G $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Power Senior Notes: 5.50% 2015 $ — $ 300 5.32% 2016 303 303 2.75% 2016 250 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,209 2,509 Pollution Control Notes: Floating Rate (D) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,253 2,553 Amounts Due Within One Year (553 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (16 ) (19 ) Total Long-Term Debt of Power $ 1,684 $ 2,234 (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 15. Financial Risk Management Activities . (B) In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The remaining deferred amount of $3 million as of December 31, 2015 is reflected as an offset to Long-Term Debt due within one year on PSEG’s Consolidated Balance Sheets. (C) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (D) The Pollution Control Financing Authority of Salem County bonds 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, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing the PEDFA bond which expires on November 30, 2019. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2015 are as follows: Energy Holdings Year PSEG (Parent) PSE&G Power Non-Recourse Debt Total Millions 2016 $ — $ 171 $ 553 $ 7 $ 731 2017 500 — — — 500 2018 — 750 250 — 1,000 2019 — 500 44 — 544 2020 — 259 406 — 665 Thereafter — 5,199 1,000 — 6,199 Total $ 500 $ 6,879 $ 2,253 $ 7 $ 9,639 Long-Term Debt Financing Transactions During 2015 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG (Parent) • entered into an agreement for a new term loan maturing November 2017. The term loan has a balance of $500 million at an interest rate of 1 month LIBOR + 0.875% and can be terminated at any time without penalty. PSE&G • issued $350 million of 3.00% Secured Medium-Term Notes, Series K due May 2025 , • issued $250 million of 4.05% Secured Medium-Term Notes, Series K due May 2045 , • issued $250 million of 4.15% Secured Medium-Term Notes, Series K due November 2045 , • paid $300 million of 2.70% Secured Medium-Term Notes at maturity, • paid $251 million of Transition Funding's securitization debt, and • paid $8 million of Transition Funding II's securitization debt. Power • paid $300 million of 5.50% Senior Notes at maturity. PSE&G PSE&G had $171 million of 6.75% Mortgage Bonds mature in January 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 our $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2015 , our total available credit capacity was $3.6 billion . As of December 31, 2015 , no single institution represented more than 7% of the total commitments in our credit facilities. As of December 31, 2015 , our total credit capacity was in excess of our anticipated maximum liquidity requirements. Each of our 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. Our total credit facilities and available liquidity as of December 31, 2015 were as follows: As of December 31, 2015 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 211 289 Apr 2020 CP Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 221 $ 779 PSE&G 5-year Credit Facility (B) $ 600 $ 167 $ 433 Apr 2020 CP Support/Funding/Letters of Credit Total PSE&G $ 600 $ 167 $ 433 Power 5-year Credit Facility $ 1,600 $ 161 $ 1,439 Apr 2019 Funding/Letters of Credit 5-year Credit Facility (C) 1,000 3 997 Apr 2020 Funding/Letters of Credit Total Power $ 2,600 $ 164 $ 2,436 Total $ 4,200 $ 552 $ 3,648 (A) PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018. (B) PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018. (C) Power facility will be reduced by $48 million in April 2016 and $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, 2015 , $211 million and $153 million , respectively, were outstanding. The weighted average interest rates on PSEG's and PSE&G's Commercial Paper Programs were 0.96% and 0.91% , respectively, at December 31, 2015 . 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, 2015 and 2014 are included in the following table and accompanying notes as of December 31, 2015 and 2014 . See Note 16. 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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (Parent) (A) $ 503 $ 506 $ 14 $ 22 PSE&G (B) 6,821 7,235 6,275 6,912 Transition Funding (PSE&G) (B) — — 251 261 Transition Funding II (PSE&G) (B) — — 8 8 Power - Recourse Debt (B) 2,237 2,508 2,534 2,930 Energy Holdings: Project Level, Non-Recourse Debt (C) 7 7 16 16 $ 9,568 $ 10,256 $ 9,098 $ 10,149 (A) Fair value includes a $500 million floating rate term loan in 2015 and net offsets in 2015 and 2014 to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. 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. 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 is 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 | Schedule of Consolidated Debt Long-Term Debt As of December 31, Maturity 2015 2014 Millions PSEG (Parent) Term Loan: Variable 2017 $ 500 $ — Total Term Loan 500 — Fair Value of Swaps (A) 6 22 Amounts Due Within One Year (6 ) (8 ) Unamortized Discount Related to Debt Exchange (B) — (8 ) Total Long-Term Debt of PSEG (Parent) $ 500 $ 6 ` As of December 31, Maturity 2015 2014 Millions PSE&G First and Refunding Mortgage Bonds (C): 6.75% 2016 $ 171 $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 320 320 Pollution Control Bonds (C): Floating Rate (D) 2033 50 50 Floating Rate (D) 2046 50 50 Total Pollution Control Bonds 100 100 Medium-Term Notes (MTNs) (C): 2.70% 2015 — 300 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 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 — 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 — 4.15% 2045 250 — Total MTNs 6,459 5,909 Principal Amount Outstanding 6,879 6,329 Amounts Due Within One Year (171 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (58 ) (54 ) Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II) $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Transition Funding (PSE&G) Securitization Bonds: 6.89% 2014-2015 $ — $ 251 Principal Amount Outstanding — 251 Amounts Due Within One Year — (251 ) Total Securitization Debt of Transition Funding — — Transition Funding II (PSE&G) Securitization Bonds: 4.57% 2014-2015 — 8 Principal Amount Outstanding — 8 Amounts Due Within One Year — (8 ) Total Securitization Debt of Transition Funding II — — Total Long-Term Debt of PSE&G $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Power Senior Notes: 5.50% 2015 $ — $ 300 5.32% 2016 303 303 2.75% 2016 250 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,209 2,509 Pollution Control Notes: Floating Rate (D) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,253 2,553 Amounts Due Within One Year (553 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (16 ) (19 ) Total Long-Term Debt of Power $ 1,684 $ 2,234 (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 15. Financial Risk Management Activities . (B) In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The remaining deferred amount of $3 million as of December 31, 2015 is reflected as an offset to Long-Term Debt due within one year on PSEG’s Consolidated Balance Sheets. (C) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (D) The Pollution Control Financing Authority of Salem County bonds 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, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing the PEDFA bond which expires on November 30, 2019. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2015 are as follows: Energy Holdings Year PSEG (Parent) PSE&G Power Non-Recourse Debt Total Millions 2016 $ — $ 171 $ 553 $ 7 $ 731 2017 500 — — — 500 2018 — 750 250 — 1,000 2019 — 500 44 — 544 2020 — 259 406 — 665 Thereafter — 5,199 1,000 — 6,199 Total $ 500 $ 6,879 $ 2,253 $ 7 $ 9,639 Long-Term Debt Financing Transactions During 2015 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG (Parent) • entered into an agreement for a new term loan maturing November 2017. The term loan has a balance of $500 million at an interest rate of 1 month LIBOR + 0.875% and can be terminated at any time without penalty. PSE&G • issued $350 million of 3.00% Secured Medium-Term Notes, Series K due May 2025 , • issued $250 million of 4.05% Secured Medium-Term Notes, Series K due May 2045 , • issued $250 million of 4.15% Secured Medium-Term Notes, Series K due November 2045 , • paid $300 million of 2.70% Secured Medium-Term Notes at maturity, • paid $251 million of Transition Funding's securitization debt, and • paid $8 million of Transition Funding II's securitization debt. Power • paid $300 million of 5.50% Senior Notes at maturity. PSE&G PSE&G had $171 million of 6.75% Mortgage Bonds mature in January 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 our $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2015 , our total available credit capacity was $3.6 billion . As of December 31, 2015 , no single institution represented more than 7% of the total commitments in our credit facilities. As of December 31, 2015 , our total credit capacity was in excess of our anticipated maximum liquidity requirements. Each of our 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. Our total credit facilities and available liquidity as of December 31, 2015 were as follows: As of December 31, 2015 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 211 289 Apr 2020 CP Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 221 $ 779 PSE&G 5-year Credit Facility (B) $ 600 $ 167 $ 433 Apr 2020 CP Support/Funding/Letters of Credit Total PSE&G $ 600 $ 167 $ 433 Power 5-year Credit Facility $ 1,600 $ 161 $ 1,439 Apr 2019 Funding/Letters of Credit 5-year Credit Facility (C) 1,000 3 997 Apr 2020 Funding/Letters of Credit Total Power $ 2,600 $ 164 $ 2,436 Total $ 4,200 $ 552 $ 3,648 (A) PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018. (B) PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018. (C) Power facility will be reduced by $48 million in April 2016 and $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, 2015 , $211 million and $153 million , respectively, were outstanding. The weighted average interest rates on PSEG's and PSE&G's Commercial Paper Programs were 0.96% and 0.91% , respectively, at December 31, 2015 . 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, 2015 and 2014 are included in the following table and accompanying notes as of December 31, 2015 and 2014 . See Note 16. 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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (Parent) (A) $ 503 $ 506 $ 14 $ 22 PSE&G (B) 6,821 7,235 6,275 6,912 Transition Funding (PSE&G) (B) — — 251 261 Transition Funding II (PSE&G) (B) — — 8 8 Power - Recourse Debt (B) 2,237 2,508 2,534 2,930 Energy Holdings: Project Level, Non-Recourse Debt (C) 7 7 16 16 $ 9,568 $ 10,256 $ 9,098 $ 10,149 (A) Fair value includes a $500 million floating rate term loan in 2015 and net offsets in 2015 and 2014 to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. 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. 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 is 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 | Schedule of Consolidated Debt Long-Term Debt As of December 31, Maturity 2015 2014 Millions PSEG (Parent) Term Loan: Variable 2017 $ 500 $ — Total Term Loan 500 — Fair Value of Swaps (A) 6 22 Amounts Due Within One Year (6 ) (8 ) Unamortized Discount Related to Debt Exchange (B) — (8 ) Total Long-Term Debt of PSEG (Parent) $ 500 $ 6 ` As of December 31, Maturity 2015 2014 Millions PSE&G First and Refunding Mortgage Bonds (C): 6.75% 2016 $ 171 $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 320 320 Pollution Control Bonds (C): Floating Rate (D) 2033 50 50 Floating Rate (D) 2046 50 50 Total Pollution Control Bonds 100 100 Medium-Term Notes (MTNs) (C): 2.70% 2015 — 300 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 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 — 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 — 4.15% 2045 250 — Total MTNs 6,459 5,909 Principal Amount Outstanding 6,879 6,329 Amounts Due Within One Year (171 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (58 ) (54 ) Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II) $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Transition Funding (PSE&G) Securitization Bonds: 6.89% 2014-2015 $ — $ 251 Principal Amount Outstanding — 251 Amounts Due Within One Year — (251 ) Total Securitization Debt of Transition Funding — — Transition Funding II (PSE&G) Securitization Bonds: 4.57% 2014-2015 — 8 Principal Amount Outstanding — 8 Amounts Due Within One Year — (8 ) Total Securitization Debt of Transition Funding II — — Total Long-Term Debt of PSE&G $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Power Senior Notes: 5.50% 2015 $ — $ 300 5.32% 2016 303 303 2.75% 2016 250 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,209 2,509 Pollution Control Notes: Floating Rate (D) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,253 2,553 Amounts Due Within One Year (553 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (16 ) (19 ) Total Long-Term Debt of Power $ 1,684 $ 2,234 (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 15. Financial Risk Management Activities . (B) In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The remaining deferred amount of $3 million as of December 31, 2015 is reflected as an offset to Long-Term Debt due within one year on PSEG’s Consolidated Balance Sheets. (C) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (D) The Pollution Control Financing Authority of Salem County bonds 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, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing the PEDFA bond which expires on November 30, 2019. Long-Term Debt Maturities The aggregate principal amounts of maturities for each of the five years following December 31, 2015 are as follows: Energy Holdings Year PSEG (Parent) PSE&G Power Non-Recourse Debt Total Millions 2016 $ — $ 171 $ 553 $ 7 $ 731 2017 500 — — — 500 2018 — 750 250 — 1,000 2019 — 500 44 — 544 2020 — 259 406 — 665 Thereafter — 5,199 1,000 — 6,199 Total $ 500 $ 6,879 $ 2,253 $ 7 $ 9,639 Long-Term Debt Financing Transactions During 2015 , PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions: PSEG (Parent) • entered into an agreement for a new term loan maturing November 2017. The term loan has a balance of $500 million at an interest rate of 1 month LIBOR + 0.875% and can be terminated at any time without penalty. PSE&G • issued $350 million of 3.00% Secured Medium-Term Notes, Series K due May 2025 , • issued $250 million of 4.05% Secured Medium-Term Notes, Series K due May 2045 , • issued $250 million of 4.15% Secured Medium-Term Notes, Series K due November 2045 , • paid $300 million of 2.70% Secured Medium-Term Notes at maturity, • paid $251 million of Transition Funding's securitization debt, and • paid $8 million of Transition Funding II's securitization debt. Power • paid $300 million of 5.50% Senior Notes at maturity. PSE&G PSE&G had $171 million of 6.75% Mortgage Bonds mature in January 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 our $4.2 billion credit facilities are provided by a diverse bank group. As of December 31, 2015 , our total available credit capacity was $3.6 billion . As of December 31, 2015 , no single institution represented more than 7% of the total commitments in our credit facilities. As of December 31, 2015 , our total credit capacity was in excess of our anticipated maximum liquidity requirements. Each of our 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. Our total credit facilities and available liquidity as of December 31, 2015 were as follows: As of December 31, 2015 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 211 289 Apr 2020 CP Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 221 $ 779 PSE&G 5-year Credit Facility (B) $ 600 $ 167 $ 433 Apr 2020 CP Support/Funding/Letters of Credit Total PSE&G $ 600 $ 167 $ 433 Power 5-year Credit Facility $ 1,600 $ 161 $ 1,439 Apr 2019 Funding/Letters of Credit 5-year Credit Facility (C) 1,000 3 997 Apr 2020 Funding/Letters of Credit Total Power $ 2,600 $ 164 $ 2,436 Total $ 4,200 $ 552 $ 3,648 (A) PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018. (B) PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018. (C) Power facility will be reduced by $48 million in April 2016 and $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, 2015 , $211 million and $153 million , respectively, were outstanding. The weighted average interest rates on PSEG's and PSE&G's Commercial Paper Programs were 0.96% and 0.91% , respectively, at December 31, 2015 . 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, 2015 and 2014 are included in the following table and accompanying notes as of December 31, 2015 and 2014 . See Note 16. 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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (Parent) (A) $ 503 $ 506 $ 14 $ 22 PSE&G (B) 6,821 7,235 6,275 6,912 Transition Funding (PSE&G) (B) — — 251 261 Transition Funding II (PSE&G) (B) — — 8 8 Power - Recourse Debt (B) 2,237 2,508 2,534 2,930 Energy Holdings: Project Level, Non-Recourse Debt (C) 7 7 16 16 $ 9,568 $ 10,256 $ 9,098 $ 10,149 (A) Fair value includes a $500 million floating rate term loan in 2015 and net offsets in 2015 and 2014 to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. 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. 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 is 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, 2015 | |
Class of Stock [Line Items] | |
Schedule of Consolidated Capital Stock | Schedule of Consolidated Capital Stock As of December 31, Outstanding Shares Book Value 2015 2014 2015 2014 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 505,282,421 505,836,592 $ 4,244 $ 4,241 (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 2015 or 2014 . 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, 2015 . As of December 31, 2015 , 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 2015 2014 2015 2014 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 505,282,421 505,836,592 $ 4,244 $ 4,241 (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 2015 or 2014 . 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, 2015 . As of December 31, 2015 , 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 2015 2014 2015 2014 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 505,282,421 505,836,592 $ 4,244 $ 4,241 (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 2015 or 2014 . 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, 2015 . As of December 31, 2015 , 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, 2015 | |
Derivative [Line Items] | |
Financial Risk Management Activities | Financial Risk Management Activities The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments. 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 normal purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but do not qualify for or 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 to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. Cash Flow Hedges PSEG and Power use forward sale contracts, swaps and futures contracts to hedge certain forecasted natural gas sales made to support the BGSS contract with PSE&G. Historically, these derivative transactions qualified and were designated as cash flow hedges. PSEG and Power had no contracts designated as cash flow hedges as of December 31, 2015 . As of December 31, 2015 and 2014 , the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows: As of December 31, 2015 2014 Millions Fair Value of Cash Flow Hedges $ — $ 18 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ — $ 10 Economic Hedges Power enters into derivative contracts that do not qualify or are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract to optimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities. 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. As of December 31, 2015 , PSEG had interest rate swaps outstanding totaling $550 million . These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of December 31, 2015 and 2014 , the fair value of all the underlying hedges was $6 million and $22 million , 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. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2015 and 2014 . 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 our accounting policy, these positions have been offset on the Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts 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 As of December 31, 2014 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 18 $ 597 $ (408 ) $ 207 $ 18 $ 15 $ 240 Noncurrent Assets — 171 (109 ) 62 8 7 77 Total Mark-to-Market Derivative Assets $ 18 $ 768 $ (517 ) $ 269 $ 26 $ 22 $ 317 Derivative Contracts Current Liabilities $ — $ (568 ) $ 436 $ (132 ) $ — $ — $ (132 ) Noncurrent Liabilities — (138 ) 105 (33 ) — — (33 ) Total Mark-to-Market Derivative (Liabilities) $ — $ (706 ) $ 541 $ (165 ) $ — $ — $ (165 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 18 $ 62 $ 24 $ 104 $ 26 $ 22 $ 152 (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, 2015 and 2014 . 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 in the Consolidated Balance Sheets. As of December 31, 2015 and 2014 , net cash collateral (received) paid of $(55) million and $24 million , respectively, were netted against the corresponding net derivative contract positions. Of the $(55) million as of December 31, 2015 , $(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. Of the $24 million as of December 31, 2014 , cash collateral of $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 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, it would be required to provide additional collateral. 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 $78 million and $127 million as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 and 2014 , Power had the contractual right of offset of $12 million and $18 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 $66 million and $109 million as of December 31, 2015 and 2014 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $864 million and $945 million as of December 31, 2015 and 2014 , respectively, discussed in Note 12. Commitments and Contingent Liabilities . 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, 2015 , 2014 and 2013 : 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) Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, Years Ended December 31, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Millions Millions PSEG Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Interest Rate Swaps (A) — — — Interest Expense — — (1 ) — — — Total PSEG $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 12 $ — $ — $ (1 ) Power Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Total Power $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) (A) Includes amounts for PSEG parent. 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, 2013 $ (4 ) $ (2 ) Gain Recognized in AOCI 12 7 Plus: Loss Reclassified into Income 9 5 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 $ — $ — The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the years ended December 31, 2015 , 2014 and 2013 : 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, 2015 2014 2013 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 412 $ (348 ) $ (128 ) Energy-Related Contracts Energy Costs (8 ) 32 106 Total PSEG and Power $ 404 $ (316 ) $ (22 ) 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 elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $19 million , $20 million and $19 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2015 and 2014 : Type Notional Total PSEG Power PSE&G Millions As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — Financial Transmission Rights (FTRs) MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — As of December 31, 2014 Natural Gas Dth 274 — 216 58 Electricity MWh 310 — 310 — FTRs MWh 15 — 15 — Interest Rate Swaps U.S. Dollars 850 850 — — Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2015 , 92% of the credit 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 and non-derivatives and normal purchases/normal sales). The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2015 . It further delineates that exposure by the credit rating of the counterparties and 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—External Rating $ 451 $ 175 $ 276 1 $ 160 (A) Non-Investment Grade—External Rating 24 — 24 — — Investment Grade—No External Rating 12 1 11 — — Non-Investment Grade—No External Rating 1 — 1 — — Total $ 488 $ 176 $ 312 1 $ 160 (A) Represents net exposure with PSE&G. As of December 31, 2015 , collateral held from counterparties where Power had credit exposure included $14 million in cash collateral and $162 million in letters of credit. As of December 31, 2015 , Power had 133 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, 2015 , 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 suppliers’ credit exposure is calculated each business day. As of December 31, 2015 , 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 The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments. 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 normal purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but do not qualify for or 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 to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. Cash Flow Hedges PSEG and Power use forward sale contracts, swaps and futures contracts to hedge certain forecasted natural gas sales made to support the BGSS contract with PSE&G. Historically, these derivative transactions qualified and were designated as cash flow hedges. PSEG and Power had no contracts designated as cash flow hedges as of December 31, 2015 . As of December 31, 2015 and 2014 , the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows: As of December 31, 2015 2014 Millions Fair Value of Cash Flow Hedges $ — $ 18 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ — $ 10 Economic Hedges Power enters into derivative contracts that do not qualify or are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract to optimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities. 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. As of December 31, 2015 , PSEG had interest rate swaps outstanding totaling $550 million . These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of December 31, 2015 and 2014 , the fair value of all the underlying hedges was $6 million and $22 million , 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. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2015 and 2014 . 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 our accounting policy, these positions have been offset on the Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts 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 As of December 31, 2014 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 18 $ 597 $ (408 ) $ 207 $ 18 $ 15 $ 240 Noncurrent Assets — 171 (109 ) 62 8 7 77 Total Mark-to-Market Derivative Assets $ 18 $ 768 $ (517 ) $ 269 $ 26 $ 22 $ 317 Derivative Contracts Current Liabilities $ — $ (568 ) $ 436 $ (132 ) $ — $ — $ (132 ) Noncurrent Liabilities — (138 ) 105 (33 ) — — (33 ) Total Mark-to-Market Derivative (Liabilities) $ — $ (706 ) $ 541 $ (165 ) $ — $ — $ (165 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 18 $ 62 $ 24 $ 104 $ 26 $ 22 $ 152 (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, 2015 and 2014 . 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 in the Consolidated Balance Sheets. As of December 31, 2015 and 2014 , net cash collateral (received) paid of $(55) million and $24 million , respectively, were netted against the corresponding net derivative contract positions. Of the $(55) million as of December 31, 2015 , $(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. Of the $24 million as of December 31, 2014 , cash collateral of $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 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, it would be required to provide additional collateral. 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 $78 million and $127 million as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 and 2014 , Power had the contractual right of offset of $12 million and $18 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 $66 million and $109 million as of December 31, 2015 and 2014 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $864 million and $945 million as of December 31, 2015 and 2014 , respectively, discussed in Note 12. Commitments and Contingent Liabilities . 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, 2015 , 2014 and 2013 : 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) Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, Years Ended December 31, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Millions Millions PSEG Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Interest Rate Swaps (A) — — — Interest Expense — — (1 ) — — — Total PSEG $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 12 $ — $ — $ (1 ) Power Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Total Power $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) (A) Includes amounts for PSEG parent. 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, 2013 $ (4 ) $ (2 ) Gain Recognized in AOCI 12 7 Plus: Loss Reclassified into Income 9 5 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 $ — $ — The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the years ended December 31, 2015 , 2014 and 2013 : 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, 2015 2014 2013 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 412 $ (348 ) $ (128 ) Energy-Related Contracts Energy Costs (8 ) 32 106 Total PSEG and Power $ 404 $ (316 ) $ (22 ) 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 elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $19 million , $20 million and $19 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2015 and 2014 : Type Notional Total PSEG Power PSE&G Millions As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — Financial Transmission Rights (FTRs) MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — As of December 31, 2014 Natural Gas Dth 274 — 216 58 Electricity MWh 310 — 310 — FTRs MWh 15 — 15 — Interest Rate Swaps U.S. Dollars 850 850 — — Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2015 , 92% of the credit 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 and non-derivatives and normal purchases/normal sales). The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2015 . It further delineates that exposure by the credit rating of the counterparties and 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—External Rating $ 451 $ 175 $ 276 1 $ 160 (A) Non-Investment Grade—External Rating 24 — 24 — — Investment Grade—No External Rating 12 1 11 — — Non-Investment Grade—No External Rating 1 — 1 — — Total $ 488 $ 176 $ 312 1 $ 160 (A) Represents net exposure with PSE&G. As of December 31, 2015 , collateral held from counterparties where Power had credit exposure included $14 million in cash collateral and $162 million in letters of credit. As of December 31, 2015 , Power had 133 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, 2015 , 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 suppliers’ credit exposure is calculated each business day. As of December 31, 2015 , 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 The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments. 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 normal purchase normal sale (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. Transactions receiving NPNS treatment are accounted for upon settlement. For a derivative instrument that qualifies and is designated as a cash flow hedge, the changes in the fair value of such a derivative that are highly effective are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. For a derivative instrument that qualifies and is designated as a fair value hedge, the gains or losses on the derivative as well as the offsetting losses or gains on the hedged item attributable to the hedged risk are recognized in earnings each period. Power and PSE&G enter into additional contracts that are derivatives, but do not qualify for or 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 to manage the commodity price risk of its electric generation facilities, including physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. Cash Flow Hedges PSEG and Power use forward sale contracts, swaps and futures contracts to hedge certain forecasted natural gas sales made to support the BGSS contract with PSE&G. Historically, these derivative transactions qualified and were designated as cash flow hedges. PSEG and Power had no contracts designated as cash flow hedges as of December 31, 2015 . As of December 31, 2015 and 2014 , the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows: As of December 31, 2015 2014 Millions Fair Value of Cash Flow Hedges $ — $ 18 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ — $ 10 Economic Hedges Power enters into derivative contracts that do not qualify or are not designated as either cash flow or fair value hedges. Power enters into financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. These transactions are economic hedges, intended to mitigate exposure to fluctuations in commodity prices and optimize the value of Power's expected generation. Changes in the fair market value of these contracts are recorded in earnings. PSE&G is a party to a long-term natural gas sales derivative contract to optimize its pipeline capacity utilization. Changes in the fair market value of the contract are recorded in Regulatory Assets and Regulatory Liabilities. 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. As of December 31, 2015 , PSEG had interest rate swaps outstanding totaling $550 million . These swaps convert $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of December 31, 2015 and 2014 , the fair value of all the underlying hedges was $6 million and $22 million , 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. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was immaterial as of December 31, 2015 and 2014 . 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 our accounting policy, these positions have been offset on the Consolidated Balance Sheets of Power, PSE&G and PSEG. The following tabular disclosure does not include the offsetting of trade receivables and payables. As of December 31, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts 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 As of December 31, 2014 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 18 $ 597 $ (408 ) $ 207 $ 18 $ 15 $ 240 Noncurrent Assets — 171 (109 ) 62 8 7 77 Total Mark-to-Market Derivative Assets $ 18 $ 768 $ (517 ) $ 269 $ 26 $ 22 $ 317 Derivative Contracts Current Liabilities $ — $ (568 ) $ 436 $ (132 ) $ — $ — $ (132 ) Noncurrent Liabilities — (138 ) 105 (33 ) — — (33 ) Total Mark-to-Market Derivative (Liabilities) $ — $ (706 ) $ 541 $ (165 ) $ — $ — $ (165 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 18 $ 62 $ 24 $ 104 $ 26 $ 22 $ 152 (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, 2015 and 2014 . 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 in the Consolidated Balance Sheets. As of December 31, 2015 and 2014 , net cash collateral (received) paid of $(55) million and $24 million , respectively, were netted against the corresponding net derivative contract positions. Of the $(55) million as of December 31, 2015 , $(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. Of the $24 million as of December 31, 2014 , cash collateral of $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 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, it would be required to provide additional collateral. 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 $78 million and $127 million as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 and 2014 , Power had the contractual right of offset of $12 million and $18 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 $66 million and $109 million as of December 31, 2015 and 2014 , respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $864 million and $945 million as of December 31, 2015 and 2014 , respectively, discussed in Note 12. Commitments and Contingent Liabilities . 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, 2015 , 2014 and 2013 : 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) Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, Years Ended December 31, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Millions Millions PSEG Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Interest Rate Swaps (A) — — — Interest Expense — — (1 ) — — — Total PSEG $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 12 $ — $ — $ (1 ) Power Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Total Power $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) (A) Includes amounts for PSEG parent. 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, 2013 $ (4 ) $ (2 ) Gain Recognized in AOCI 12 7 Plus: Loss Reclassified into Income 9 5 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 $ — $ — The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the years ended December 31, 2015 , 2014 and 2013 : 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, 2015 2014 2013 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 412 $ (348 ) $ (128 ) Energy-Related Contracts Energy Costs (8 ) 32 106 Total PSEG and Power $ 404 $ (316 ) $ (22 ) 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 elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $19 million , $20 million and $19 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2015 and 2014 : Type Notional Total PSEG Power PSE&G Millions As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — Financial Transmission Rights (FTRs) MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — As of December 31, 2014 Natural Gas Dth 274 — 216 58 Electricity MWh 310 — 310 — FTRs MWh 15 — 15 — Interest Rate Swaps U.S. Dollars 850 850 — — Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe 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, 2015 , 92% of the credit 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 and non-derivatives and normal purchases/normal sales). The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2015 . It further delineates that exposure by the credit rating of the counterparties and 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—External Rating $ 451 $ 175 $ 276 1 $ 160 (A) Non-Investment Grade—External Rating 24 — 24 — — Investment Grade—No External Rating 12 1 11 — — Non-Investment Grade—No External Rating 1 — 1 — — Total $ 488 $ 176 $ 312 1 $ 160 (A) Represents net exposure with PSE&G. As of December 31, 2015 , collateral held from counterparties where Power had credit exposure included $14 million in cash collateral and $162 million in letters of credit. As of December 31, 2015 , Power had 133 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, 2015 , 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 suppliers’ credit exposure is calculated each business day. As of December 31, 2015 , 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, 2015 | |
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. 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, 2015 , these consisted primarily of long-term gas supply 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, 2015 and December 31, 2014 , 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 Power and PSE&G. 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—Govt Obligations $ 108 $ — $ — $ 108 $ — Debt Securities—Other $ 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—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 26 $ — $ — $ 26 $ — Debt Securities—Other $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2014 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) $ 295 $ (517 ) $ — $ 774 $ 38 Interest Rate Swaps (C) $ 22 $ — $ — $ 22 $ — NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 23 $ — $ 23 $ — $ — Debt Securities—Govt Obligations $ 91 $ — $ — $ 91 $ — Debt Securities—Other $ 75 $ — $ — $ 75 $ — Other Securities $ 2 $ — $ — $ 2 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) PSE&G Assets: Cash Equivalents (A) $ 294 $ — $ 294 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 26 $ — $ — $ — $ 26 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 20 $ — $ — $ 20 $ — Debt Securities—Other $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 269 $ (517 ) $ — $ 774 $ 12 NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 18 $ — $ — $ 18 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) (A) Represents money market mutual funds. (B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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 Consolidated Balance Sheets. 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. As of December 31, 2014 , net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014 , $(12) million was netted against assets and $36 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 and Power, natural gas supply contracts are 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. For Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as 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. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For additional information see Note 12. Commitments and Contingent Liabilities . The following tables provide detail surrounding significant Level 3 valuations as of December 31, 2015 and 2014 . 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/dekatherm Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Other Various (A) 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2014 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 26 $ — Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm Total PSE&G $ 26 $ — Power Electricity Electric Load Contracts 12 (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Other Various (B) — — Total Power $ 12 $ (1 ) Total PSEG $ 38 $ (1 ) (A) Includes long-term electric capacity positions which were immaterial as of December 31, 2015 . (B) Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014 . 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 contract 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 either the power basis or the load variability or the longer-term gas basis amounts 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, 2015 and 2014 , respectively, follows: 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 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2014 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2014 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances (Settlements) (C) Transfers In (Out) (D) Balance as of December 31, 2014 Millions PSEG Net Derivative Assets (Liabilities) $ 88 $ (31 ) $ (68 ) $ — $ 51 $ (3 ) $ 37 PSE&G Net Derivative Assets (Liabilities) $ 94 $ — $ (68 ) $ — $ — $ — $ 26 Power Net Derivative Assets (Liabilities) $ (6 ) $ (31 ) $ — $ — $ 51 $ (3 ) $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $20 million and $(31) million in Operating Income in 2015 and 2014 , respectively. The $20 million in Operating Income in 2015 is realized. Of the $(31) million in Operating Income in 2014 , $22 million is unrealized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(20) million and $51 million in settlements for derivative contracts in 2015 and 2014 , respectively. (D) During the year ended December 31, 2014 , $(3) million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy. 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. As of December 31, 2014 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $37 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. Non-recurring Fair Value Measurements During the fourth quarter of 2014 , an assessment of recoverability was triggered for two commercial real estate properties located in Ohio and Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $14 million which is included in Operating Revenues in PSEG’s Consolidated Statement of Operations for the year ended December 31, 2014 . On September 30, 2015 the property located in Michigan was sold. The real estate investment of $5 million is carried as a nonrecurring fair value measurement determined using an income approach valuation technique (cash flow analyses) along with bids received as part of a marketing initiative. This technique relied on significant unobservable inputs and is considered a Level 3 measurement 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. 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, 2015 , these consisted primarily of long-term gas supply 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, 2015 and December 31, 2014 , 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 Power and PSE&G. 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—Govt Obligations $ 108 $ — $ — $ 108 $ — Debt Securities—Other $ 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—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 26 $ — $ — $ 26 $ — Debt Securities—Other $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2014 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) $ 295 $ (517 ) $ — $ 774 $ 38 Interest Rate Swaps (C) $ 22 $ — $ — $ 22 $ — NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 23 $ — $ 23 $ — $ — Debt Securities—Govt Obligations $ 91 $ — $ — $ 91 $ — Debt Securities—Other $ 75 $ — $ — $ 75 $ — Other Securities $ 2 $ — $ — $ 2 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) PSE&G Assets: Cash Equivalents (A) $ 294 $ — $ 294 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 26 $ — $ — $ — $ 26 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 20 $ — $ — $ 20 $ — Debt Securities—Other $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 269 $ (517 ) $ — $ 774 $ 12 NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 18 $ — $ — $ 18 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) (A) Represents money market mutual funds. (B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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 Consolidated Balance Sheets. 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. As of December 31, 2014 , net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014 , $(12) million was netted against assets and $36 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 and Power, natural gas supply contracts are 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. For Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as 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. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For additional information see Note 12. Commitments and Contingent Liabilities . The following tables provide detail surrounding significant Level 3 valuations as of December 31, 2015 and 2014 . 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/dekatherm Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Other Various (A) 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2014 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 26 $ — Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm Total PSE&G $ 26 $ — Power Electricity Electric Load Contracts 12 (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Other Various (B) — — Total Power $ 12 $ (1 ) Total PSEG $ 38 $ (1 ) (A) Includes long-term electric capacity positions which were immaterial as of December 31, 2015 . (B) Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014 . 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 contract 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 either the power basis or the load variability or the longer-term gas basis amounts 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, 2015 and 2014 , respectively, follows: 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 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2014 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2014 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances (Settlements) (C) Transfers In (Out) (D) Balance as of December 31, 2014 Millions PSEG Net Derivative Assets (Liabilities) $ 88 $ (31 ) $ (68 ) $ — $ 51 $ (3 ) $ 37 PSE&G Net Derivative Assets (Liabilities) $ 94 $ — $ (68 ) $ — $ — $ — $ 26 Power Net Derivative Assets (Liabilities) $ (6 ) $ (31 ) $ — $ — $ 51 $ (3 ) $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $20 million and $(31) million in Operating Income in 2015 and 2014 , respectively. The $20 million in Operating Income in 2015 is realized. Of the $(31) million in Operating Income in 2014 , $22 million is unrealized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(20) million and $51 million in settlements for derivative contracts in 2015 and 2014 , respectively. (D) During the year ended December 31, 2014 , $(3) million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy. 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. As of December 31, 2014 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $37 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. Non-recurring Fair Value Measurements During the fourth quarter of 2014 , an assessment of recoverability was triggered for two commercial real estate properties located in Ohio and Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $14 million which is included in Operating Revenues in PSEG’s Consolidated Statement of Operations for the year ended December 31, 2014 . On September 30, 2015 the property located in Michigan was sold. The real estate investment of $5 million is carried as a nonrecurring fair value measurement determined using an income approach valuation technique (cash flow analyses) along with bids received as part of a marketing initiative. This technique relied on significant unobservable inputs and is considered a Level 3 measurement 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. 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, 2015 , these consisted primarily of long-term gas supply 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, 2015 and December 31, 2014 , 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 Power and PSE&G. 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—Govt Obligations $ 108 $ — $ — $ 108 $ — Debt Securities—Other $ 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—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 26 $ — $ — $ 26 $ — Debt Securities—Other $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2014 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) $ 295 $ (517 ) $ — $ 774 $ 38 Interest Rate Swaps (C) $ 22 $ — $ — $ 22 $ — NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 23 $ — $ 23 $ — $ — Debt Securities—Govt Obligations $ 91 $ — $ — $ 91 $ — Debt Securities—Other $ 75 $ — $ — $ 75 $ — Other Securities $ 2 $ — $ — $ 2 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) PSE&G Assets: Cash Equivalents (A) $ 294 $ — $ 294 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 26 $ — $ — $ — $ 26 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 20 $ — $ — $ 20 $ — Debt Securities—Other $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 269 $ (517 ) $ — $ 774 $ 12 NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 18 $ — $ — $ 18 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) (A) Represents money market mutual funds. (B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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 Consolidated Balance Sheets. 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. As of December 31, 2014 , net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014 , $(12) million was netted against assets and $36 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 and Power, natural gas supply contracts are 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. For Power, in general, electric swaps are measured at fair value based on at least two pricing inputs, the underlying price of electricity at a liquid reference point and the basis difference between electricity prices at the liquid reference point and electricity prices at the respective delivery locations. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as 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. For Power, long-term electric capacity contracts are measured using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For additional information see Note 12. Commitments and Contingent Liabilities . The following tables provide detail surrounding significant Level 3 valuations as of December 31, 2015 and 2014 . 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/dekatherm Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Other Various (A) 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2014 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 26 $ — Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm Total PSE&G $ 26 $ — Power Electricity Electric Load Contracts 12 (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Other Various (B) — — Total Power $ 12 $ (1 ) Total PSEG $ 38 $ (1 ) (A) Includes long-term electric capacity positions which were immaterial as of December 31, 2015 . (B) Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014 . 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 contract 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 either the power basis or the load variability or the longer-term gas basis amounts 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, 2015 and 2014 , respectively, follows: 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 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2014 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2014 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances (Settlements) (C) Transfers In (Out) (D) Balance as of December 31, 2014 Millions PSEG Net Derivative Assets (Liabilities) $ 88 $ (31 ) $ (68 ) $ — $ 51 $ (3 ) $ 37 PSE&G Net Derivative Assets (Liabilities) $ 94 $ — $ (68 ) $ — $ — $ — $ 26 Power Net Derivative Assets (Liabilities) $ (6 ) $ (31 ) $ — $ — $ 51 $ (3 ) $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $20 million and $(31) million in Operating Income in 2015 and 2014 , respectively. The $20 million in Operating Income in 2015 is realized. Of the $(31) million in Operating Income in 2014 , $22 million is unrealized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(20) million and $51 million in settlements for derivative contracts in 2015 and 2014 , respectively. (D) During the year ended December 31, 2014 , $(3) million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy. 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. As of December 31, 2014 , PSEG carried $2.5 billion of net assets that are measured at fair value on a recurring basis, of which $37 million of net assets were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. Non-recurring Fair Value Measurements During the fourth quarter of 2014 , an assessment of recoverability was triggered for two commercial real estate properties located in Ohio and Michigan. As a result of the evaluation, Energy Holdings recorded a pre-tax impairment of $14 million which is included in Operating Revenues in PSEG’s Consolidated Statement of Operations for the year ended December 31, 2014 . On September 30, 2015 the property located in Michigan was sold. The real estate investment of $5 million is carried as a nonrecurring fair value measurement determined using an income approach valuation technique (cash flow analyses) along with bids received as part of a marketing initiative. This technique relied on significant unobservable inputs and is considered a Level 3 measurement within the fair value hierarchy. |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
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 (OCC), the plan'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, 2015 , 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 OCC. 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 OCC (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 OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock. 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 vested, 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 2015 and 2014 generally vest at the end of three years. Vesting may be accelerated 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 pro-rated for 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 All outstanding unvested stock options are being expensed based on their grant date fair values, which were 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. 2015 2014 2013 Millions Compensation Cost included in Operation and Maintenance Expense $ 34 $ 32 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 14 $ 13 $ 13 For 2015 the excess tax benefit was $3 million . There was no excess tax benefit for 2014 and 2013 . 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 2015 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2015 2,075,850 $ 35.35 Exercised 368,600 $ 32.37 Canceled/Forfeited — $ — Outstanding as of December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 Exercisable at December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 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 2015 , 2014 and 2013 . Activity for options exercised for the years ended December 31, 2015 , 2014 and 2013 is shown below: 2015 2014 2013 Millions Total Intrinsic Value of Options Exercised $ 3 $ 4 $ 1 Cash Received from Options Exercised $ 12 $ 16 $ 7 Tax Benefit Realized from Options Exercised $ — $ — $ — No options were vested during the years ended December 31, 2015 and 2014 . Less than one million options vested during the year ended December 31, 2013 . The total fair value of the stock options vested during the year ended December 31, 2013 was $1 million . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2015 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, 2015 1,069,029 $ 32.49 Granted 318,805 $ 39.65 Vested 963,387 $ 33.73 Canceled/Forfeited 15,940 $ 37.28 Non-vested as of December 31, 2015 408,507 $ 34.95 1.1 $ 15,805,175 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2015 , 2014 and 2013 was $39.65 , $35.16 and $31.41 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2015 , 2014 and 2013 was $11 million , $12 million and $4 million , respectively. As of December 31, 2015 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 43,081 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2015 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, 2015 765,633 $ 36.86 Granted 337,585 $ 41.32 Vested 655,201 $ 36.82 Canceled/Forfeited 44,056 $ 38.97 Non-vested as of December 31, 2015 403,961 $ 40.42 1.6 $ 15,629,251 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2015 , 2014 and 2013 was $41.32 , $38.94 and $35.07 per share, respectively. The total intrinsic value of performance share units vested during the year ended December 31, 2015 , 2014 and 2013 was $13 million , $6 million and $5 million , respectively. As of December 31, 2015 , there was approximately $15 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 44,559 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 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 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, 2015 , 2014 and 2013 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, 2015 , 2014 and 2013 . During the years ended December 31, 2015 , 2014 and 2013 , employees purchased 250,499 shares, 207,248 shares and 257,513 shares at an average price of $36.66 , $36.07 and $30.57 per share, respectively. As of December 31, 2015 , 3.7 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 (OCC), the plan'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, 2015 , 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 OCC. 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 OCC (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 OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock. 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 vested, 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 2015 and 2014 generally vest at the end of three years. Vesting may be accelerated 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 pro-rated for 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 All outstanding unvested stock options are being expensed based on their grant date fair values, which were 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. 2015 2014 2013 Millions Compensation Cost included in Operation and Maintenance Expense $ 34 $ 32 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 14 $ 13 $ 13 For 2015 the excess tax benefit was $3 million . There was no excess tax benefit for 2014 and 2013 . 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 2015 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2015 2,075,850 $ 35.35 Exercised 368,600 $ 32.37 Canceled/Forfeited — $ — Outstanding as of December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 Exercisable at December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 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 2015 , 2014 and 2013 . Activity for options exercised for the years ended December 31, 2015 , 2014 and 2013 is shown below: 2015 2014 2013 Millions Total Intrinsic Value of Options Exercised $ 3 $ 4 $ 1 Cash Received from Options Exercised $ 12 $ 16 $ 7 Tax Benefit Realized from Options Exercised $ — $ — $ — No options were vested during the years ended December 31, 2015 and 2014 . Less than one million options vested during the year ended December 31, 2013 . The total fair value of the stock options vested during the year ended December 31, 2013 was $1 million . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2015 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, 2015 1,069,029 $ 32.49 Granted 318,805 $ 39.65 Vested 963,387 $ 33.73 Canceled/Forfeited 15,940 $ 37.28 Non-vested as of December 31, 2015 408,507 $ 34.95 1.1 $ 15,805,175 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2015 , 2014 and 2013 was $39.65 , $35.16 and $31.41 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2015 , 2014 and 2013 was $11 million , $12 million and $4 million , respectively. As of December 31, 2015 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 43,081 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2015 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, 2015 765,633 $ 36.86 Granted 337,585 $ 41.32 Vested 655,201 $ 36.82 Canceled/Forfeited 44,056 $ 38.97 Non-vested as of December 31, 2015 403,961 $ 40.42 1.6 $ 15,629,251 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2015 , 2014 and 2013 was $41.32 , $38.94 and $35.07 per share, respectively. The total intrinsic value of performance share units vested during the year ended December 31, 2015 , 2014 and 2013 was $13 million , $6 million and $5 million , respectively. As of December 31, 2015 , there was approximately $15 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 44,559 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 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 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, 2015 , 2014 and 2013 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, 2015 , 2014 and 2013 . During the years ended December 31, 2015 , 2014 and 2013 , employees purchased 250,499 shares, 207,248 shares and 257,513 shares at an average price of $36.66 , $36.07 and $30.57 per share, respectively. As of December 31, 2015 , 3.7 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 (OCC), the plan'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, 2015 , 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 OCC. 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 OCC (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 OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock. 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 vested, 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 2015 and 2014 generally vest at the end of three years. Vesting may be accelerated 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 pro-rated for 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 All outstanding unvested stock options are being expensed based on their grant date fair values, which were 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. 2015 2014 2013 Millions Compensation Cost included in Operation and Maintenance Expense $ 34 $ 32 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 14 $ 13 $ 13 For 2015 the excess tax benefit was $3 million . There was no excess tax benefit for 2014 and 2013 . 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 2015 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2015 2,075,850 $ 35.35 Exercised 368,600 $ 32.37 Canceled/Forfeited — $ — Outstanding as of December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 Exercisable at December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 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 2015 , 2014 and 2013 . Activity for options exercised for the years ended December 31, 2015 , 2014 and 2013 is shown below: 2015 2014 2013 Millions Total Intrinsic Value of Options Exercised $ 3 $ 4 $ 1 Cash Received from Options Exercised $ 12 $ 16 $ 7 Tax Benefit Realized from Options Exercised $ — $ — $ — No options were vested during the years ended December 31, 2015 and 2014 . Less than one million options vested during the year ended December 31, 2013 . The total fair value of the stock options vested during the year ended December 31, 2013 was $1 million . Restricted Stock Units Changes in restricted stock units for the year ended December 31, 2015 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, 2015 1,069,029 $ 32.49 Granted 318,805 $ 39.65 Vested 963,387 $ 33.73 Canceled/Forfeited 15,940 $ 37.28 Non-vested as of December 31, 2015 408,507 $ 34.95 1.1 $ 15,805,175 The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2015 , 2014 and 2013 was $39.65 , $35.16 and $31.41 per share, respectively. The total intrinsic value of restricted stock units vested during the years ended December 31, 2015 , 2014 and 2013 was $11 million , $12 million and $4 million , respectively. As of December 31, 2015 , there was approximately $5 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of one year. Dividend equivalents units of 43,081 accrued on the restricted stock units during the year. Performance Share Units Changes in performance share units for the year ended December 31, 2015 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, 2015 765,633 $ 36.86 Granted 337,585 $ 41.32 Vested 655,201 $ 36.82 Canceled/Forfeited 44,056 $ 38.97 Non-vested as of December 31, 2015 403,961 $ 40.42 1.6 $ 15,629,251 The weighted average grant date fair value per share for performance share units during the years ended December 31, 2015 , 2014 and 2013 was $41.32 , $38.94 and $35.07 per share, respectively. The total intrinsic value of performance share units vested during the year ended December 31, 2015 , 2014 and 2013 was $13 million , $6 million and $5 million , respectively. As of December 31, 2015 , there was approximately $15 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 44,559 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 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 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, 2015 , 2014 and 2013 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, 2015 , 2014 and 2013 . During the years ended December 31, 2015 , 2014 and 2013 , employees purchased 250,499 shares, 207,248 shares and 257,513 shares at an average price of $36.66 , $36.07 and $30.57 per share, respectively. As of December 31, 2015 , 3.7 million shares were available for future issuance under this plan. |
Other Income and Deductions
Other Income and Deductions | 12 Months Ended |
Dec. 31, 2015 | |
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, 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 Year Ended December 31, 2013 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 152 $ — $ 152 Allowance for Funds Used During Construction 24 — — 24 Solar Loan Interest 23 — — 23 Other 7 2 5 14 Total Other Income $ 54 $ 154 $ 5 $ 213 Other Deductions PSE&G Power Other (A) Consolidated Total Millions 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 Year Ended December 31, 2013 NDT Fund Realized Losses and Expenses $ — $ 34 $ — $ 34 Other 3 15 2 20 Total Other Deductions $ 3 $ 49 $ 2 $ 54 (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, 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 Year Ended December 31, 2013 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 152 $ — $ 152 Allowance for Funds Used During Construction 24 — — 24 Solar Loan Interest 23 — — 23 Other 7 2 5 14 Total Other Income $ 54 $ 154 $ 5 $ 213 Other Deductions PSE&G Power Other (A) Consolidated Total Millions 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 Year Ended December 31, 2013 NDT Fund Realized Losses and Expenses $ — $ 34 $ — $ 34 Other 3 15 2 20 Total Other Deductions $ 3 $ 49 $ 2 $ 54 (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, 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 Year Ended December 31, 2013 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 152 $ — $ 152 Allowance for Funds Used During Construction 24 — — 24 Solar Loan Interest 23 — — 23 Other 7 2 5 14 Total Other Income $ 54 $ 154 $ 5 $ 213 Other Deductions PSE&G Power Other (A) Consolidated Total Millions 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 Year Ended December 31, 2013 NDT Fund Realized Losses and Expenses $ — $ 34 $ — $ 34 Other 3 15 2 20 Total Other Deductions $ 3 $ 49 $ 2 $ 54 (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, 2015 | |
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 2015 2014 2013 Millions Net Income $ 1,679 $ 1,518 $ 1,243 Income Taxes: Operating Income: Current Expense: Federal $ 243 $ 335 $ 487 State 85 58 42 Total Current 328 393 529 Deferred Expense: Federal 540 262 147 State 104 260 118 Total Deferred 644 522 265 Investment Tax Credit (ITC) 29 23 18 Total Income Taxes $ 1,001 $ 938 $ 812 Pre-Tax Income $ 2,680 $ 2,456 $ 2,055 Tax Computed at Statutory Rate 35% $ 938 $ 860 $ 719 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 129 145 108 Uncertain Tax Positions 7 (9 ) 10 Manufacturing Deduction (10 ) (16 ) (9 ) NDT Fund 7 14 12 Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (13 ) (14 ) (9 ) Audit Settlement — (12 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (4 ) (17 ) (5 ) Sub-Total 63 78 93 Total Income Tax Provision $ 1,001 $ 938 $ 812 Effective Income Tax Rate 37.4 % 38.2 % 39.5 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 11 Noncurrent OPEB $ 256 $ 269 Related to Uncertain Tax Position 160 160 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 443 $ 484 Total Assets $ 443 $ 495 Liabilities: Current (net) Securitization $ — $ 163 Other — 10 Total Current Liabilities (net) $ — $ 173 Noncurrent: Plant-Related Items $ 6,174 $ 5,422 New Jersey Corporate Business Tax 615 535 Leasing Activities 612 623 Pension Costs 218 219 AROs and NDT Fund 393 419 Taxes Recoverable Through Future Rate (net) 191 196 Other 244 240 Total Noncurrent Liabilities $ 8,447 $ 7,654 Total Liabilities $ 8,447 $ 7,827 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 11 Net Current Deferred Income Tax Liabilities $ — $ 173 Net Noncurrent Deferred Income Tax Liabilities $ 8,004 $ 7,170 ITC 162 133 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,166 $ 7,303 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 2015 2014 2013 Millions Net Income $ 787 $ 725 $ 612 Income Taxes: Operating Income: Current Expense: Federal $ 32 $ 124 $ 183 State 52 16 — Total Current 84 140 183 Deferred Expense: Federal 325 214 101 State 52 84 92 Total Deferred 377 298 193 ITC 9 11 5 Total Income Taxes $ 470 $ 449 $ 381 Pre-Tax Income $ 1,257 $ 1,174 $ 993 Tax Computed at Statutory Rate 35% $ 440 $ 411 $ 348 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 67 65 59 Uncertain Tax Positions (14 ) — — Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (6 ) (7 ) (6 ) Audit Settlement — 1 — Other 3 (8 ) (6 ) Sub-Total 30 38 33 Total Income Tax Provision $ 470 $ 449 $ 381 Effective Income Tax Rate 37.4 % 38.2 % 38.4 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 24 Noncurrent: OPEB $ 164 $ 173 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 191 $ 228 Total Assets $ 191 $ 252 Liabilities: Current (net) Securitization $ — $ 163 Other — 2 Total Current Liabilities (net) $ — $ 165 Noncurrent: Plant-Related Items $ 4,435 $ 3,869 New Jersey Corporate Business Tax 312 268 Conservation Costs 40 48 Pension Costs 262 269 Taxes Recoverable Through Future Rate (net) 191 196 Other 54 84 Total Noncurrent Liabilities $ 5,294 $ 4,734 Total Liabilities $ 5,294 $ 4,899 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 24 Net Current Deferred Income Tax Liabilities $ — $ 165 Net Noncurrent Deferred Income Tax Liabilities $ 5,103 $ 4,506 ITC 78 69 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,181 $ 4,575 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards . 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 2015 2014 2013 Millions Net Income $ 856 $ 760 $ 644 Income Taxes: Operating Income: Current Expense: Federal $ 220 $ 231 $ 262 State 30 39 40 Total Current 250 270 302 Deferred Expense: Federal 189 163 69 State 52 48 35 Total Deferred 241 211 104 ITC 20 10 13 Total Income Taxes $ 511 $ 491 $ 419 Pre-Tax Income $ 1,367 $ 1,251 $ 1,063 Tax Computed at Statutory Rate 35% $ 478 $ 438 $ 372 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 59 58 51 Manufacturing Deduction (10 ) (16 ) (10 ) NDT Fund 7 15 12 Tax Credits (7 ) (6 ) (2 ) Uncertain Tax Positions 22 (8 ) 3 Audit Settlement — (4 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (5 ) 14 (7 ) Sub-Total 33 53 47 Total Income Tax Provision $ 511 $ 491 $ 419 Effective Income Tax Rate 37.4 % 39.2 % 39.4 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2015 2014 Millions Deferred Income Taxes Assets: Current $ — $ — Noncurrent: Pension Costs $ 56 $ 52 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 47 23 Other — 70 Total Noncurrent Assets $ 121 $ 163 Total Assets $ 121 $ 163 Liabilities: Current (net) $ — $ 43 Noncurrent: Plant-Related Items $ 1,736 $ 1,552 New Jersey Corporate Business Tax 243 192 AROs and NDT Fund 395 420 Other 10 — Total Noncurrent Liabilities $ 2,384 $ 2,164 Total Liabilities $ 2,384 $ 2,207 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ — Net Current Deferred Income Tax Liabilities $ — $ 43 Net Noncurrent Deferred Income Tax Liabilities $ 2,263 $ 2,001 ITC 84 64 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,347 $ 2,065 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 has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 5. Regulatory Assets and Liabilities . In August 2014, PSEG received notice from the IRS that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settled all issues with the IRS through 2010. In September 2014, PSEG received refunds from the IRS totaling $121 million , representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense in the quarter ended September 30, 2014. In September 2013, the U.S. Department of the Treasury and the IRS released final regulations effective in 2014 that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce or improve tangible property, as well as rules for materials and supplies. Implementation of these regulations did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows. The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation rules enacted in 2010 for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 was eligible for 50% bonus depreciation for federal tax purposes. On December 19, 2014, the Tax Increase Prevention Act of 2014 was enacted. This act further 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: 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 2013 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2013 $ 402 $ 163 $ 134 $ 101 Increases as a Result of Positions Taken in a Prior Period 83 39 33 11 Decreases as a Result of Positions Taken in a Prior Period (30 ) (9 ) (19 ) (2 ) Increases as a Result of Positions Taken during the Current Period 23 15 8 — 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 — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2013 $ 478 $ 208 $ 156 $ 110 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (320 ) (177 ) (105 ) (37 ) Regulatory Asset—Unrecognized Tax Benefits (30 ) (30 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 128 $ 1 $ 51 $ 73 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, 2015 2014 2013 Millions PSE&G $ 20 $ 15 $ 6 Power 6 9 (2 ) Energy Holdings 40 45 44 Total $ 66 $ 69 $ 48 It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows: Possible Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 158 PSE&G $ 102 Power $ 42 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 2011-2014 N/A N/A New Jersey 2006-2014 2006-2014 N/A Pennsylvania 2006-2014 2006-2014 N/A Connecticut 2002-2014 N/A N/A Texas 2007-2014 N/A N/A California 2003-2014 N/A N/A New York 2011-2014 N/A 2011-2014 |
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 2015 2014 2013 Millions Net Income $ 1,679 $ 1,518 $ 1,243 Income Taxes: Operating Income: Current Expense: Federal $ 243 $ 335 $ 487 State 85 58 42 Total Current 328 393 529 Deferred Expense: Federal 540 262 147 State 104 260 118 Total Deferred 644 522 265 Investment Tax Credit (ITC) 29 23 18 Total Income Taxes $ 1,001 $ 938 $ 812 Pre-Tax Income $ 2,680 $ 2,456 $ 2,055 Tax Computed at Statutory Rate 35% $ 938 $ 860 $ 719 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 129 145 108 Uncertain Tax Positions 7 (9 ) 10 Manufacturing Deduction (10 ) (16 ) (9 ) NDT Fund 7 14 12 Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (13 ) (14 ) (9 ) Audit Settlement — (12 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (4 ) (17 ) (5 ) Sub-Total 63 78 93 Total Income Tax Provision $ 1,001 $ 938 $ 812 Effective Income Tax Rate 37.4 % 38.2 % 39.5 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 11 Noncurrent OPEB $ 256 $ 269 Related to Uncertain Tax Position 160 160 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 443 $ 484 Total Assets $ 443 $ 495 Liabilities: Current (net) Securitization $ — $ 163 Other — 10 Total Current Liabilities (net) $ — $ 173 Noncurrent: Plant-Related Items $ 6,174 $ 5,422 New Jersey Corporate Business Tax 615 535 Leasing Activities 612 623 Pension Costs 218 219 AROs and NDT Fund 393 419 Taxes Recoverable Through Future Rate (net) 191 196 Other 244 240 Total Noncurrent Liabilities $ 8,447 $ 7,654 Total Liabilities $ 8,447 $ 7,827 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 11 Net Current Deferred Income Tax Liabilities $ — $ 173 Net Noncurrent Deferred Income Tax Liabilities $ 8,004 $ 7,170 ITC 162 133 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,166 $ 7,303 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 2015 2014 2013 Millions Net Income $ 787 $ 725 $ 612 Income Taxes: Operating Income: Current Expense: Federal $ 32 $ 124 $ 183 State 52 16 — Total Current 84 140 183 Deferred Expense: Federal 325 214 101 State 52 84 92 Total Deferred 377 298 193 ITC 9 11 5 Total Income Taxes $ 470 $ 449 $ 381 Pre-Tax Income $ 1,257 $ 1,174 $ 993 Tax Computed at Statutory Rate 35% $ 440 $ 411 $ 348 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 67 65 59 Uncertain Tax Positions (14 ) — — Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (6 ) (7 ) (6 ) Audit Settlement — 1 — Other 3 (8 ) (6 ) Sub-Total 30 38 33 Total Income Tax Provision $ 470 $ 449 $ 381 Effective Income Tax Rate 37.4 % 38.2 % 38.4 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 24 Noncurrent: OPEB $ 164 $ 173 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 191 $ 228 Total Assets $ 191 $ 252 Liabilities: Current (net) Securitization $ — $ 163 Other — 2 Total Current Liabilities (net) $ — $ 165 Noncurrent: Plant-Related Items $ 4,435 $ 3,869 New Jersey Corporate Business Tax 312 268 Conservation Costs 40 48 Pension Costs 262 269 Taxes Recoverable Through Future Rate (net) 191 196 Other 54 84 Total Noncurrent Liabilities $ 5,294 $ 4,734 Total Liabilities $ 5,294 $ 4,899 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 24 Net Current Deferred Income Tax Liabilities $ — $ 165 Net Noncurrent Deferred Income Tax Liabilities $ 5,103 $ 4,506 ITC 78 69 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,181 $ 4,575 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards . 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 2015 2014 2013 Millions Net Income $ 856 $ 760 $ 644 Income Taxes: Operating Income: Current Expense: Federal $ 220 $ 231 $ 262 State 30 39 40 Total Current 250 270 302 Deferred Expense: Federal 189 163 69 State 52 48 35 Total Deferred 241 211 104 ITC 20 10 13 Total Income Taxes $ 511 $ 491 $ 419 Pre-Tax Income $ 1,367 $ 1,251 $ 1,063 Tax Computed at Statutory Rate 35% $ 478 $ 438 $ 372 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 59 58 51 Manufacturing Deduction (10 ) (16 ) (10 ) NDT Fund 7 15 12 Tax Credits (7 ) (6 ) (2 ) Uncertain Tax Positions 22 (8 ) 3 Audit Settlement — (4 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (5 ) 14 (7 ) Sub-Total 33 53 47 Total Income Tax Provision $ 511 $ 491 $ 419 Effective Income Tax Rate 37.4 % 39.2 % 39.4 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2015 2014 Millions Deferred Income Taxes Assets: Current $ — $ — Noncurrent: Pension Costs $ 56 $ 52 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 47 23 Other — 70 Total Noncurrent Assets $ 121 $ 163 Total Assets $ 121 $ 163 Liabilities: Current (net) $ — $ 43 Noncurrent: Plant-Related Items $ 1,736 $ 1,552 New Jersey Corporate Business Tax 243 192 AROs and NDT Fund 395 420 Other 10 — Total Noncurrent Liabilities $ 2,384 $ 2,164 Total Liabilities $ 2,384 $ 2,207 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ — Net Current Deferred Income Tax Liabilities $ — $ 43 Net Noncurrent Deferred Income Tax Liabilities $ 2,263 $ 2,001 ITC 84 64 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,347 $ 2,065 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 has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 5. Regulatory Assets and Liabilities . In August 2014, PSEG received notice from the IRS that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settled all issues with the IRS through 2010. In September 2014, PSEG received refunds from the IRS totaling $121 million , representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense in the quarter ended September 30, 2014. In September 2013, the U.S. Department of the Treasury and the IRS released final regulations effective in 2014 that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce or improve tangible property, as well as rules for materials and supplies. Implementation of these regulations did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows. The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation rules enacted in 2010 for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 was eligible for 50% bonus depreciation for federal tax purposes. On December 19, 2014, the Tax Increase Prevention Act of 2014 was enacted. This act further 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: 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 2013 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2013 $ 402 $ 163 $ 134 $ 101 Increases as a Result of Positions Taken in a Prior Period 83 39 33 11 Decreases as a Result of Positions Taken in a Prior Period (30 ) (9 ) (19 ) (2 ) Increases as a Result of Positions Taken during the Current Period 23 15 8 — 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 — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2013 $ 478 $ 208 $ 156 $ 110 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (320 ) (177 ) (105 ) (37 ) Regulatory Asset—Unrecognized Tax Benefits (30 ) (30 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 128 $ 1 $ 51 $ 73 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, 2015 2014 2013 Millions PSE&G $ 20 $ 15 $ 6 Power 6 9 (2 ) Energy Holdings 40 45 44 Total $ 66 $ 69 $ 48 It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows: Possible Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 158 PSE&G $ 102 Power $ 42 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 2011-2014 N/A N/A New Jersey 2006-2014 2006-2014 N/A Pennsylvania 2006-2014 2006-2014 N/A Connecticut 2002-2014 N/A N/A Texas 2007-2014 N/A N/A California 2003-2014 N/A N/A New York 2011-2014 N/A 2011-2014 |
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 2015 2014 2013 Millions Net Income $ 1,679 $ 1,518 $ 1,243 Income Taxes: Operating Income: Current Expense: Federal $ 243 $ 335 $ 487 State 85 58 42 Total Current 328 393 529 Deferred Expense: Federal 540 262 147 State 104 260 118 Total Deferred 644 522 265 Investment Tax Credit (ITC) 29 23 18 Total Income Taxes $ 1,001 $ 938 $ 812 Pre-Tax Income $ 2,680 $ 2,456 $ 2,055 Tax Computed at Statutory Rate 35% $ 938 $ 860 $ 719 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 129 145 108 Uncertain Tax Positions 7 (9 ) 10 Manufacturing Deduction (10 ) (16 ) (9 ) NDT Fund 7 14 12 Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (13 ) (14 ) (9 ) Audit Settlement — (12 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (4 ) (17 ) (5 ) Sub-Total 63 78 93 Total Income Tax Provision $ 1,001 $ 938 $ 812 Effective Income Tax Rate 37.4 % 38.2 % 39.5 % The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 11 Noncurrent OPEB $ 256 $ 269 Related to Uncertain Tax Position 160 160 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 443 $ 484 Total Assets $ 443 $ 495 Liabilities: Current (net) Securitization $ — $ 163 Other — 10 Total Current Liabilities (net) $ — $ 173 Noncurrent: Plant-Related Items $ 6,174 $ 5,422 New Jersey Corporate Business Tax 615 535 Leasing Activities 612 623 Pension Costs 218 219 AROs and NDT Fund 393 419 Taxes Recoverable Through Future Rate (net) 191 196 Other 244 240 Total Noncurrent Liabilities $ 8,447 $ 7,654 Total Liabilities $ 8,447 $ 7,827 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 11 Net Current Deferred Income Tax Liabilities $ — $ 173 Net Noncurrent Deferred Income Tax Liabilities $ 8,004 $ 7,170 ITC 162 133 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,166 $ 7,303 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 2015 2014 2013 Millions Net Income $ 787 $ 725 $ 612 Income Taxes: Operating Income: Current Expense: Federal $ 32 $ 124 $ 183 State 52 16 — Total Current 84 140 183 Deferred Expense: Federal 325 214 101 State 52 84 92 Total Deferred 377 298 193 ITC 9 11 5 Total Income Taxes $ 470 $ 449 $ 381 Pre-Tax Income $ 1,257 $ 1,174 $ 993 Tax Computed at Statutory Rate 35% $ 440 $ 411 $ 348 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 67 65 59 Uncertain Tax Positions (14 ) — — Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (6 ) (7 ) (6 ) Audit Settlement — 1 — Other 3 (8 ) (6 ) Sub-Total 30 38 33 Total Income Tax Provision $ 470 $ 449 $ 381 Effective Income Tax Rate 37.4 % 38.2 % 38.4 % The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 24 Noncurrent: OPEB $ 164 $ 173 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 191 $ 228 Total Assets $ 191 $ 252 Liabilities: Current (net) Securitization $ — $ 163 Other — 2 Total Current Liabilities (net) $ — $ 165 Noncurrent: Plant-Related Items $ 4,435 $ 3,869 New Jersey Corporate Business Tax 312 268 Conservation Costs 40 48 Pension Costs 262 269 Taxes Recoverable Through Future Rate (net) 191 196 Other 54 84 Total Noncurrent Liabilities $ 5,294 $ 4,734 Total Liabilities $ 5,294 $ 4,899 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 24 Net Current Deferred Income Tax Liabilities $ — $ 165 Net Noncurrent Deferred Income Tax Liabilities $ 5,103 $ 4,506 ITC 78 69 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,181 $ 4,575 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards . 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 2015 2014 2013 Millions Net Income $ 856 $ 760 $ 644 Income Taxes: Operating Income: Current Expense: Federal $ 220 $ 231 $ 262 State 30 39 40 Total Current 250 270 302 Deferred Expense: Federal 189 163 69 State 52 48 35 Total Deferred 241 211 104 ITC 20 10 13 Total Income Taxes $ 511 $ 491 $ 419 Pre-Tax Income $ 1,367 $ 1,251 $ 1,063 Tax Computed at Statutory Rate 35% $ 478 $ 438 $ 372 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 59 58 51 Manufacturing Deduction (10 ) (16 ) (10 ) NDT Fund 7 15 12 Tax Credits (7 ) (6 ) (2 ) Uncertain Tax Positions 22 (8 ) 3 Audit Settlement — (4 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (5 ) 14 (7 ) Sub-Total 33 53 47 Total Income Tax Provision $ 511 $ 491 $ 419 Effective Income Tax Rate 37.4 % 39.2 % 39.4 % The following is an analysis of deferred income taxes for Power: As of December 31, Power 2015 2014 Millions Deferred Income Taxes Assets: Current $ — $ — Noncurrent: Pension Costs $ 56 $ 52 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 47 23 Other — 70 Total Noncurrent Assets $ 121 $ 163 Total Assets $ 121 $ 163 Liabilities: Current (net) $ — $ 43 Noncurrent: Plant-Related Items $ 1,736 $ 1,552 New Jersey Corporate Business Tax 243 192 AROs and NDT Fund 395 420 Other 10 — Total Noncurrent Liabilities $ 2,384 $ 2,164 Total Liabilities $ 2,384 $ 2,207 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ — Net Current Deferred Income Tax Liabilities $ — $ 43 Net Noncurrent Deferred Income Tax Liabilities $ 2,263 $ 2,001 ITC 84 64 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,347 $ 2,065 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 has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. 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 5. Regulatory Assets and Liabilities . In August 2014, PSEG received notice from the IRS that the audit settlement covering tax years 2007 through 2010 had been approved by the Joint Committee on Taxation. This effectively settled all issues with the IRS through 2010. In September 2014, PSEG received refunds from the IRS totaling $121 million , representing the net settlement of all disputed amounts, including interest, through the tax year 2010. As a result of the settlement of this audit, PSEG recorded a $12 million reduction of tax expense in the quarter ended September 30, 2014. In September 2013, the U.S. Department of the Treasury and the IRS released final regulations effective in 2014 that provide guidance on applying Section 263(a) of the Internal Revenue Code to amounts paid to acquire, produce or improve tangible property, as well as rules for materials and supplies. Implementation of these regulations did not have any material impact on PSEG’s and its subsidiaries’ results of operations, financial condition or cash flows. The American Taxpayer Relief Act of 2012 extended the 50% bonus depreciation rules enacted in 2010 for qualified property placed into service before January 1, 2014. In addition, long production property placed into service in 2014 was eligible for 50% bonus depreciation for federal tax purposes. On December 19, 2014, the Tax Increase Prevention Act of 2014 was enacted. This act further 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: 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 2013 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2013 $ 402 $ 163 $ 134 $ 101 Increases as a Result of Positions Taken in a Prior Period 83 39 33 11 Decreases as a Result of Positions Taken in a Prior Period (30 ) (9 ) (19 ) (2 ) Increases as a Result of Positions Taken during the Current Period 23 15 8 — 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 — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2013 $ 478 $ 208 $ 156 $ 110 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (320 ) (177 ) (105 ) (37 ) Regulatory Asset—Unrecognized Tax Benefits (30 ) (30 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 128 $ 1 $ 51 $ 73 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, 2015 2014 2013 Millions PSE&G $ 20 $ 15 $ 6 Power 6 9 (2 ) Energy Holdings 40 45 44 Total $ 66 $ 69 $ 48 It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows: Possible Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 158 PSE&G $ 102 Power $ 42 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 2011-2014 N/A N/A New Jersey 2006-2014 2006-2014 N/A Pennsylvania 2006-2014 2006-2014 N/A Connecticut 2002-2014 N/A N/A Texas 2007-2014 N/A N/A California 2003-2014 N/A N/A New York 2011-2014 N/A 2011-2014 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax | 12 Months Ended |
Dec. 31, 2015 | |
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, 2012 $ 7 $ (485 ) $ 90 $ (388 ) Other Comprehensive Income before Reclassifications (2 ) 210 91 299 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (7 ) 37 (36 ) (6 ) Net Current Period Other Comprehensive Income (Loss) (9 ) 247 55 293 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 ) 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, 2012 $ 9 $ (422 ) $ 85 $ (328 ) Other Comprehensive Income before Reclassifications (2 ) 185 93 276 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (8 ) 33 (36 ) (11 ) Net Current Period Other Comprehensive Income (Loss) (10 ) 218 57 265 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 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2013 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 $ 13 $ (5 ) $ 8 Interest Rate Swaps Interest Expense (1 ) — (1 ) Total Cash Flow Hedges 12 (5 ) 7 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (4 ) 7 Amortization of Actuarial Loss O&M Expense (75 ) 31 (44 ) Total Pension and OPEB Plans (64 ) 27 (37 ) Available-for-Sale Securities Realized Gains Other Income 116 (59 ) 57 Realized Losses Other Deductions (29 ) 14 (15 ) Other-Than-Temporary Impairments (OTTI) OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 75 (39 ) 36 Total $ 23 $ (17 ) $ 6 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2013 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 $ 13 $ (5 ) $ 8 Total Cash Flow Hedges 13 (5 ) 8 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (64 ) 26 (38 ) Total Pension and OPEB Plans (55 ) 22 (33 ) Available-for-Sale Securities Realized Gains Other Income 112 (57 ) 55 Realized Losses Other Deductions (26 ) 13 (13 ) OTTI OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 74 (38 ) 36 Total $ 32 $ (21 ) $ 11 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 ) 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 ) |
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, 2012 $ 7 $ (485 ) $ 90 $ (388 ) Other Comprehensive Income before Reclassifications (2 ) 210 91 299 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (7 ) 37 (36 ) (6 ) Net Current Period Other Comprehensive Income (Loss) (9 ) 247 55 293 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 ) 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, 2012 $ 9 $ (422 ) $ 85 $ (328 ) Other Comprehensive Income before Reclassifications (2 ) 185 93 276 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (8 ) 33 (36 ) (11 ) Net Current Period Other Comprehensive Income (Loss) (10 ) 218 57 265 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 ) PSEG Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2013 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 $ 13 $ (5 ) $ 8 Interest Rate Swaps Interest Expense (1 ) — (1 ) Total Cash Flow Hedges 12 (5 ) 7 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (4 ) 7 Amortization of Actuarial Loss O&M Expense (75 ) 31 (44 ) Total Pension and OPEB Plans (64 ) 27 (37 ) Available-for-Sale Securities Realized Gains Other Income 116 (59 ) 57 Realized Losses Other Deductions (29 ) 14 (15 ) Other-Than-Temporary Impairments (OTTI) OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 75 (39 ) 36 Total $ 23 $ (17 ) $ 6 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2013 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 $ 13 $ (5 ) $ 8 Total Cash Flow Hedges 13 (5 ) 8 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (64 ) 26 (38 ) Total Pension and OPEB Plans (55 ) 22 (33 ) Available-for-Sale Securities Realized Gains Other Income 112 (57 ) 55 Realized Losses Other Deductions (26 ) 13 (13 ) OTTI OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 74 (38 ) 36 Total $ 32 $ (21 ) $ 11 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 ) 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 ) |
Earnings Per Share (EPS) and Di
Earnings Per Share (EPS) and Dividends | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 1,679 $ 1,679 $ 1,518 $ 1,518 $ 1,243 $ 1,243 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 505 505 506 506 506 506 Effect of Stock Based Compensation Awards — 3 — 2 — 2 Total Shares 505 508 506 508 506 508 EPS: Net Income $ 3.32 $ 3.30 $ 3.00 $ 2.99 $ 2.46 $ 2.45 There were approximately 0.5 million , 0.4 million and 1.6 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, 2015 , 2014 and 2013 , respectively. No other stock options had an antidilutive effect for the years ended December 31, 2015 , 2014 or 2013 . Dividends Years Ended December 31, Dividend Payments on Common Stock 2015 2014 2013 Per Share $ 1.56 $ 1.48 $ 1.44 in Millions $ 789 $ 748 $ 728 On February 16, 2016 , PSEG’s Board of Directors approved a $0.41 per share common stock dividend for the first quarter of 2016 . |
Financial Information By Busine
Financial Information By Business Segments | 12 Months Ended |
Dec. 31, 2015 | |
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, 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 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2013 Operating Revenues $ 6,655 $ 5,063 $ 52 $ (1,802 ) $ 9,968 Depreciation and Amortization 872 273 33 — 1,178 Operating Income (Loss) 1,235 1,070 (6 ) — 2,299 Income from Equity Method Investments — 16 (5 ) — 11 Interest Income 25 1 25 (22 ) 29 Interest Expense 293 116 15 (22 ) 402 Income (Loss) before Income Taxes 993 1,063 (1 ) — 2,055 Income Tax Expense (Benefit) 381 419 12 — 812 Net Income (Loss) 612 644 (13 ) — 1,243 Gross Additions to Long-Lived Assets $ 2,175 $ 609 $ 27 $ — $ 2,811 As of December 31, 2013 Total Assets $ 19,689 $ 11,991 $ 4,025 $ (3,225 ) $ 32,480 Investments in Equity Method Subsidiaries $ — $ 123 $ 3 $ — $ 126 (A) Includes amounts applicable to Energy Holdings and PSEG LI (for 2015 and 2014), 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 23. 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, 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 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2013 Operating Revenues $ 6,655 $ 5,063 $ 52 $ (1,802 ) $ 9,968 Depreciation and Amortization 872 273 33 — 1,178 Operating Income (Loss) 1,235 1,070 (6 ) — 2,299 Income from Equity Method Investments — 16 (5 ) — 11 Interest Income 25 1 25 (22 ) 29 Interest Expense 293 116 15 (22 ) 402 Income (Loss) before Income Taxes 993 1,063 (1 ) — 2,055 Income Tax Expense (Benefit) 381 419 12 — 812 Net Income (Loss) 612 644 (13 ) — 1,243 Gross Additions to Long-Lived Assets $ 2,175 $ 609 $ 27 $ — $ 2,811 As of December 31, 2013 Total Assets $ 19,689 $ 11,991 $ 4,025 $ (3,225 ) $ 32,480 Investments in Equity Method Subsidiaries $ — $ 123 $ 3 $ — $ 126 (A) Includes amounts applicable to Energy Holdings and PSEG LI (for 2015 and 2014), 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 23. 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, 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 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2013 Operating Revenues $ 6,655 $ 5,063 $ 52 $ (1,802 ) $ 9,968 Depreciation and Amortization 872 273 33 — 1,178 Operating Income (Loss) 1,235 1,070 (6 ) — 2,299 Income from Equity Method Investments — 16 (5 ) — 11 Interest Income 25 1 25 (22 ) 29 Interest Expense 293 116 15 (22 ) 402 Income (Loss) before Income Taxes 993 1,063 (1 ) — 2,055 Income Tax Expense (Benefit) 381 419 12 — 812 Net Income (Loss) 612 644 (13 ) — 1,243 Gross Additions to Long-Lived Assets $ 2,175 $ 609 $ 27 $ — $ 2,811 As of December 31, 2013 Total Assets $ 19,689 $ 11,991 $ 4,025 $ (3,225 ) $ 32,480 Investments in Equity Method Subsidiaries $ — $ 123 $ 3 $ — $ 126 (A) Includes amounts applicable to Energy Holdings and PSEG LI (for 2015 and 2014), 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 23. Related-Party Transactions . |
Related-Party Transactions
Related-Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
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 2015 2014 2013 Millions Billings from Affiliates: Billings from Power primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Administrative Billings from Services (B) 274 248 255 Total Billings from Affiliates $ 1,904 $ 2,019 $ 2,052 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivables from PSEG (C) $ 222 $ 274 Payable to Power (A) $ 212 $ 313 Payable to Services (B) 80 66 Accounts Payable—Affiliated Companies $ 292 $ 379 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 109 $ 116 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2015 2014 2013 Millions Billings to Affiliates: Billings to PSE&G primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Billings from Affiliates: Administrative Billings from Services (B) $ 187 $ 165 $ 178 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivable from PSE&G (A) $ 212 $ 313 Receivable from PSEG (C) 64 — Accounts Receivable—Affiliated Companies $ 276 $ 313 Payable to Services (B) $ 33 $ 23 Payable to PSEG (C) — 95 Accounts Payable—Affiliated Companies $ 33 $ 118 Short-Term Loan due (to) from Affiliate (E) $ 363 $ 584 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 35 $ 41 (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. (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 2015 2014 2013 Millions Billings from Affiliates: Billings from Power primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Administrative Billings from Services (B) 274 248 255 Total Billings from Affiliates $ 1,904 $ 2,019 $ 2,052 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivables from PSEG (C) $ 222 $ 274 Payable to Power (A) $ 212 $ 313 Payable to Services (B) 80 66 Accounts Payable—Affiliated Companies $ 292 $ 379 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 109 $ 116 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2015 2014 2013 Millions Billings to Affiliates: Billings to PSE&G primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Billings from Affiliates: Administrative Billings from Services (B) $ 187 $ 165 $ 178 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivable from PSE&G (A) $ 212 $ 313 Receivable from PSEG (C) 64 — Accounts Receivable—Affiliated Companies $ 276 $ 313 Payable to Services (B) $ 33 $ 23 Payable to PSEG (C) — 95 Accounts Payable—Affiliated Companies $ 33 $ 118 Short-Term Loan due (to) from Affiliate (E) $ 363 $ 584 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 35 $ 41 (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. (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 2015 2014 2013 Millions Billings from Affiliates: Billings from Power primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Administrative Billings from Services (B) 274 248 255 Total Billings from Affiliates $ 1,904 $ 2,019 $ 2,052 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivables from PSEG (C) $ 222 $ 274 Payable to Power (A) $ 212 $ 313 Payable to Services (B) 80 66 Accounts Payable—Affiliated Companies $ 292 $ 379 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 109 $ 116 Power The financial statements for Power include transactions with related parties presented as follows: Years Ended December 31, Related Party Transactions 2015 2014 2013 Millions Billings to Affiliates: Billings to PSE&G primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Billings from Affiliates: Administrative Billings from Services (B) $ 187 $ 165 $ 178 Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivable from PSE&G (A) $ 212 $ 313 Receivable from PSEG (C) 64 — Accounts Receivable—Affiliated Companies $ 276 $ 313 Payable to Services (B) $ 33 $ 23 Payable to PSEG (C) — 95 Accounts Payable—Affiliated Companies $ 33 $ 118 Short-Term Loan due (to) from Affiliate (E) $ 363 $ 584 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 35 $ 41 (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. (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, 2015 | |
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, 2015 2014 2015 2014 2015 2014 2015 2014 PSEG Consolidated: Millions, except per share data Operating Revenues $ 3,135 $ 3,223 $ 2,314 $ 2,249 $ 2,688 $ 2,641 $ 2,278 $ 2,773 Operating Income $ 1,048 $ 705 $ 568 $ 365 $ 814 $ 746 $ 532 $ 807 Net Income (Loss) $ 586 $ 386 $ 345 $ 212 $ 439 $ 444 $ 309 $ 476 Earnings Per Share: Basic: Net Income (Loss) $ 1.16 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.88 $ 0.61 $ 0.94 Diluted: Net Income (Loss) $ 1.15 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.87 $ 0.60 $ 0.94 Weighted Average Common Shares Outstanding: Basic 506 506 506 506 505 506 505 506 Diluted 508 508 508 508 508 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 PSE&G: Millions Operating Revenues $ 2,002 $ 2,145 $ 1,466 $ 1,435 $ 1,766 $ 1,655 $ 1,402 $ 1,531 Operating Income $ 451 $ 411 $ 320 $ 291 $ 404 $ 383 $ 287 $ 308 Net Income (Loss) $ 242 $ 214 $ 167 $ 151 $ 222 $ 200 $ 156 $ 160 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 Power: Millions Operating Revenues $ 1,725 $ 1,700 $ 1,025 $ 986 $ 1,096 $ 1,138 $ 1,082 $ 1,610 Operating Income $ 584 $ 282 $ 228 $ 67 $ 391 $ 353 $ 227 $ 507 Net Income (Loss) $ 335 $ 164 $ 166 $ 54 $ 206 $ 222 $ 149 $ 320 |
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, 2015 2014 2015 2014 2015 2014 2015 2014 PSEG Consolidated: Millions, except per share data Operating Revenues $ 3,135 $ 3,223 $ 2,314 $ 2,249 $ 2,688 $ 2,641 $ 2,278 $ 2,773 Operating Income $ 1,048 $ 705 $ 568 $ 365 $ 814 $ 746 $ 532 $ 807 Net Income (Loss) $ 586 $ 386 $ 345 $ 212 $ 439 $ 444 $ 309 $ 476 Earnings Per Share: Basic: Net Income (Loss) $ 1.16 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.88 $ 0.61 $ 0.94 Diluted: Net Income (Loss) $ 1.15 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.87 $ 0.60 $ 0.94 Weighted Average Common Shares Outstanding: Basic 506 506 506 506 505 506 505 506 Diluted 508 508 508 508 508 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 PSE&G: Millions Operating Revenues $ 2,002 $ 2,145 $ 1,466 $ 1,435 $ 1,766 $ 1,655 $ 1,402 $ 1,531 Operating Income $ 451 $ 411 $ 320 $ 291 $ 404 $ 383 $ 287 $ 308 Net Income (Loss) $ 242 $ 214 $ 167 $ 151 $ 222 $ 200 $ 156 $ 160 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 Power: Millions Operating Revenues $ 1,725 $ 1,700 $ 1,025 $ 986 $ 1,096 $ 1,138 $ 1,082 $ 1,610 Operating Income $ 584 $ 282 $ 228 $ 67 $ 391 $ 353 $ 227 $ 507 Net Income (Loss) $ 335 $ 164 $ 166 $ 54 $ 206 $ 222 $ 149 $ 320 |
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, 2015 2014 2015 2014 2015 2014 2015 2014 PSEG Consolidated: Millions, except per share data Operating Revenues $ 3,135 $ 3,223 $ 2,314 $ 2,249 $ 2,688 $ 2,641 $ 2,278 $ 2,773 Operating Income $ 1,048 $ 705 $ 568 $ 365 $ 814 $ 746 $ 532 $ 807 Net Income (Loss) $ 586 $ 386 $ 345 $ 212 $ 439 $ 444 $ 309 $ 476 Earnings Per Share: Basic: Net Income (Loss) $ 1.16 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.88 $ 0.61 $ 0.94 Diluted: Net Income (Loss) $ 1.15 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.87 $ 0.60 $ 0.94 Weighted Average Common Shares Outstanding: Basic 506 506 506 506 505 506 505 506 Diluted 508 508 508 508 508 507 508 508 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 PSE&G: Millions Operating Revenues $ 2,002 $ 2,145 $ 1,466 $ 1,435 $ 1,766 $ 1,655 $ 1,402 $ 1,531 Operating Income $ 451 $ 411 $ 320 $ 291 $ 404 $ 383 $ 287 $ 308 Net Income (Loss) $ 242 $ 214 $ 167 $ 151 $ 222 $ 200 $ 156 $ 160 Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 Power: Millions Operating Revenues $ 1,725 $ 1,700 $ 1,025 $ 986 $ 1,096 $ 1,138 $ 1,082 $ 1,610 Operating Income $ 584 $ 282 $ 228 $ 67 $ 391 $ 353 $ 227 $ 507 Net Income (Loss) $ 335 $ 164 $ 166 $ 54 $ 206 $ 222 $ 149 $ 320 |
Guarantees of Debt
Guarantees of Debt | 12 Months Ended |
Dec. 31, 2015 | |
Subsidiary or Equity Method Investee [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 table presents financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013 . 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 As of December 31, 2014 Current Assets $ 4,263 $ 2,037 $ 150 $ (4,091 ) $ 2,359 Property, Plant and Equipment, net 81 6,265 1,169 — 7,515 Investment in Subsidiaries 4,516 120 — (4,636 ) — Noncurrent Assets 269 1,952 137 (195 ) 2,163 Total Assets $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 Current Liabilities $ 883 $ 3,606 $ 786 $ (4,091 ) $ 1,184 Noncurrent Liabilities 454 2,442 360 (195 ) 3,061 Long-Term Debt 2,234 — — — 2,234 Member’s Equity 5,558 4,326 310 (4,636 ) 5,558 Total Liabilities and Member’s Equity $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 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 Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2013 Operating Revenues $ — $ 5,022 $ 190 $ (149 ) $ 5,063 Operating Expenses 23 3,945 174 (149 ) 3,993 Operating Income (Loss) (23 ) 1,077 16 — 1,070 Equity Earnings (Losses) of Subsidiaries 684 (5 ) 16 (679 ) 16 Other Income 35 157 — (38 ) 154 Other Deductions (14 ) (35 ) — — (49 ) Other-Than-Temporary Impairments — (12 ) — — (12 ) Interest Expense (93 ) (42 ) (19 ) 38 (116 ) Income Tax Benefit (Expense) 55 (474 ) — — (419 ) Net Income (Loss) $ 644 $ 666 $ 13 $ (679 ) $ 644 Comprehensive Income (Loss) $ 909 $ 713 $ 11 $ (724 ) $ 909 Year Ended December 31, 2013 Net Cash Provided By (Used In) Operating Activities $ 288 $ 1,503 $ 82 $ (526 ) $ 1,347 Net Cash Provided By (Used In) Investing Activities $ (395 ) $ (1,092 ) $ (71 ) $ 697 $ (861 ) Net Cash Provided By (Used In) Financing Activities $ 107 $ (412 ) $ (11 ) $ (171 ) $ (487 ) |
Power [Member] | |
Subsidiary or Equity Method Investee [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 table presents financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013 . 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 As of December 31, 2014 Current Assets $ 4,263 $ 2,037 $ 150 $ (4,091 ) $ 2,359 Property, Plant and Equipment, net 81 6,265 1,169 — 7,515 Investment in Subsidiaries 4,516 120 — (4,636 ) — Noncurrent Assets 269 1,952 137 (195 ) 2,163 Total Assets $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 Current Liabilities $ 883 $ 3,606 $ 786 $ (4,091 ) $ 1,184 Noncurrent Liabilities 454 2,442 360 (195 ) 3,061 Long-Term Debt 2,234 — — — 2,234 Member’s Equity 5,558 4,326 310 (4,636 ) 5,558 Total Liabilities and Member’s Equity $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 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 Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2013 Operating Revenues $ — $ 5,022 $ 190 $ (149 ) $ 5,063 Operating Expenses 23 3,945 174 (149 ) 3,993 Operating Income (Loss) (23 ) 1,077 16 — 1,070 Equity Earnings (Losses) of Subsidiaries 684 (5 ) 16 (679 ) 16 Other Income 35 157 — (38 ) 154 Other Deductions (14 ) (35 ) — — (49 ) Other-Than-Temporary Impairments — (12 ) — — (12 ) Interest Expense (93 ) (42 ) (19 ) 38 (116 ) Income Tax Benefit (Expense) 55 (474 ) — — (419 ) Net Income (Loss) $ 644 $ 666 $ 13 $ (679 ) $ 644 Comprehensive Income (Loss) $ 909 $ 713 $ 11 $ (724 ) $ 909 Year Ended December 31, 2013 Net Cash Provided By (Used In) Operating Activities $ 288 $ 1,503 $ 82 $ (526 ) $ 1,347 Net Cash Provided By (Used In) Investing Activities $ (395 ) $ (1,092 ) $ (71 ) $ 697 $ (861 ) Net Cash Provided By (Used In) Financing Activities $ 107 $ (412 ) $ (11 ) $ (171 ) $ (487 ) |
Valuation And Qualifying Accoun
Valuation And Qualifying Accounts | 12 Months Ended |
Dec. 31, 2015 | |
Valuation and Qualifying Accounts [Abstract] | |
Valuation And Qualifying Accounts | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2015 — December 31, 2013 Column A Column B Column C Column D Column E Additions Description Balance at Beginning of Period Charged to cost and expenses Charged to other accounts- describe Deductions- describe Balance at End of Period Millions 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 2013 Allowance for Doubtful Accounts $ 56 $ 90 $ — $ 90 (A) $ 56 Materials and Supplies Valuation Reserve 22 2 — 16 (B) 8 (A) Accounts Receivable written off. (B) Reduced reserve to appropriate level and to remove obsolete inventory. PUBLIC SERVICE ELECTRIC AND GAS COMPANY Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2015 — December 31, 2013 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 2015 Millions 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 2013 Allowance for Doubtful Accounts $ 56 $ 90 $ — $ 90 (A) $ 56 (A) Accounts Receivable written off. (B) Reduced reserve to appropriate level and to remove obsolete inventory. PSEG POWER LLC Schedule II—Valuation and Qualifying Accounts Years Ended December 31, 2015 — December 31, 2013 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 2015 Materials and Supplies Valuation Reserve $ 13 $ 2 $ — $ 5 (A) $ 10 2014 Materials and Supplies Valuation Reserve $ 8 $ 7 $ — $ 2 (A) $ 13 2013 Materials and Supplies Valuation Reserve $ 22 $ 2 $ — $ 16 (A) $ 8 (A) Reduced reserve to appropriate level and to remove obsolete inventory. |
Organization, Basis Of Presen36
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2015 | |
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 3. 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 5. Regulatory Assets and Liabilities . |
Derivative Financial Instruments | Derivative Financial Instruments Each company uses derivative financial instruments to manage risk pursuant to its business plans and prudent practices. Derivative instruments, not designated as normal purchases or sales, are recognized on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a fair value hedge, along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current period earnings. Changes in the fair value of a derivative that is highly effective as and that is designated and qualifies as a cash flow hedge are recorded 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 normal purchases or sales, changes in fair value are recorded in current period earnings. Many contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement. For additional information regarding derivative financial instruments, see Note 15. 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 normal purchases or sales or as cash flow or fair value hedges of other positions. See Note 15. 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 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 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 3. 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: 2015 2014 2013 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.46 % 2.47 % 2.48 % 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— 19 years to 79 years • nuclear generation assets—approximately 60 years • pumped storage facilities— 76 years • solar assets— 25 years |
Taxes Other Than Income Taxes | Taxes Other Than Income Taxes Excise taxes and the transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. Effective January 1, 2014, the TEFA was eliminated. For the year ended December 31, 2013 , $74 million and $68 million of the TEFA were included in Operating Revenues and Taxes Other Than Income Taxes, respectively, in the Consolidated Statements of Operations. |
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, 2015 , 2014 and 2013 were as follows: AFUDC/IDC Capitalized 2015 2014 2013 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 65 8.01 % $ 44 8.09 % $ 34 8.11 % Power $ 27 5.14 % $ 24 5.14 % $ 23 5.36 % |
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 19. Income Taxes for further discussion. |
Impairment Of Long-Lived Assets | Impairment of Long-Lived Assets In accordance with GAAP, 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, 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. 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 or that meet the normal purchases and normal sales exemption. 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. |
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) (except credit losses on debt securities which are recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 8. 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 11. 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 Adopted in 2015 Simplifying the Presentation of Debt Issuance Costs This standard was issued to simplify presentation of debt issuance costs. The standard requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this standard. The update is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued; therefore, PSEG has elected to early adopt these amendments in the fourth quarter of 2015 on a retrospective basis and therefore reclassified debt issuance costs in the 2014 Consolidated Balance Sheets. Unamortized debt issuance costs for PSE&G and Power were $41 million and $8 million , respectively, as of December 31, 2015 and $37 million and $9 million , respectively, as of December 31, 2014. Balance Sheet Classification of Deferred Taxes This standard was issued to reduce complexity in the presentation of deferred taxes. The new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet. The guidance is effective for annual and interim periods beginning after December 15, 2016. Early application is permitted as of the beginning of an interim or annual reporting period and the guidance may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. PSEG has elected to early adopt the guidance as of the fourth quarter of 2015 and to apply it prospectively. Prior periods were not retrospectively adjusted. New Standards Issued But Not Yet Adopted Revenue from Contracts with Customers This accounting standard was issued to clarify the principles for recognizing revenue and to develop a common standard that would remove inconsistencies in revenue requirements; improve comparability of revenue recognition practices across entities, industries, jurisdictions and capital markets; and provide 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 update was originally to be effective for annual and interim reporting periods beginning after December 15, 2016; however, the Financial Accounting Standards Board issued new guidance deferring the effective date by one year to periods beginning after December 31, 2017. Early application will be permitted as of the original effective date. PSEG is currently analyzing the impact of this standard on its financial statements. 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 and how they will present changes in the fair value of financial liabilities measured under the fair value option that are attributable to their own credit. Under the new guidance, equity investments (other than those accounted for using the equity method) will now have to be measured at fair value through Net Income instead of 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 accounting standard is effective for annual and interim reporting periods beginning after December 15, 2017. Early application is permitted for fiscal years or interim periods for which financial statements have not been issued. 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 would recognize a lease asset and corresponding lease obligation. A lessee would 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 would 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. The accounting 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. |
Organization, Basis Of Presen37
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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: 2015 2014 2013 Avg Rate Avg Rate Avg Rate PSE&G Depreciation Rate 2.46 % 2.47 % 2.48 % |
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, 2015 , 2014 and 2013 were as follows: AFUDC/IDC Capitalized 2015 2014 2013 Millions Avg Rate Millions Avg Rate Millions Avg Rate PSE&G $ 65 8.01 % $ 44 8.09 % $ 34 8.11 % Power $ 27 5.14 % $ 24 5.14 % $ 23 5.36 % |
Property, Plant And Equipment38
Property, Plant And Equipment And Jointly-Owned Facilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Schedule Of Property, Plant And Equipment | Information related to Property, Plant and Equipment as of December 31, 2015 and 2014 is detailed below: 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 Power Other PSEG Consolidated Millions 2014 Transmission and Distribution: Electric Transmission $ 5,845 $ — $ — $ 5,845 Electric Distribution 7,295 — — 7,295 Gas Transmission 89 — — 89 Gas Distribution 5,479 — — 5,479 Construction Work in Progress 1,304 — — 1,304 Plant Held for Future Use 15 — — 15 Other 401 — — 401 Total Transmission and Distribution 20,428 — — 20,428 Generation: Fossil Production — 6,964 — 6,964 Nuclear Production — 1,751 — 1,751 Nuclear Fuel in Service — 889 — 889 Other Production-Solar 521 314 — 835 Construction Work in Progress — 714 — 714 Total Generation 521 10,632 — 11,153 Other 154 100 361 615 Total $ 21,103 $ 10,732 $ 361 $ 32,196 |
Schedule Of Jointly-Owned Facilities | As of December 31, 2015 2014 Ownership Accumulated Accumulated Interest Plant Depreciation Plant Depreciation Millions PSE&G: Transmission Facilities Various $ 166 $ 72 $ 162 $ 69 Power: Coal Generating: Conemaugh 23 % $ 404 $ 154 $ 397 $ 142 Keystone 23 % $ 408 $ 163 $ 396 $ 151 Nuclear Generating: Peach Bottom 50 % $ 1,219 $ 262 $ 1,087 $ 236 Salem 57 % $ 990 $ 276 $ 916 $ 236 Nuclear Support Facilities Various $ 226 $ 60 $ 218 $ 49 Pumped Storage Facilities: Yards Creek 50 % $ 42 $ 24 $ 41 $ 24 Merrill Creek Reservoir 14 % $ 1 $ — $ 1 $ — Power holds undivided ownership interests in the jointly-owned facilities above. |
Regulatory Assets And Liabili39
Regulatory Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of Regulatory Assets | PSE&G had the following Regulatory Assets and Liabilities: As of December 31, 2015 2014 Recovery/Refund Period Millions Regulatory Assets Current New Jersey Clean Energy Program $ 142 $ 142 Annual filing for recovery (2) Stranded Costs (including $249 in 2014 related to VIEs) — 412 Through December 2015 (2) Underrecovered Electric Energy Costs—Basic Generation Service 11 — Annual filing for recovery (1) (2) Weather Normalization Clause (WNC) 10 — Annual filing for recovery (2) Solar and Energy Efficiency Recovery Charges (Green Program Recovery Charges (GPRC)) 1 13 Annual filing for recovery (1) (2) Other — 5 Various Total Current Regulatory Assets $ 164 $ 572 Noncurrent Pension and OPEB Costs $ 1,270 $ 1,265 Various Deferred Income Taxes 467 473 Various Manufactured Gas Plant (MGP) Remediation Costs 431 434 Various (2) Storm Damage Deferrals 233 245 To be determined Remediation Adjustment Charge (RAC) (Other SBC) 174 164 Through 2022 (1) (2) Conditional Asset Retirement Obligation 152 138 Various Electric Transmission Cost of Removal 133 91 Through depreciation rates GPRC 104 134 Various (1) (2) Unamortized Loss on Reacquired Debt and Debt Expense 67 74 Over remaining debt life Mark-to-Market (MTM) Contracts 63 75 Through 2017 Other 102 99 Various Total Noncurrent Regulatory Assets $ 3,196 $ 3,192 Total Regulatory Assets $ 3,360 $ 3,764 |
Schedule of Regulatory Liabilities | As of December 31, 2015 2014 Recovery/Refund Period Millions Regulatory Liabilities Current Stranded Costs (including $42 in 2015 related to VIEs) $ 64 $ — Through December 2016 (2) GPRC 36 6 Annual filing for recovery (1) (2) Societal Benefit Clause (SBC) 31 13 Various (1) (2) FERC Formula Rate True-up 19 — Annual filing for recovery (1) (2) Gas Margin Adjustment Clause 13 28 Annual filing for recovery (1) (2) Overrecovered Gas Costs —Basic Gas Supply Service 1 46 Annual filing for recovery (1) (2) WNC — 31 Annual filing for recovery (2) Deferred Income Taxes — 28 Various Overrecovered Electric Energy Costs— Basic Generation Service — 21 Annual filing for recovery (1) (2) Overrecovered Non-Utility Generation Charge (NGC) 1 13 Annual filing for recovery (1) (2) Total Current Regulatory Liabilities $ 165 $ 186 Noncurrent Electric Distribution Cost of Removal $ 122 $ 133 Through depreciation rates FERC Formula Rate True-up 49 26 Annual filing for recovery (1) (2) Stranded Costs (including $39 in 2014 related to VIEs) — 134 Through December 2016 (2) Other 4 4 Various Total Noncurrent Regulatory Liabilities $ 175 $ 297 Total Regulatory Liabilities $ 340 $ 483 (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, 2015 | |
Long-term Investments [Abstract] | |
Schedule of Long Term Investments | Long-Term Investments as of December 31, 2015 and 2014 included the following: As of December 31, 2015 2014 Millions PSE&G Life Insurance and Supplemental Benefits $ 150 $ 156 Solar Loans 175 187 Other Investments 5 5 Power Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) 119 121 Energy Holdings Lease Investments 784 836 Partnerships and Corporate Joint Ventures (Equity Method Investments) (A) — 2 Total Long-Term Investments $ 1,233 $ 1,307 (A) During the three years ended December 31, 2015 , 2014 and 2013 , the amount of dividends from these investments was $16 million , $17 million and $11 million , respectively. |
Schedule Of Net Investment In Leveraged Leases | The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2015 and 2014 , respectively. As of December 31, 2015 2014 Millions Lease Receivables (net of Non-Recourse Debt) $ 631 $ 691 Estimated Residual Value of Leased Assets 519 525 Total Investment in Rental Receivables 1,150 1,216 Unearned and Deferred Income (366 ) (380 ) Gross Investments in Leases 784 836 Deferred Tax Liabilities (724 ) (738 ) Net Investments in Leases $ 60 $ 98 |
Schedule Of Pre-Tax Income And Income Tax Effects Related To Investments In Leveraged Leases | The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows: Years Ended December 31, 2015 2014 2013 Millions Pre-Tax Income (Loss) from Leases $ 12 $ 24 $ 11 Income Tax Expense (Benefit) on Pre-Tax Income from Leases $ 5 $ 32 $ 6 |
Equity Method Investments | Equity Method Investments Power had the following equity method investments as of December 31, 2015 : Name As of December 31, 2015 Location % Owned Millions Power Keystone Fuels, LLC $ 16 PA 23% Conemaugh Fuels, LLC $ 14 PA 23% PennEast Pipeline $ 5 PA 12% Kalaeloa $ 84 HI 50% |
Financing Receivables (Tables)
Financing Receivables (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 6. Long-Term Investments , by class of customer, none of which would be considered “non-performing.” Credit Risk Profile Based on Payment Activity As of December 31, Consumer Loans 2015 2014 Millions Commercial/Industrial $ 177 $ 188 Residential 12 13 $ 189 $ 201 |
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 below, 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 and Poor's (S&P) as of December 31, 2015 As of December 31, 2015 Millions AA $ 17 BBB+ - BBB- 316 BB- 134 CCC+ 164 $ 631 |
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 $ 84 64 % 1,044 Coal BB- NRG Energy, Inc. Keystone Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Conemaugh Station Units 1 and 2 PA $ 121 17 % 1,711 Coal CCC+ NRG REMA, LLC Shawville Station Units 1, 2, 3 and 4 PA $ 113 100 % 603 Coal CCC+ NRG REMA, LLC |
Available-for-Sale Securities (
Available-for-Sale Securities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 693 $ 185 $ (13 ) $ 865 Debt Securities Government Obligations 483 8 (3 ) 488 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 685 $ 220 $ (8 ) $ 897 Debt Securities Government Obligations 430 9 (1 ) 438 Other Debt Securities 333 9 (3 ) 339 Total Debt Securities 763 18 (4 ) 777 Other Securities 106 — — 106 Total NDT Available-for-Sale Securities $ 1,554 $ 238 $ (12 ) $ 1,780 |
Schedule Of Accounts Receivable And Accounts Payable | These 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, 2015 As of December 31, 2014 Millions Accounts Receivable $ 17 $ 10 Accounts Payable $ 10 $ 2 |
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, 2015 As of December 31, 2014 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) $ 151 $ (13 ) $ 1 $ — $ 162 $ (8 ) $ 1 $ — Debt Securities Government Obligations (B) 245 (2 ) 19 (1 ) 95 — 28 (1 ) Other Debt Securities (C) 222 (7 ) 36 (3 ) 99 (1 ) 30 (2 ) Total Debt Securities 467 (9 ) 55 (4 ) 194 (1 ) 58 (3 ) NDT Available-for-Sale Securities $ 618 $ (22 ) $ 56 $ (4 ) $ 356 $ (9 ) $ 59 $ (3 ) (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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . |
Amount Of Available-For-Sale Debt Securities By Maturity Periods | The available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 16 1 - 5 years 209 6 - 10 years 200 11 - 15 years 57 16 - 20 years 49 Over 20 years 316 Total NDT Available-for-Sale Debt Securities $ 847 |
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, 2015 2014 2013 Millions Proceeds from Sales (A) $ 1,397 $ 1,448 $ 1,070 Net Realized Gains (Losses): Gross Realized Gains $ 97 $ 177 $ 112 Gross Realized Losses (37 ) (23 ) (26 ) Net Realized Gains (Losses) on NDT Fund $ 60 $ 154 $ 86 (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 | 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, 2015 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 10 $ — $ 22 Debt Securities Government Obligations 108 1 (1 ) 108 Other Debt Securities 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 As of December 31, 2014 Cost Gross Unrealized Gains Gross Unrealized Losses Fair Value Millions Equity Securities $ 12 $ 11 $ — $ 23 Debt Securities Government Obligations 89 2 — 91 Other Debt Securities 74 1 — 75 Total Debt Securities 163 3 — 166 Other Securities 2 — — 2 Total Rabbi Trust Available-for-Sale Securities $ 177 $ 14 $ — $ 191 |
Schedule Of Accounts Receivable And Accounts Payable | These 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 show in the following table. As of December 31, 2015 As of December 31, 2014 Millions Accounts Receivable $ 1 $ 1 Accounts Payable $ — $ — |
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, 2015 As of December 31, 2014 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 Obligations (B) 53 (1 ) 2 — 2 — — — Other Debt Securities (C) 46 (1 ) 9 — 24 — — — Total Debt Securities 99 (2 ) 11 — 26 — — — Rabbi Trust Available-for-Sale Securities $ 99 $ (2 ) $ 11 $ — $ 26 $ — $ — $ — (A) Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is 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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2015 . (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, 2015 . |
Amount Of Available-For-Sale Debt Securities By Maturity Periods | The Rabbi Trust available-for-sale debt securities held as of December 31, 2015 had the following maturities: Time Frame Fair Value Millions Less than one year $ 3 1 - 5 years 49 6 - 10 years 44 11 - 15 years 5 16 - 20 years 8 Over 20 years 80 Total Rabbi Trust Available-for-Sale Debt Securities $ 189 |
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, 2015 2014 2013 Millions Proceeds from Rabbi Trust Sales (A) $ 104 $ 467 $ 89 Net Realized Gains (Losses): Gross Realized Gains $ 3 $ 4 $ 4 Gross Realized Losses (2 ) (3 ) (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, 2015 As of December 31, 2014 Millions PSE&G $ 42 $ 41 Power 52 45 Other 119 105 Total Rabbi Trust Available-for-Sale Securities $ 213 $ 191 |
Goodwill And Other Intangibles
Goodwill And Other Intangibles (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Power [Member] | |
Goodwill [Line Items] | |
Expenses Related To Emissions And Renewable Energy Requirements | Such expenses for the years ended December 31, 2015 , 2014 and 2013 were as follows: Years Ended December 31, 2015 2014 2013 Millions Emissions Expense $ 13 $ 10 $ 6 Renewable Energy Expense $ 91 $ 59 $ 26 |
Asset Retirement Obligations 44
Asset Retirement Obligations (AROs) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 2014 and 2015 are presented in the following table: PSEG PSE&G Power Other Millions ARO Liability as of January 1, 2014 $ 677 $ 274 $ 400 $ 3 Liabilities Settled (2 ) (2 ) — — Liabilities Incurred 23 3 20 — Accretion Expense 30 — 30 — Accretion Expense Deferred and Recovered in Rate Base (A) 15 15 — — ARO Liability as of December 31, 2014 $ 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 (A) Not reflected as expense in Consolidated Statements of Operations |
Pension, OPEB and Savings Pla45
Pension, OPEB and Savings Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year (A) $ 5,722 $ 4,812 $ 1,638 $ 1,414 Service Cost 123 104 22 18 Interest Cost 234 234 67 69 Actuarial (Gain) Loss (B) (289 ) 838 (45 ) 210 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Benefit Obligation at End of Year (A) (B) $ 5,522 $ 5,722 $ 1,612 $ 1,638 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 5,293 $ 5,116 $ 361 $ 319 Actual Return on Plan Assets (11 ) 433 (1 ) 28 Employer Contributions 25 10 84 87 Gross Benefits Paid (268 ) (266 ) (70 ) (73 ) Fair Value of Assets at End of Year $ 5,039 $ 5,293 $ 374 $ 361 Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in the Consolidated Balance Sheets Noncurrent Assets (included in Other Special Funds) $ 14 $ 21 $ — $ — Current Accrued Benefit Cost (10 ) (10 ) (10 ) — Noncurrent Accrued Benefit Cost (487 ) (440 ) (1,228 ) (1,277 ) Amounts Recognized $ (483 ) $ (429 ) $ (1,238 ) $ (1,277 ) Additional Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulated Assets and Deferred Assets (C) Prior Service Cost $ (83 ) $ (102 ) $ (25 ) $ (39 ) Net Actuarial Loss 1,710 1,724 438 495 Total $ 1,627 $ 1,622 $ 413 $ 456 (A) Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. (B) In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013. (C) Includes $ 658 million ($ 386 million , after-tax) and $ 702 million ($ 411 million , after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2015 and 2014 , 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, 2015 and 2014 . 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 2015 2014 2015 2014 Millions Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 195 $ — $ 452 $ — Service Cost 26 20 17 13 Interest Cost 9 7 21 17 Actuarial (Gain) Loss (20 ) 42 (114 ) 107 Gross Benefits Paid — — (1 ) — Plan Amendments 1 126 — 315 Benefit Obligation at End of Year (A) $ 211 $ 195 $ 375 $ 452 Change in Plan Assets Fair Value of Assets at Beginning of Year $ 69 $ — $ — $ — Actual Return on Plan Assets (2 ) 2 — — Employer Contributions 30 67 1 — Gross Benefits Paid — — (1 ) — Fair Value of Assets at End of Year $ 97 $ 69 $ — $ — Funded Status Funded Status (Plan Assets less Benefit Obligation) $ (114 ) $ (126 ) $ (375 ) $ (452 ) Additional Amounts Recognized in the Consolidated Balance Sheets Accrued Pension Costs of Servco $ (114 ) $ (126 ) N/A N/A OPEB Costs of Servco N/A N/A (375 ) (452 ) Amounts Recognized (B) $ (114 ) $ (126 ) $ (375 ) $ (452 ) (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 Sheet. |
Components Of Net Periodic Benefit Cost | The following table provides the components of net periodic benefit cost for the years ended December 31, 2015 , 2014 and 2013 . Pension Benefits Years Ended December 31, Other Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Millions Components of Net Periodic Benefit Cost (Credit) Service Cost $ 123 $ 104 $ 116 $ 22 $ 18 21 Interest Cost 234 234 215 67 69 63 Expected Return on Plan Assets (414 ) (399 ) (348 ) (31 ) (26 ) (21 ) Amortization of Net Prior Service Cost (19 ) (18 ) (19 ) (14 ) (14 ) (14 ) Actuarial Loss 150 56 188 43 23 42 Net Periodic Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 |
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, 2015 2014 2013 2015 2014 2013 Millions PSE&G $ 40 $ (19 ) $ 91 $ 55 $ 46 $ 65 Power 21 (7 ) 43 27 20 23 Other 13 3 18 5 4 3 Total Benefit Cost (Credit) $ 74 $ (23 ) $ 152 $ 87 $ 70 $ 91 |
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 2015 2014 2015 2014 Millions Net Actuarial (Gain) Loss in Current Period $ 136 $ 803 $ (14 ) $ 208 Amortization of Net Actuarial Gain (Loss) (150 ) (56 ) (43 ) (23 ) Amortization of Prior Service Credit 19 18 14 14 Total $ 5 $ 765 $ (43 ) $ 199 |
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 2016 are as follows: Pension Benefits Other Benefits 2016 2016 Millions Actuarial (Gain) Loss $ 158 $ 40 Prior Service Cost $ (18 ) $ (14 ) |
Schedule of Assumptions Used | The following assumptions were used to determine the benefit obligations of Servco: Pension Benefits Other Benefits 2015 2014 2015 2014 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.92 % 4.50 % 4.97 % 4.60 % Rate of Compensation Increase 3.25 % 3.25 % 3.25 % 3.25 % Assumed Health Care Cost Trend Rates as of December 31 Administrative Expense 5.00 % 5.00 % Health Care Costs Immediate Rate 7.55 % 7.33 % Ultimate Rate 4.75 % 5.00 % Year Ultimate Rate Reached 2025 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ 75 $ 160 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Postretirement Benefit Obligation $ (60 ) $ (106 ) The following assumptions were used to determine the benefit obligations and net periodic benefit costs: Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-Average Assumptions Used to Determine Benefit Obligations as of December 31 Discount Rate 4.54 % 4.20 % 5.00 % 4.58 % 4.21 % 5.01 % Rate of Compensation Increase 3.61 % 3.61 % 4.61 % 3.61 % 3.61 % 4.61 % Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31 Discount Rate 4.20 % 5.00 % 4.20 % 4.21 % 5.01 % 4.20 % Expected Return on Plan Assets 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % 8.00 % Rate of Compensation Increase 3.61 % 4.61 % 4.61 % 3.61 % 4.61 % 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 7.75 % 7.40 % 7.83 % Ultimate Rate 4.75 % 5.00 % 5.00 % Year Ultimate Rate Reached 2025 2022 2021 Millions Effect of a 1% Increase in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ 12 $ 13 $ 12 Postretirement Benefit Obligation $ 194 $ 201 $ 161 Effect of a 1% Decrease in the Assumed Rate of Increase in Health Care Benefit Costs Total of Service Cost and Interest Cost $ (10 ) $ (10 ) $ (9 ) Postretirement Benefit Obligation $ (160 ) $ (165 ) $ (134 ) |
Schedule of Allocation of Plan Assets | The following tables present information about Servco's investments measured at fair value on a recurring basis as of December 31, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ — $ — $ — $ — Common Stocks (B) Commingled-United States 68 68 — — Bonds (C) Other 29 — 29 — Total $ 97 $ 68 $ 29 $ — Recurring Fair Value Measurements as of December 31, 2014 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) $ 1 $ — $ 1 $ — Common Stocks (B) Commingled-United States 48 48 — — Bonds (C) Other 20 — 20 — Total $ 69 $ 48 $ 21 $ — (A) Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). (B) Wherever possible, fair values of equity investments in commingled stock funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2015 and 2014 , including the fair value measurements and the levels of inputs used in determining those fair values. 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) $ 103 $ 102 $ 1 $ — Common Stocks (B) Commingled-United States 1,980 1,980 — — Commingled-International 987 987 — — Other 816 816 — — Bonds (C) Government (United States & Foreign) 602 — 602 — Other 906 — 906 — Private Equity (D) 19 — — 19 Total $ 5,413 $ 3,885 $ 1,509 $ 19 Recurring Fair Value Measurements as of December 31, 2014 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) $ 153 $ 92 $ 61 $ — Common Stocks (B) Commingled-United States 2,292 2,292 — — Commingled-International 1,005 1,005 — — Other 727 727 — — Bonds (C) Government (United States & Foreign) 509 — 509 — Other 943 — 943 — Private Equity (D) 25 — — 25 Total $ 5,654 $ 4,116 $ 1,513 $ 25 (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) Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. (C) Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). (D) Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3). |
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets | Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2015 and 2014 are as follows: Balance as of January 1, 2015 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2015 Millions Private Equity $ 25 $ (10 ) $ — $ 1 $ 3 $ 19 Balance as of January 1, 2014 Purchases/ (Sales) Transfer In/ (Out) Actual Return on Asset Sales Actual Return on Assets Still Held Balance as of December 31, 2014 Millions Private Equity $ 25 $ (5 ) $ — $ 3 $ 2 $ 25 |
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 as of the measurement date, December 31: As of December 31, Investments 2015 2014 Equity Securities 70 % 71 % Fixed Income Securities 28 26 Other Investments 2 3 Total Percentage 100 % 100 % 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 2015 2014 Equity Securities 71 % 70 % Fixed Income Securities 29 29 Other Investments — 1 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 2016 $ 1 $ 3 2017 2 5 2018 3 7 2019 4 8 2020 6 10 2021-2025 60 80 Total $ 76 $ 113 The following pension benefit and postretirement benefit payments are expected to be paid to plan participants. Year Pension Benefits Other Benefits Millions 2016 $ 285 $ 81 2017 295 84 2018 305 87 2019 317 91 2020 329 95 2021-2025 1,818 518 Total $ 3,349 $ 956 |
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, 2015 2014 2013 Millions PSE&G $ 22 $ 20 $ 19 Power 12 11 10 Other 5 5 4 Total Employer Matching Contributions $ 39 $ 36 $ 33 |
Commitments and Contingent Li46
Commitments and Contingent Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Commitments [Line Items] | |
Future Minimum Rental Payments | The total future minimum payments under various operating leases as of December 31, 2015 are: PSE&G Power Services Other Total Millions 2016 $ 12 $ 2 $ 13 $ 2 $ 29 2017 9 2 13 1 25 2018 8 2 13 1 24 2019 7 2 13 — 22 2020 6 3 13 — 22 Thereafter 66 33 146 — 245 Total Minimum Lease Payments $ 108 $ 44 $ 211 $ 4 $ 367 |
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 2013 2014 2015 2016 36-Month Terms Ending May 2016 May 2017 May 2018 May 2019 (A) Load (MW) 2,800 2,800 2,900 2,800 $ per MWh $92.18 $97.39 $99.54 $96.38 (A) Prices set in the 2016 BGS auction will become effective on June 1, 2016 when the 2013 BGS auction agreements expire. |
Power [Member] | |
Other Commitments [Line Items] | |
Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions | The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2015 and 2014 are shown below: As of December 31, 2015 As of December 31, 2014 Millions Face Value of Outstanding Guarantees $ 1,734 $ 1,814 Exposure under Current Guarantees $ 172 $ 273 Letters of Credit Margin Posted $ 122 $ 159 Letters of Credit Margin Received $ 192 $ 40 Cash Deposited and Received Counterparty Cash Margin Deposited $ — $ — Counterparty Cash Margin Received $ (15 ) $ (13 ) Net Broker Balance Deposited (Received) $ (5 ) $ 115 In the Event Power were to Lose its Investment Grade Rating Additional Collateral that could be Required $ 864 $ 945 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,215 $ 3,495 Additional Amounts Posted Other Letters of Credit $ 51 $ 45 |
Total Minimum Purchase Commitments | As of December 31, 2015 , the total minimum purchase requirements included in these commitments were as follows: Fuel Type Power's Share of Commitments through 2020 Millions Nuclear Fuel Uranium $ 475 Enrichment $ 394 Fabrication $ 204 Natural Gas $ 1,023 Coal $ 300 |
Insurance coverages and maximum retrospective assessments for its nuclear operations | Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows: Type and Source of Coverages Total Site Coverage Retrospective Assessments Millions Public and Nuclear Worker Liability (Primary Layer): ANI $ 375 (A) $ — Nuclear Liability (Excess Layer): Price-Anderson Act 13,113 (B) 401 Nuclear Liability Total $ 13,488 (C) $ 401 Property Damage (Primary Layer): NEIL Primary (Salem/Hope Creek and Peach Bottom) $ 1,500 $ 46 Property Damage (Excess Layers) NEIL Excess (Salem/Hope Creek and Peach Bottom) 600 (D) 6 Property Damage Total (Per Site) $ 2,100 $ 52 Accidental Outage: NEIL I (Peach Bottom) $ 245 (E) $ 8 NEIL I (Salem) 281 (E) 9 NEIL I (Hope Creek) 490 (E) 7 Replacement Power Total $ 1,016 $ 24 (A) The primary limit for Public Liability is a per site aggregate limit with no potential for 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) Limit of liability under the Price-Anderson Act for each nuclear incident. (D) For nuclear event property limits in excess of $1.5 billion , Power participates in a $600 million nuclear event Blanket Limit Policy. The blanket limit policy is shared with Exelon Generation and covers the following facilities: Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 Peach Bottom, Salem and Hope Creek. This limit is not subject to reinstatement in the event of a loss. Participation in this program reduces Power’s premium and the associated potential assessment. In addition, for non-nuclear event limits in excess of $1.5 billion, Power maintains a $600 million limit shared by the Salem and Hope Creek facilities. Exelon maintains a $600 million non-nuclear event limit shared by Peach Bottom, Braidwood, Byron, Clinton, Dresden, LaSalle, Limerick, Oyster Creek, Quad Cities, and the TMI-1 facilities. (E) Peach Bottom 2 and 3 have an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem 1 and 2 have an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. |
Schedule Of Consolidated Debt (
Schedule Of Consolidated Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | Long-Term Debt As of December 31, Maturity 2015 2014 Millions PSEG (Parent) Term Loan: Variable 2017 $ 500 $ — Total Term Loan 500 — Fair Value of Swaps (A) 6 22 Amounts Due Within One Year (6 ) (8 ) Unamortized Discount Related to Debt Exchange (B) — (8 ) Total Long-Term Debt of PSEG (Parent) $ 500 $ 6 ` As of December 31, Maturity 2015 2014 Millions PSE&G First and Refunding Mortgage Bonds (C): 6.75% 2016 $ 171 $ 171 9.25% 2021 134 134 8.00% 2037 7 7 5.00% 2037 8 8 Total First and Refunding Mortgage Bonds 320 320 Pollution Control Bonds (C): Floating Rate (D) 2033 50 50 Floating Rate (D) 2046 50 50 Total Pollution Control Bonds 100 100 Medium-Term Notes (MTNs) (C): 2.70% 2015 — 300 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 2.38% 2023 500 500 3.75% 2024 250 250 3.15% 2024 250 250 3.05% 2024 250 250 3.00% 2025 350 — 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 — 4.15% 2045 250 — Total MTNs 6,459 5,909 Principal Amount Outstanding 6,879 6,329 Amounts Due Within One Year (171 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (58 ) (54 ) Total Long-Term Debt of PSE&G (excluding Transition Funding and Transition Funding II) $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Transition Funding (PSE&G) Securitization Bonds: 6.89% 2014-2015 $ — $ 251 Principal Amount Outstanding — 251 Amounts Due Within One Year — (251 ) Total Securitization Debt of Transition Funding — — Transition Funding II (PSE&G) Securitization Bonds: 4.57% 2014-2015 — 8 Principal Amount Outstanding — 8 Amounts Due Within One Year — (8 ) Total Securitization Debt of Transition Funding II — — Total Long-Term Debt of PSE&G $ 6,650 $ 5,975 As of December 31, Maturity 2015 2014 Millions Power Senior Notes: 5.50% 2015 $ — $ 300 5.32% 2016 303 303 2.75% 2016 250 250 2.45% 2018 250 250 5.13% 2020 406 406 4.15% 2021 250 250 4.30% 2023 250 250 8.63% 2031 500 500 Total Senior Notes 2,209 2,509 Pollution Control Notes: Floating Rate (D) 2019 44 44 Total Pollution Control Notes 44 44 Principal Amount Outstanding 2,253 2,553 Amounts Due Within One Year (553 ) (300 ) Net Unamortized Discount and Debt Issuance Costs (16 ) (19 ) Total Long-Term Debt of Power $ 1,684 $ 2,234 (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 15. Financial Risk Management Activities . (B) In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The remaining deferred amount of $3 million as of December 31, 2015 is reflected as an offset to Long-Term Debt due within one year on PSEG’s Consolidated Balance Sheets. (C) Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. (D) The Pollution Control Financing Authority of Salem County bonds 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, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing the PEDFA bond which expires on November 30, 2019. |
Aggregate Principal Amounts Of Maturities | The aggregate principal amounts of maturities for each of the five years following December 31, 2015 are as follows: Energy Holdings Year PSEG (Parent) PSE&G Power Non-Recourse Debt Total Millions 2016 $ — $ 171 $ 553 $ 7 $ 731 2017 500 — — — 500 2018 — 750 250 — 1,000 2019 — 500 44 — 544 2020 — 259 406 — 665 Thereafter — 5,199 1,000 — 6,199 Total $ 500 $ 6,879 $ 2,253 $ 7 $ 9,639 |
Short-Term Liquidity | Our total credit facilities and available liquidity as of December 31, 2015 were as follows: As of December 31, 2015 Company/Facility Total Facility Usage (D) Available Liquidity Expiration Date Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 10 $ 490 Apr 2019 Commercial Paper (CP) Support/Funding/Letters of Credit 5-year Credit Facility (A) 500 211 289 Apr 2020 CP Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 221 $ 779 PSE&G 5-year Credit Facility (B) $ 600 $ 167 $ 433 Apr 2020 CP Support/Funding/Letters of Credit Total PSE&G $ 600 $ 167 $ 433 Power 5-year Credit Facility $ 1,600 $ 161 $ 1,439 Apr 2019 Funding/Letters of Credit 5-year Credit Facility (C) 1,000 3 997 Apr 2020 Funding/Letters of Credit Total Power $ 2,600 $ 164 $ 2,436 Total $ 4,200 $ 552 $ 3,648 (A) PSEG facility will be reduced by $23 million in April 2016 and $12 million in March 2018. (B) PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018. (C) Power facility will be reduced by $48 million in April 2016 and $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, 2015 , $211 million and $153 million , respectively, were outstanding. The weighted average interest rates on PSEG's and PSE&G's Commercial Paper Programs were 0.96% and 0.91% , respectively, at December 31, 2015 . |
Estimated Fair Values | December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value Millions Long-Term Debt: PSEG (Parent) (A) $ 503 $ 506 $ 14 $ 22 PSE&G (B) 6,821 7,235 6,275 6,912 Transition Funding (PSE&G) (B) — — 251 261 Transition Funding II (PSE&G) (B) — — 8 8 Power - Recourse Debt (B) 2,237 2,508 2,534 2,930 Energy Holdings: Project Level, Non-Recourse Debt (C) 7 7 16 16 $ 9,568 $ 10,256 $ 9,098 $ 10,149 (A) Fair value includes a $500 million floating rate term loan in 2015 and net offsets in 2015 and 2014 to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. 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. 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 is valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Schedule Of Consolidated Capi48
Schedule Of Consolidated Capital Stock (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Class of Stock Disclosures [Abstract] | |
Schedule Of Consolidated Capital Stock | As of December 31, Outstanding Shares Book Value 2015 2014 2015 2014 Millions PSEG Common Stock (no par value) (A) Authorized 1,000,000,000 shares 505,282,421 505,836,592 $ 4,244 $ 4,241 (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 2015 or 2014 . 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, 2015 . |
Financial Risk Management Act49
Financial Risk Management Activities (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure Financial Risk Management Activities [Abstract] | |
Schedule Of Derivative Transactions Designated And Effective As Cash Flow Hedges | As of December 31, 2015 and 2014 , the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows: As of December 31, 2015 2014 Millions Fair Value of Cash Flow Hedges $ — $ 18 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ — $ 10 |
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, 2015 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts 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 As of December 31, 2014 Power (A) PSE&G (A) PSEG (A) Consolidated Cash Flow Hedges Not Designated Not Designated Fair Value Hedges Balance Sheet Location Energy- Related Contracts Energy- Related Contracts Netting (B) Total Power Energy- Related Contracts Interest Rate Swaps Total Derivatives Millions Derivative Contracts Current Assets $ 18 $ 597 $ (408 ) $ 207 $ 18 $ 15 $ 240 Noncurrent Assets — 171 (109 ) 62 8 7 77 Total Mark-to-Market Derivative Assets $ 18 $ 768 $ (517 ) $ 269 $ 26 $ 22 $ 317 Derivative Contracts Current Liabilities $ — $ (568 ) $ 436 $ (132 ) $ — $ — $ (132 ) Noncurrent Liabilities — (138 ) 105 (33 ) — — (33 ) Total Mark-to-Market Derivative (Liabilities) $ — $ (706 ) $ 541 $ (165 ) $ — $ — $ (165 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 18 $ 62 $ 24 $ 104 $ 26 $ 22 $ 152 (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, 2015 and 2014 . 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 in the Consolidated Balance Sheets. As of December 31, 2015 and 2014 , net cash collateral (received) paid of $(55) million and $24 million , respectively, were netted against the corresponding net derivative contract positions. Of the $(55) million as of December 31, 2015 , $(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. Of the $24 million as of December 31, 2014 , cash collateral of $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 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, 2015 , 2014 and 2013 : 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) Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) Derivatives in Cash Flow Hedging Relationships Years Ended December 31, Years Ended December 31, Years Ended December 31, 2015 2014 2013 2015 2014 2013 2015 2014 2013 Millions Millions PSEG Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Interest Rate Swaps (A) — — — Interest Expense — — (1 ) — — — Total PSEG $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 12 $ — $ — $ (1 ) Power Energy-Related Contracts $ 3 $ 12 $ (4 ) Operating Revenues $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) Total Power $ 3 $ 12 $ (4 ) $ 20 $ (9 ) $ 13 $ — $ — $ (1 ) (A) Includes amounts for PSEG parent. |
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, 2013 $ (4 ) $ (2 ) Gain Recognized in AOCI 12 7 Plus: Loss Reclassified into Income 9 5 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 $ — $ — |
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 normal purchases and sales for the years ended December 31, 2015 , 2014 and 2013 : 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, 2015 2014 2013 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ 412 $ (348 ) $ (128 ) Energy-Related Contracts Energy Costs (8 ) 32 106 Total PSEG and Power $ 404 $ (316 ) $ (22 ) |
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, 2015 and 2014 : Type Notional Total PSEG Power PSE&G Millions As of December 31, 2015 Natural Gas Dth 201 — 168 33 Electricity MWh 299 — 299 — Financial Transmission Rights (FTRs) MWh 23 — 23 — Interest Rate Swaps U.S. Dollars 550 550 — — As of December 31, 2014 Natural Gas Dth 274 — 216 58 Electricity MWh 310 — 310 — FTRs MWh 15 — 15 — Interest Rate Swaps U.S. Dollars 850 850 — — |
Schedule Providing Credit Risk From Others, Net Of Collateral | . The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2015 . It further delineates that exposure by the credit rating of the counterparties and 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—External Rating $ 451 $ 175 $ 276 1 $ 160 (A) Non-Investment Grade—External Rating 24 — 24 — — Investment Grade—No External Rating 12 1 11 — — Non-Investment Grade—No External Rating 1 — 1 — — Total $ 488 $ 176 $ 312 1 $ 160 (A) Represents net exposure with PSE&G. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and December 31, 2014 , 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 Power and PSE&G. 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 22 $ — $ 22 $ — $ — Debt Securities—Govt Obligations $ 108 $ — $ — $ 108 $ — Debt Securities—Other $ 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—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 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—Govt Obligations $ 488 $ — $ — $ 488 $ — Debt Securities—Other $ 359 $ — $ — $ 359 $ — Other Securities $ 42 $ — $ 42 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 26 $ — $ — $ 26 $ — Debt Securities—Other $ 20 $ — $ — $ 20 $ — Other Securities $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (92 ) $ 553 $ — $ (644 ) $ (1 ) Recurring Fair Value Measurements as of December 31, 2014 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) $ 295 $ (517 ) $ — $ 774 $ 38 Interest Rate Swaps (C) $ 22 $ — $ — $ 22 $ — NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 23 $ — $ 23 $ — $ — Debt Securities—Govt Obligations $ 91 $ — $ — $ 91 $ — Debt Securities—Other $ 75 $ — $ — $ 75 $ — Other Securities $ 2 $ — $ — $ 2 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) PSE&G Assets: Cash Equivalents (A) $ 294 $ — $ 294 $ — $ — Derivative Contracts: Energy Related Contracts (B) $ 26 $ — $ — $ — $ 26 Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 20 $ — $ — $ 20 $ — Debt Securities—Other $ 16 $ — $ — $ 16 $ — Other Securities $ — $ — $ — $ — $ — Power Assets: Derivative Contracts: Energy-Related Contracts (B) $ 269 $ (517 ) $ — $ 774 $ 12 NDT Fund (D) Equity Securities $ 897 $ — $ 896 $ 1 $ — Debt Securities—Govt Obligations $ 438 $ — $ — $ 438 $ — Debt Securities—Other $ 339 $ — $ — $ 339 $ — Other Securities $ 106 $ — $ 106 $ — $ — Rabbi Trust (D) Equity Securities—Mutual Funds $ 5 $ — $ 5 $ — $ — Debt Securities—Govt Obligations $ 21 $ — $ — $ 21 $ — Debt Securities—Other $ 18 $ — $ — $ 18 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (B) $ (165 ) $ 541 $ — $ (705 ) $ (1 ) (A) Represents money market mutual funds. (B) 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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 Consolidated Balance Sheets. 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. As of December 31, 2014 , net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014 , $(12) million was netted against assets and $36 million was netted against liabilities. |
Schedule Of Quantitative Information About Level 3 Fair Value Measurements | The following tables provide detail surrounding significant Level 3 valuations as of December 31, 2015 and 2014 . 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/dekatherm Total PSE&G $ 13 $ (11 ) Power Electricity Electric Load Contracts $ 11 $ (1 ) Discounted Cash flow Historic Load Variability 0% to +10% Other Various (A) 1 — Total Power $ 12 $ (1 ) Total PSEG $ 25 $ (12 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value as of December 31, 2014 Valuation Technique(s) Significant Unobservable Input Range Assets (Liabilities) Millions PSE&G Gas Natural Gas Supply Contract $ 26 $ — Discounted Cash Flow Transportation Costs $0.70 to $1/dekatherm Total PSE&G $ 26 $ — Power Electricity Electric Load Contracts 12 (1 ) Discounted Cash Flow Historic Load Variability 0% to +10% Other Various (B) — — Total Power $ 12 $ (1 ) Total PSEG $ 38 $ (1 ) (A) Includes long-term electric capacity positions which were immaterial as of December 31, 2015 . (B) Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014 . |
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, 2015 and 2014 , respectively, follows: 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 Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Year Ended December 31, 2014 Total Gains or (Losses) Realized/Unrealized Description Balance as of January 1, 2014 Included in Income (A) Included in Regulatory Assets/ Liabilities (B) Purchases, (Sales) Issuances (Settlements) (C) Transfers In (Out) (D) Balance as of December 31, 2014 Millions PSEG Net Derivative Assets (Liabilities) $ 88 $ (31 ) $ (68 ) $ — $ 51 $ (3 ) $ 37 PSE&G Net Derivative Assets (Liabilities) $ 94 $ — $ (68 ) $ — $ — $ — $ 26 Power Net Derivative Assets (Liabilities) $ (6 ) $ (31 ) $ — $ — $ 51 $ (3 ) $ 11 (A) PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $20 million and $(31) million in Operating Income in 2015 and 2014 , respectively. The $20 million in Operating Income in 2015 is realized. Of the $(31) million in Operating Income in 2014 , $22 million is unrealized. (B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. (C) Represents $(20) million and $51 million in settlements for derivative contracts in 2015 and 2014 , respectively. (D) During the year ended December 31, 2014 , $(3) million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy. |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Accrual Adjustments | 2015 2014 2013 Millions Compensation Cost included in Operation and Maintenance Expense $ 34 $ 32 $ 32 Income Tax Benefit Recognized in Consolidated Statement of Operations $ 14 $ 13 $ 13 |
Stock Options Activity | Changes in stock options for 2015 are summarized as follows: Options Weighted Average Exercise Price Weighted Average Remaining Years Contractual Term Aggregate Intrinsic Value Outstanding as of January 1, 2015 2,075,850 $ 35.35 Exercised 368,600 $ 32.37 Canceled/Forfeited — $ — Outstanding as of December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 Exercisable at December 31, 2015 1,707,250 $ 36.00 2.8 $ 8,120,788 |
Activity For Options Exercised | Activity for options exercised for the years ended December 31, 2015 , 2014 and 2013 is shown below: 2015 2014 2013 Millions Total Intrinsic Value of Options Exercised $ 3 $ 4 $ 1 Cash Received from Options Exercised $ 12 $ 16 $ 7 Tax Benefit Realized from Options Exercised $ — $ — $ — |
Restricted Stock Units Activity | Changes in restricted stock units for the year ended December 31, 2015 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, 2015 1,069,029 $ 32.49 Granted 318,805 $ 39.65 Vested 963,387 $ 33.73 Canceled/Forfeited 15,940 $ 37.28 Non-vested as of December 31, 2015 408,507 $ 34.95 1.1 $ 15,805,175 |
Performance Units Information | Changes in performance share units for the year ended December 31, 2015 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, 2015 765,633 $ 36.86 Granted 337,585 $ 41.32 Vested 655,201 $ 36.82 Canceled/Forfeited 44,056 $ 38.97 Non-vested as of December 31, 2015 403,961 $ 40.42 1.6 $ 15,629,251 |
Other Income and Deductions (Ta
Other Income and Deductions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Other Income and Deductions Disclosure [Abstract] | |
Schedule Of Other Income | Other Income PSE&G Power Other (A) Consolidated Total Millions 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 Year Ended December 31, 2013 NDT Fund Gains, Interest, Dividend and Other Income $ — $ 152 $ — $ 152 Allowance for Funds Used During Construction 24 — — 24 Solar Loan Interest 23 — — 23 Other 7 2 5 14 Total Other Income $ 54 $ 154 $ 5 $ 213 |
Schedule Of Other Deductions | Other Deductions PSE&G Power Other (A) Consolidated Total Millions 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 Year Ended December 31, 2013 NDT Fund Realized Losses and Expenses $ — $ 34 $ — $ 34 Other 3 15 2 20 Total Other Deductions $ 3 $ 49 $ 2 $ 54 (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, 2015 | |
Income Taxes [Line Items] | |
Unrecognized Tax Benefits | 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: 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 2013 PSEG PSE&G Power Energy Holdings Millions Total Amount of Unrecognized Tax Benefits as of January 1, 2013 $ 402 $ 163 $ 134 $ 101 Increases as a Result of Positions Taken in a Prior Period 83 39 33 11 Decreases as a Result of Positions Taken in a Prior Period (30 ) (9 ) (19 ) (2 ) Increases as a Result of Positions Taken during the Current Period 23 15 8 — 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 — — — — Total Amount of Unrecognized Tax Benefits as of December 31, 2013 $ 478 $ 208 $ 156 $ 110 Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits (320 ) (177 ) (105 ) (37 ) Regulatory Asset—Unrecognized Tax Benefits (30 ) (30 ) — — Total Amount of Unrecognized Tax Benefits that if Recognized, would Impact the Effective Tax Rate (including Interest and Penalties) $ 128 $ 1 $ 51 $ 73 |
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, 2015 2014 2013 Millions PSE&G $ 20 $ 15 $ 6 Power 6 9 (2 ) Energy Holdings 40 45 44 Total $ 66 $ 69 $ 48 |
Possible Decrease In Total Unrecognized Tax Benefits Including Interest | It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows: Possible Decrease in Total Unrecognized Tax Benefits Over the next 12 Months Millions PSEG $ 158 PSE&G $ 102 Power $ 42 |
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 2011-2014 N/A N/A New Jersey 2006-2014 2006-2014 N/A Pennsylvania 2006-2014 2006-2014 N/A Connecticut 2002-2014 N/A N/A Texas 2007-2014 N/A N/A California 2003-2014 N/A N/A New York 2011-2014 N/A 2011-2014 |
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 2015 2014 2013 Millions Net Income $ 1,679 $ 1,518 $ 1,243 Income Taxes: Operating Income: Current Expense: Federal $ 243 $ 335 $ 487 State 85 58 42 Total Current 328 393 529 Deferred Expense: Federal 540 262 147 State 104 260 118 Total Deferred 644 522 265 Investment Tax Credit (ITC) 29 23 18 Total Income Taxes $ 1,001 $ 938 $ 812 Pre-Tax Income $ 2,680 $ 2,456 $ 2,055 Tax Computed at Statutory Rate 35% $ 938 $ 860 $ 719 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 129 145 108 Uncertain Tax Positions 7 (9 ) 10 Manufacturing Deduction (10 ) (16 ) (9 ) NDT Fund 7 14 12 Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (13 ) (14 ) (9 ) Audit Settlement — (12 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (4 ) (17 ) (5 ) Sub-Total 63 78 93 Total Income Tax Provision $ 1,001 $ 938 $ 812 Effective Income Tax Rate 37.4 % 38.2 % 39.5 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for PSEG: As of December 31, PSEG 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 11 Noncurrent OPEB $ 256 $ 269 Related to Uncertain Tax Position 160 160 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 443 $ 484 Total Assets $ 443 $ 495 Liabilities: Current (net) Securitization $ — $ 163 Other — 10 Total Current Liabilities (net) $ — $ 173 Noncurrent: Plant-Related Items $ 6,174 $ 5,422 New Jersey Corporate Business Tax 615 535 Leasing Activities 612 623 Pension Costs 218 219 AROs and NDT Fund 393 419 Taxes Recoverable Through Future Rate (net) 191 196 Other 244 240 Total Noncurrent Liabilities $ 8,447 $ 7,654 Total Liabilities $ 8,447 $ 7,827 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 11 Net Current Deferred Income Tax Liabilities $ — $ 173 Net Noncurrent Deferred Income Tax Liabilities $ 8,004 $ 7,170 ITC 162 133 Net Total Noncurrent Deferred Income Taxes and ITC $ 8,166 $ 7,303 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. |
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 2015 2014 2013 Millions Net Income $ 787 $ 725 $ 612 Income Taxes: Operating Income: Current Expense: Federal $ 32 $ 124 $ 183 State 52 16 — Total Current 84 140 183 Deferred Expense: Federal 325 214 101 State 52 84 92 Total Deferred 377 298 193 ITC 9 11 5 Total Income Taxes $ 470 $ 449 $ 381 Pre-Tax Income $ 1,257 $ 1,174 $ 993 Tax Computed at Statutory Rate 35% $ 440 $ 411 $ 348 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 67 65 59 Uncertain Tax Positions (14 ) — — Plant-Related Items (20 ) (13 ) (14 ) Tax Credits (6 ) (7 ) (6 ) Audit Settlement — 1 — Other 3 (8 ) (6 ) Sub-Total 30 38 33 Total Income Tax Provision $ 470 $ 449 $ 381 Effective Income Tax Rate 37.4 % 38.2 % 38.4 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for PSE&G: As of December 31, PSE&G 2015 2014 Millions Deferred Income Taxes Assets: Current (net) $ — $ 24 Noncurrent: OPEB $ 164 $ 173 Securitization-Overcollection 27 55 Total Noncurrent Assets $ 191 $ 228 Total Assets $ 191 $ 252 Liabilities: Current (net) Securitization $ — $ 163 Other — 2 Total Current Liabilities (net) $ — $ 165 Noncurrent: Plant-Related Items $ 4,435 $ 3,869 New Jersey Corporate Business Tax 312 268 Conservation Costs 40 48 Pension Costs 262 269 Taxes Recoverable Through Future Rate (net) 191 196 Other 54 84 Total Noncurrent Liabilities $ 5,294 $ 4,734 Total Liabilities $ 5,294 $ 4,899 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ 24 Net Current Deferred Income Tax Liabilities $ — $ 165 Net Noncurrent Deferred Income Tax Liabilities $ 5,103 $ 4,506 ITC 78 69 Net Total Noncurrent Deferred Income Taxes and ITC $ 5,181 $ 4,575 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. PSEG has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards . |
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 2015 2014 2013 Millions Net Income $ 856 $ 760 $ 644 Income Taxes: Operating Income: Current Expense: Federal $ 220 $ 231 $ 262 State 30 39 40 Total Current 250 270 302 Deferred Expense: Federal 189 163 69 State 52 48 35 Total Deferred 241 211 104 ITC 20 10 13 Total Income Taxes $ 511 $ 491 $ 419 Pre-Tax Income $ 1,367 $ 1,251 $ 1,063 Tax Computed at Statutory Rate 35% $ 478 $ 438 $ 372 Increase (Decrease) Attributable to Flow-Through of Certain Tax Adjustments: State Income Taxes (net of federal income tax) 59 58 51 Manufacturing Deduction (10 ) (16 ) (10 ) NDT Fund 7 15 12 Tax Credits (7 ) (6 ) (2 ) Uncertain Tax Positions 22 (8 ) 3 Audit Settlement — (4 ) — Nuclear Decommissioning Tax Carryback (33 ) — — Other (5 ) 14 (7 ) Sub-Total 33 53 47 Total Income Tax Provision $ 511 $ 491 $ 419 Effective Income Tax Rate 37.4 % 39.2 % 39.4 % |
Deferred Income Taxes | The following is an analysis of deferred income taxes for Power: As of December 31, Power 2015 2014 Millions Deferred Income Taxes Assets: Current $ — $ — Noncurrent: Pension Costs $ 56 $ 52 Contractual Liabilities & Environmental Costs 18 18 Related to Uncertain Tax Positions 47 23 Other — 70 Total Noncurrent Assets $ 121 $ 163 Total Assets $ 121 $ 163 Liabilities: Current (net) $ — $ 43 Noncurrent: Plant-Related Items $ 1,736 $ 1,552 New Jersey Corporate Business Tax 243 192 AROs and NDT Fund 395 420 Other 10 — Total Noncurrent Liabilities $ 2,384 $ 2,164 Total Liabilities $ 2,384 $ 2,207 Summary of Accumulated Deferred Income Taxes: Net Current Deferred Income Tax Assets $ — $ — Net Current Deferred Income Tax Liabilities $ — $ 43 Net Noncurrent Deferred Income Tax Liabilities $ 2,263 $ 2,001 ITC 84 64 Net Total Noncurrent Deferred Income Taxes and ITC $ 2,347 $ 2,065 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 has early adopted the accounting standards update Balance Sheet Classification of Deferred Taxes as of December 31, 2015. This standard requires noncurrent classification of all deferred tax assets and liabilities. For further details refer to Note 2. Recent Accounting Standards. |
Accumulated Other Comprehensi54
Accumulated Other Comprehensive Income (Loss), Net of Tax Accumulated Other Comprehensive Income (Loss), Net of Tax (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2012 $ 7 $ (485 ) $ 90 $ (388 ) Other Comprehensive Income before Reclassifications (2 ) 210 91 299 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (7 ) 37 (36 ) (6 ) Net Current Period Other Comprehensive Income (Loss) (9 ) 247 55 293 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 ) 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, 2012 $ 9 $ (422 ) $ 85 $ (328 ) Other Comprehensive Income before Reclassifications (2 ) 185 93 276 Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) (8 ) 33 (36 ) (11 ) Net Current Period Other Comprehensive Income (Loss) (10 ) 218 57 265 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 ) |
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, 2013 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 $ 13 $ (5 ) $ 8 Interest Rate Swaps Interest Expense (1 ) — (1 ) Total Cash Flow Hedges 12 (5 ) 7 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 11 (4 ) 7 Amortization of Actuarial Loss O&M Expense (75 ) 31 (44 ) Total Pension and OPEB Plans (64 ) 27 (37 ) Available-for-Sale Securities Realized Gains Other Income 116 (59 ) 57 Realized Losses Other Deductions (29 ) 14 (15 ) Other-Than-Temporary Impairments (OTTI) OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 75 (39 ) 36 Total $ 23 $ (17 ) $ 6 Power Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) to Income Statement Year Ended December 31, 2013 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 $ 13 $ (5 ) $ 8 Total Cash Flow Hedges 13 (5 ) 8 Pension and OPEB Plans Amortization of Prior Service (Cost) Credit O&M Expense 9 (4 ) 5 Amortization of Actuarial Loss O&M Expense (64 ) 26 (38 ) Total Pension and OPEB Plans (55 ) 22 (33 ) Available-for-Sale Securities Realized Gains Other Income 112 (57 ) 55 Realized Losses Other Deductions (26 ) 13 (13 ) OTTI OTTI (12 ) 6 (6 ) Total Available-for-Sale Securities 74 (38 ) 36 Total $ 32 $ (21 ) $ 11 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 ) 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 ) |
Earnings Per Share (EPS) and 55
Earnings Per Share (EPS) and Dividends (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 Basic Diluted Basic Diluted Basic Diluted EPS Numerator: (Millions) Net Income $ 1,679 $ 1,679 $ 1,518 $ 1,518 $ 1,243 $ 1,243 EPS Denominator: (Millions) Weighted Average Common Shares Outstanding 505 505 506 506 506 506 Effect of Stock Based Compensation Awards — 3 — 2 — 2 Total Shares 505 508 506 508 506 508 EPS: Net Income $ 3.32 $ 3.30 $ 3.00 $ 2.99 $ 2.46 $ 2.45 |
Dividend Payments On Common Stock | Years Ended December 31, Dividend Payments on Common Stock 2015 2014 2013 Per Share $ 1.56 $ 1.48 $ 1.44 in Millions $ 789 $ 748 $ 728 |
Financial Information By Busi56
Financial Information By Business Segments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Financial Information By Business Segments | 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 PSE&G Power Other (A) Eliminations (B) Consolidated Total Millions Year Ended December 31, 2013 Operating Revenues $ 6,655 $ 5,063 $ 52 $ (1,802 ) $ 9,968 Depreciation and Amortization 872 273 33 — 1,178 Operating Income (Loss) 1,235 1,070 (6 ) — 2,299 Income from Equity Method Investments — 16 (5 ) — 11 Interest Income 25 1 25 (22 ) 29 Interest Expense 293 116 15 (22 ) 402 Income (Loss) before Income Taxes 993 1,063 (1 ) — 2,055 Income Tax Expense (Benefit) 381 419 12 — 812 Net Income (Loss) 612 644 (13 ) — 1,243 Gross Additions to Long-Lived Assets $ 2,175 $ 609 $ 27 $ — $ 2,811 As of December 31, 2013 Total Assets $ 19,689 $ 11,991 $ 4,025 $ (3,225 ) $ 32,480 Investments in Equity Method Subsidiaries $ — $ 123 $ 3 $ — $ 126 (A) Includes amounts applicable to Energy Holdings and PSEG LI (for 2015 and 2014), 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 23. Related-Party Transactions . |
Related-Party Transactions (Tab
Related-Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 2015 2014 2013 Millions Billings from Affiliates: Billings from Power primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Administrative Billings from Services (B) 274 248 255 Total Billings from Affiliates $ 1,904 $ 2,019 $ 2,052 |
Schedule Of Related Party Transactions, Payables | Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivables from PSEG (C) $ 222 $ 274 Payable to Power (A) $ 212 $ 313 Payable to Services (B) 80 66 Accounts Payable—Affiliated Companies $ 292 $ 379 Working Capital Advances to Services (D) $ 33 $ 33 Long-Term Accrued Taxes Payable $ 109 $ 116 |
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 2015 2014 2013 Millions Billings to Affiliates: Billings to PSE&G primarily through BGS and BGSS (A) $ 1,630 $ 1,771 $ 1,797 Billings from Affiliates: Administrative Billings from Services (B) $ 187 $ 165 $ 178 |
Schedule Of Related Party Transactions, Receivables | Years Ended December 31, Related Party Transactions 2015 2014 Millions Receivable from PSE&G (A) $ 212 $ 313 Receivable from PSEG (C) 64 — Accounts Receivable—Affiliated Companies $ 276 $ 313 Payable to Services (B) $ 33 $ 23 Payable to PSEG (C) — 95 Accounts Payable—Affiliated Companies $ 33 $ 118 Short-Term Loan due (to) from Affiliate (E) $ 363 $ 584 Working Capital Advances to Services (D) $ 17 $ 17 Long-Term Accrued Taxes Payable $ 35 $ 41 (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. (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, 2015 | |
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, 2015 2014 2015 2014 2015 2014 2015 2014 PSEG Consolidated: Millions, except per share data Operating Revenues $ 3,135 $ 3,223 $ 2,314 $ 2,249 $ 2,688 $ 2,641 $ 2,278 $ 2,773 Operating Income $ 1,048 $ 705 $ 568 $ 365 $ 814 $ 746 $ 532 $ 807 Net Income (Loss) $ 586 $ 386 $ 345 $ 212 $ 439 $ 444 $ 309 $ 476 Earnings Per Share: Basic: Net Income (Loss) $ 1.16 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.88 $ 0.61 $ 0.94 Diluted: Net Income (Loss) $ 1.15 $ 0.76 $ 0.68 $ 0.42 $ 0.87 $ 0.87 $ 0.60 $ 0.94 Weighted Average Common Shares Outstanding: Basic 506 506 506 506 505 506 505 506 Diluted 508 508 508 508 508 507 508 508 |
PSE&G [Member] | |
Schedule of Quarterly Data [Line Items] | |
Schedule Of Selected Quarterly Data | Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 PSE&G: Millions Operating Revenues $ 2,002 $ 2,145 $ 1,466 $ 1,435 $ 1,766 $ 1,655 $ 1,402 $ 1,531 Operating Income $ 451 $ 411 $ 320 $ 291 $ 404 $ 383 $ 287 $ 308 Net Income (Loss) $ 242 $ 214 $ 167 $ 151 $ 222 $ 200 $ 156 $ 160 |
Power [Member] | |
Schedule of Quarterly Data [Line Items] | |
Schedule Of Selected Quarterly Data | Quarter Ended March 31, June 30, September 30, December 31, 2015 2014 2015 2014 2015 2014 2015 2014 Power: Millions Operating Revenues $ 1,725 $ 1,700 $ 1,025 $ 986 $ 1,096 $ 1,138 $ 1,082 $ 1,610 Operating Income $ 584 $ 282 $ 228 $ 67 $ 391 $ 353 $ 227 $ 507 Net Income (Loss) $ 335 $ 164 $ 166 $ 54 $ 206 $ 222 $ 149 $ 320 |
Guarantees of Debt (Tables)
Guarantees of Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Subsidiary or Equity Method Investee [Line Items] | |
Schedule Of Financial Statements Of Guarantors | The following table presents financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013 . 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 As of December 31, 2014 Current Assets $ 4,263 $ 2,037 $ 150 $ (4,091 ) $ 2,359 Property, Plant and Equipment, net 81 6,265 1,169 — 7,515 Investment in Subsidiaries 4,516 120 — (4,636 ) — Noncurrent Assets 269 1,952 137 (195 ) 2,163 Total Assets $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 Current Liabilities $ 883 $ 3,606 $ 786 $ (4,091 ) $ 1,184 Noncurrent Liabilities 454 2,442 360 (195 ) 3,061 Long-Term Debt 2,234 — — — 2,234 Member’s Equity 5,558 4,326 310 (4,636 ) 5,558 Total Liabilities and Member’s Equity $ 9,129 $ 10,374 $ 1,456 $ (8,922 ) $ 12,037 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 Guarantor Subsidiaries Other Subsidiaries Consolidating Adjustments Total Millions Year Ended December 31, 2013 Operating Revenues $ — $ 5,022 $ 190 $ (149 ) $ 5,063 Operating Expenses 23 3,945 174 (149 ) 3,993 Operating Income (Loss) (23 ) 1,077 16 — 1,070 Equity Earnings (Losses) of Subsidiaries 684 (5 ) 16 (679 ) 16 Other Income 35 157 — (38 ) 154 Other Deductions (14 ) (35 ) — — (49 ) Other-Than-Temporary Impairments — (12 ) — — (12 ) Interest Expense (93 ) (42 ) (19 ) 38 (116 ) Income Tax Benefit (Expense) 55 (474 ) — — (419 ) Net Income (Loss) $ 644 $ 666 $ 13 $ (679 ) $ 644 Comprehensive Income (Loss) $ 909 $ 713 $ 11 $ (724 ) $ 909 Year Ended December 31, 2013 Net Cash Provided By (Used In) Operating Activities $ 288 $ 1,503 $ 82 $ (526 ) $ 1,347 Net Cash Provided By (Used In) Investing Activities $ (395 ) $ (1,092 ) $ (71 ) $ 697 $ (861 ) Net Cash Provided By (Used In) Financing Activities $ 107 $ (412 ) $ (11 ) $ (171 ) $ (487 ) |
Organization, Basis Of Presen60
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
TEFA | $ 0 | $ 0 | $ 68 | ||||||||
Operating Revenues | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 2,773 | $ 2,641 | $ 2,249 | $ 3,223 | 10,415 | 10,886 | 9,968 |
Net Income | 1,679 | 1,518 | 1,243 | ||||||||
Total Assets | 37,535 | 35,287 | 37,535 | 35,287 | 32,480 | ||||||
Power [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Operating Revenues | 1,082 | 1,096 | 1,025 | 1,725 | 1,610 | 1,138 | 986 | 1,700 | 4,928 | 5,434 | 5,063 |
Basis Adjustment | (986) | (986) | (986) | (986) | |||||||
Net Income | 856 | 760 | 644 | ||||||||
Total Assets | 12,250 | 12,037 | $ 12,250 | 12,037 | |||||||
Power [Member] | Nuclear Production [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 60 years | ||||||||||
Power [Member] | Pumped Storage Facilities [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 76 years | ||||||||||
Power [Member] | Solar Assets [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 25 years | ||||||||||
Power [Member] | Minimum [Member] | General Plant Assets [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 3 years | ||||||||||
Power [Member] | Minimum [Member] | Fossil Production [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 19 years | ||||||||||
Power [Member] | Maximum [Member] | General Plant Assets [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 20 years | ||||||||||
Power [Member] | Maximum [Member] | Fossil Production [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Estimated useful lives | 79 years | ||||||||||
PSE&G [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
TEFA | $ 0 | 0 | 68 | ||||||||
Operating Revenues | 1,402 | $ 1,766 | $ 1,466 | $ 2,002 | 1,531 | $ 1,655 | $ 1,435 | $ 2,145 | 6,636 | 6,766 | 6,655 |
Basis Adjustment | 986 | 986 | 986 | 986 | |||||||
Net Income | 787 | 725 | 612 | ||||||||
Total Assets | $ 23,677 | $ 22,186 | $ 23,677 | $ 22,186 | |||||||
Operating Revenues [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
TEFA | 74 | ||||||||||
Tefa And Grt [Member] | |||||||||||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||||||||||
TEFA | $ 68 |
Organization, Basis Of Presen61
Organization, Basis Of Presentation And Summary Of Significant Accounting Policies (Depreciation Rate Stated Percentage) (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
PSE&G [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation Rate | 2.46% | 2.47% | 2.48% |
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 | 19 years | ||
Fossil Production [Member] | Maximum [Member] | Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
Estimated useful lives | 79 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 Presen62
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
PSE&G [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
IDC/AFUDC | $ 65 | $ 44 | $ 34 |
Average Rate | 8.01% | 8.09% | 8.11% |
Power [Member] | |||
Organization Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items] | |||
IDC/AFUDC | $ 27 | $ 24 | $ 23 |
Average Rate | 5.14% | 5.14% | 5.36% |
Recent Accounting Standards New
Recent Accounting Standards New Standards Adopted (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
PSE&G [Member] | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Unamortized Debt Issuance Costs | $ 41 | $ 37 |
Power [Member] | ||
New Accounting Pronouncement, Early Adoption [Line Items] | ||
Unamortized Debt Issuance Costs | $ 8 | $ 9 |
Variable Interest Entities (V64
Variable Interest Entities (VIEs) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 2,773 | $ 2,641 | $ 2,249 | $ 3,223 | $ 10,415 | $ 10,886 | $ 9,968 |
Operation and Maintenance | 2,978 | 3,150 | 2,887 | ||||||||
PSE&G [Member] | |||||||||||
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | $ 1,402 | $ 1,766 | $ 1,466 | $ 2,002 | $ 1,531 | $ 1,655 | $ 1,435 | $ 2,145 | 6,636 | 6,766 | 6,655 |
Operation and Maintenance | 1,560 | 1,558 | $ 1,639 | ||||||||
Long Island ServCo [Member] | |||||||||||
Variable Interest Entity [Line Items] | |||||||||||
Operating Revenues | 375 | 389 | |||||||||
Operation and Maintenance | $ 375 | $ 389 |
Property, Plant And Equipment65
Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Property, Plant And Equipment) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | $ 22,967 | $ 20,428 |
Total Generation | 11,842 | 11,153 |
Other | 685 | 615 |
Total | 35,494 | 32,196 |
PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 22,967 | 20,428 |
Total Generation | 569 | 521 |
Other | 196 | 154 |
Total | 23,732 | 21,103 |
Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 11,273 | 10,632 |
Other | 81 | 100 |
Total | 11,354 | 10,732 |
Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 0 | 0 |
Total Generation | 0 | 0 |
Other | 408 | 361 |
Total | 408 | 361 |
Electric Transmission [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 7,554 | 5,845 |
Electric Transmission [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 7,554 | 5,845 |
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 | 7,553 | 7,295 |
Electric Distribution [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 7,553 | 7,295 |
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 | 5,875 | 5,479 |
Gas Distribution [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 5,875 | 5,479 |
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 | 1,459 | 1,304 |
Total Generation | 892 | 714 |
Construction Work In Progress [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 1,459 | 1,304 |
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 | 892 | 714 |
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 | 26 | 15 |
Plant Held For Future Use [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 26 | 15 |
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 | 411 | 401 |
Other Plant [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Transmission and Distribution | 411 | 401 |
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 | 7,005 | 6,964 |
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 | 7,005 | 6,964 |
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 | 2,202 | 1,751 |
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 | 2,202 | 1,751 |
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 | 785 | 889 |
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 | 785 | 889 |
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 | 958 | 835 |
Other Production-Solar [Member] | PSE&G [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 569 | 521 |
Other Production-Solar [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | 389 | 314 |
Other Production-Solar [Member] | Other [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Total Generation | $ 0 | $ 0 |
Property, Plant And Equipment66
Property, Plant And Equipment And Jointly-Owned Facilities (Schedule Of Jointly-Owned Facilities) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Conemaugh [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 23.00% | |
Plant | $ 404 | $ 397 |
Accumulated Depreciation | $ 154 | 142 |
Keystone [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 23.00% | |
Plant | $ 408 | 396 |
Accumulated Depreciation | $ 163 | 151 |
Peach Bottom [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 50.00% | |
Plant | $ 1,219 | 1,087 |
Accumulated Depreciation | $ 262 | 236 |
Salem [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 57.00% | |
Plant | $ 990 | 916 |
Accumulated Depreciation | 276 | 236 |
Nuclear Support Facilities [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Plant | 226 | 218 |
Accumulated Depreciation | $ 60 | 49 |
Yards Creek [Member] | Power [Member] | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Ownership Interest | 50.00% | |
Plant | $ 42 | 41 |
Accumulated Depreciation | $ 24 | 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 | 166 | 162 |
Accumulated Depreciation | $ 72 | $ 69 |
Regulatory Assets And Liabili67
Regulatory Assets And Liabilities (Schedule Of Regulatory Assets and Liabilities) (Details) $ in Millions | 1 Months Ended | ||||||||||||
Nov. 30, 2015USD ($) | Oct. 31, 2015USD ($) | Jul. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Apr. 30, 2015$ / DTH | Mar. 31, 2015$ / DTH | Feb. 28, 2015USD ($) | Dec. 31, 2015USD ($) | Oct. 01, 2015 | Dec. 31, 2014USD ($) | May. 31, 2014USD ($) | |||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets of Variable Interest Entities (VIEs) | $ 0 | $ 249 | |||||||||||
Regulatory Liabilities of Consolidated Variable Interest Entity, Current | 42 | 0 | |||||||||||
Regulatory Assets, Current | 164 | 323 | |||||||||||
Regulatory Assets, Noncurrent | 3,196 | 3,192 | |||||||||||
Regulatory Liability, Current | 123 | 186 | |||||||||||
Regulatory Liabilities, Noncurrent | 175 | 258 | |||||||||||
Regulatory Liabilities Of Consolidated Variable Interest Entity Noncurrent | 0 | 39 | |||||||||||
PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets of Variable Interest Entities (VIEs) | 0 | 249 | |||||||||||
Regulatory Liabilities of Consolidated Variable Interest Entity, Current | $ 42 | 0 | |||||||||||
Approved SBC and NGC revenue recovery | $ 311 | ||||||||||||
Current BGSS rate per therm | 0.45 | ||||||||||||
Proposed BGSS rate per therm | 0.40 | ||||||||||||
Self Implementing Bill Credit per therm | $ / DTH | 0.45 | 243,000,000 | |||||||||||
True-up adjustment for Transmission Formula Rate Revenues | $ (19) | ||||||||||||
Deferred Storm and Property Reserve Deficiency, Noncurrent | 220 | ||||||||||||
Request for RAC Recovery | 85 | ||||||||||||
Regulatory Assets, Current | 164 | 323 | |||||||||||
Regulatory Assets Including Consolidated Variable Interest Entities, Current | 164 | 572 | |||||||||||
Regulatory Assets, Noncurrent | 3,196 | 3,192 | |||||||||||
Total Noncurrent Regulatory Assets | 3,196 | 3,192 | |||||||||||
Total Regulatory Assets | 3,360 | 3,764 | |||||||||||
Regulatory Liability, Current | 123 | 186 | |||||||||||
Regulatory Liabilities Including Consolidated Variable Interest Entity, Current | 165 | 186 | |||||||||||
Regulatory Liabilities, Noncurrent | 175 | 258 | |||||||||||
Regulatory Liabilities Of Consolidated Variable Interest Entity Noncurrent | 0 | 39 | |||||||||||
Total Noncurrent Regulatory Liabilities | 175 | 297 | |||||||||||
Total Regulatory Liabilities | 340 | 483 | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 146 | $ 6 | $ 1 | ||||||||||
Proposed Recovery of costs for Electric Green Energy Program | $ 57 | $ 66 | |||||||||||
Proposed Recovery of costs for Gas Green Energy Programs | $ 8 | $ 10 | |||||||||||
Overrecovered Electric Energy Costs-BGS [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | 0 | 21 | |||||||||||
Stranded Costs [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | 64 | 0 | |||||||||||
Regulatory Liabilities, Noncurrent | [1],[2] | 0 | 134 | ||||||||||
Deferred Income Taxes [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | 0 | 28 | |||||||||||
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] | 36 | 6 | ||||||||||
Societal Benefits Charges (SBC) [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | [1],[2] | 31 | 13 | ||||||||||
Weather Normalization Clause [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | [1] | 0 | 31 | ||||||||||
Gas Margin Adjustment Clause [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | [1],[2] | 13 | 28 | ||||||||||
FERC Formula Rate True-Up [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | [1],[2] | 19 | 0 | ||||||||||
Regulatory Liabilities, Noncurrent | [1],[2] | 49 | 26 | ||||||||||
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | [1],[2] | 1 | 46 | ||||||||||
Electric Cost Of Removal [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liabilities, Noncurrent | 122 | 133 | |||||||||||
Other [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liabilities, Noncurrent | 4 | 4 | |||||||||||
Non-Utility Generation Charge [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Liability, Current | 1 | 13 | |||||||||||
New Jersey Clean Energy Program [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Current | [1],[2] | 142 | 142 | ||||||||||
Weather Normalization Clause [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Current | [1] | 10 | 0 | ||||||||||
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, Current | [1],[2] | 1 | 13 | ||||||||||
Regulatory Assets, Noncurrent | [1] | 104 | 134 | ||||||||||
Stranded Costs [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Current | [1] | 0 | 412 | ||||||||||
Pension and Other Postretirement Benefit Costs [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 1,270 | 1,265 | |||||||||||
Deferred Income Taxes [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 467 | 473 | |||||||||||
Manufactured Gas Plant (MGP) Remediation Costs [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | [1] | 431 | 434 | ||||||||||
Storm Damage Deferral [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 233 | 245 | |||||||||||
Remediation Adjustment Charge (Other SBC) [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | [1],[2] | 174 | 164 | ||||||||||
Conditional Asset Retirement Obligation [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 152 | 138 | |||||||||||
Electric Cost Of Removal [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 133 | 91 | |||||||||||
Unamortized Loss On Reacquired Debt And Debt Expense [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | [2] | 67 | 74 | ||||||||||
Mark-To-Market Contracts [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Noncurrent | 63 | 75 | |||||||||||
Other [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Current | 0 | 5 | |||||||||||
Regulatory Assets, Noncurrent | 102 | 99 | |||||||||||
Underrecovered Electric Costs Basic Generation Service [Member] | PSE&G [Member] | |||||||||||||
Regulatory Assets And Liabilities [Line Items] | |||||||||||||
Regulatory Assets, Current | $ 11 | $ 0 | [1],[2] | ||||||||||
[1] | Recoverable/Refundable per specific rate order. | ||||||||||||
[2] | Recovered/Refunded with interest. |
Regulatory Assets And Liabili68
Regulatory Assets And Liabilities (Significant Orders and Pending Filings) (Details) - PSE&G [Member] $ in Millions | 1 Months Ended | 3 Months Ended | ||||||||||
Nov. 30, 2015USD ($) | Oct. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jul. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Apr. 30, 2015USD ($)$ / DTH | Mar. 31, 2015$ / DTH | Feb. 28, 2015USD ($) | Feb. 29, 2016USD ($)$ / DTH | Dec. 31, 2015USD ($) | Oct. 01, 2015 | May. 31, 2014USD ($) | |
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
Deferred Storm and Property Reserve Deficiency, Noncurrent | $ 220 | |||||||||||
Request for RAC Recovery | $ 85 | |||||||||||
Self Implementing Bill Credit per therm | $ / DTH | 0.45 | 243,000,000 | ||||||||||
Current BGSS rate per therm | 0.45 | |||||||||||
Proposed BGSS rate per therm | 0.40 | |||||||||||
Approved SBC and NGC revenue recovery | $ 311 | |||||||||||
True-up adjustment for Transmission Formula Rate Revenues | $ (19) | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 146 | $ 6 | $ 1 | |||||||||
Proposed Recovery of costs for Electric Green Energy Program | $ 57 | $ 66 | ||||||||||
Proposed Recovery of costs for Gas Green Energy Programs | $ 8 | $ 10 | ||||||||||
Public Utilities, Approved Additional Capital Expenditures | $ 95 | |||||||||||
Public Utilities, Approved Additional Administrative Expenses | 12 | |||||||||||
Gas Distribution [Member] | ||||||||||||
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 17 | |||||||||||
Electric Distribution [Member] | ||||||||||||
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 10 | |||||||||||
Overrecovered Gas and Electric Costs - BGSS and BGS [Member] | ||||||||||||
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
BGSS Revenue Reduction | 70 | |||||||||||
Weather Normalization Clause [Member] | ||||||||||||
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ (40) | $ (45) | ||||||||||
Subsequent Event [Member] | ||||||||||||
Regulatory Assets And Liabilities [Line Items] | ||||||||||||
Self Implementing Bill Credit per therm | $ / DTH | 0.25 | |||||||||||
BGSS Revenue Reduction | $ 155 |
Long-Term Investments (Schedule
Long-Term Investments (Schedule Of Long Term Investments) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | $ 1,233 | $ 1,307 | ||
Dividends in equity method investments | 16 | 17 | $ 11 | |
Power [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 119 | 121 | ||
PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 330 | 348 | ||
Life Insurance And Supplemental Benefits [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 150 | 156 | ||
Solar Loan Investments [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 175 | 187 | ||
Lease Investments [Member] | Energy Holdings [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 784 | 836 | ||
Partnerships And Corporate Joint Ventures [Member] | Power [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | [1] | 119 | 121 | |
Other Investments [Member] | PSE&G [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | 5 | 5 | ||
Equity Method Investments [Member] | Partnerships And Corporate Joint Ventures [Member] | Energy Holdings [Member] | ||||
Long-Term Investments [Line Items] | ||||
Total Long-Term Investments | $ 0 | $ 2 | ||
[1] | During the three years ended December 31, 2015, 2014 and 2013, the amount of dividends from these investments was $16 million, $17 million and $11 million, respectively. |
Long-Term Investments (Schedu70
Long-Term Investments (Schedule Of Net Investment In Leveraged Leases) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Long-term Investments [Abstract] | ||
Lease Receivables (net of Non-Recourse Debt) | $ 1,150 | $ 1,216 |
Estimated Residual Value of Leased Assets | 519 | 525 |
Subtotal | 631 | 691 |
Unearned and Deferred Income | (366) | (380) |
Gross Investment in Leases | 784 | 836 |
Deferred Tax Liabilities | (724) | (738) |
Net Investments in Leases | $ 60 | $ 98 |
Long-Term Investments (Schedu71
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Long-term Investments [Abstract] | |||
Pre-Tax Income (Loss) from Leases | $ 12 | $ 24 | $ 11 |
Income Tax Expense (Benefit) on Pre-Tax Income from Leases | $ 5 | $ 32 | $ 6 |
Long-Term Investments (Equity M
Long-Term Investments (Equity Method Investments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Long-Term Investments [Line Items] | |||
Long-Term Investments | $ 1,233 | $ 1,307 | |
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 | 12.00% | ||
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 | $ 119 | 121 | |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | [1] | 119 | $ 121 |
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Keystone [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 0 | ||
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Conemaugh [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 0 | ||
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | PennEast [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | 0 | ||
Power [Member] | Partnerships And Corporate Joint Ventures [Member] | Kalaeloa [Member] | |||
Long-Term Investments [Line Items] | |||
Long-Term Investments | $ 0 | ||
[1] | During the three years ended December 31, 2015, 2014 and 2013, the amount of dividends from these investments was $16 million, $17 million and $11 million, respectively. |
Financing Receivables (Schedule
Financing Receivables (Schedule Of Credit Risk Profile Based On Payment Activity) (Detail) - PSE&G [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Concentration Risk [Line Items] | ||
Credit Risk Profile Based on Payment Activity | $ 189 | $ 201 |
Commercial/Industrial [Member] | ||
Concentration Risk [Line Items] | ||
Loans Receivable, Net | 177 | 188 |
Residential [Member] | ||
Concentration Risk [Line Items] | ||
Loans Receivable, Net | $ 12 | $ 13 |
Financing Receivables (Schedu74
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, 2015 | Dec. 31, 2014 |
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | $ 631 | $ 691 |
Energy Holdings [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 631 | |
Energy Holdings [Member] | Counterparties' Credit Rating (S&P), AA [Member] | ||
Guarantor Obligations [Line Items] | ||
Lease Receivables, Net of Non-Recourse Debt | 17 | |
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 | 134 | |
Energy Holdings [Member] | Standard & Poor's, CCC plus 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, 2015 | Dec. 31, 2014 |
Financing Receivable, Recorded Investment [Line Items] | ||
Net Investments in Leases | $ 60 | $ 98 |
Lease investment with non-investment grade counterparties, gross | 573 | |
Lease investment with non-investment grade counterparties, net of deferred taxes | $ (30) | |
Powerton Station [Member] | ||
Financing Receivable, Recorded Investment [Line Items] | ||
Lease Receivable Percent Owned | 64.00% |
Financing Receivables (Schedu76
Financing Receivables (Schedule Of Assets Under Lease Receivables) (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($)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 | $ | $ 84 |
Lease Receivable, % Owned | 64.00% |
Lease Receivable, Total, MW | MW | 1,044 |
Lease Receivable, Asset, Fuel Type | Coal |
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 | $ | $ 121 |
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+ |
Lease Receivable, Counterparty | NRG REMA, LLC |
Conemaugh Station Units 1 And 2 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | PA |
Lease Receivable, Gross Investment | $ | $ 121 |
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+ |
Lease Receivable, Counterparty | NRG REMA, LLC |
Shawville Station Units 1, 2, 3 And 4 [Member] | |
Financing Receivable, Recorded Investment [Line Items] | |
Lease Receivable, Asset Location | PA |
Lease Receivable, Gross Investment | $ | $ 113 |
Lease Receivable, % Owned | 100.00% |
Lease Receivable, Total, MW | MW | 603 |
Lease Receivable, Asset, Fuel Type | Coal |
Lease Receivable, Counterparties' S&P Credit Ratings | CCC+ |
Lease Receivable, Counterparty | NRG REMA, LLC |
Available-For-Sale Securities77
Available-For-Sale Securities (Fair Values And Gross Unrealized Gains And Losses For The Securities) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | $ 1,584 | $ 1,554 |
Gross Unrealized Gains | 196 | 238 |
Gross Unrealized Losses | (26) | (12) |
Fair Value | 1,754 | 1,780 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Equity Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 693 | 685 |
Gross Unrealized Gains | 185 | 220 |
Gross Unrealized Losses | (13) | (8) |
Fair Value | 865 | 897 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Government Obligations [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 483 | 430 |
Gross Unrealized Gains | 8 | 9 |
Gross Unrealized Losses | (3) | (1) |
Fair Value | 488 | 438 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Debt Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 366 | 333 |
Gross Unrealized Gains | 3 | 9 |
Gross Unrealized Losses | (10) | (3) |
Fair Value | 359 | 339 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Total Debt Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 849 | 763 |
Gross Unrealized Gains | 11 | 18 |
Gross Unrealized Losses | (13) | (4) |
Fair Value | 847 | 777 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | Other Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 42 | 106 |
Gross Unrealized Gains | 0 | 0 |
Gross Unrealized Losses | 0 | 0 |
Fair Value | 42 | 106 |
Rabbi Trust [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 204 | 177 |
Gross Unrealized Gains | 11 | 14 |
Gross Unrealized Losses | (2) | 0 |
Fair Value | 213 | 191 |
Rabbi Trust [Member] | Equity Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 12 | 12 |
Gross Unrealized Gains | 10 | 11 |
Gross Unrealized Losses | 0 | 0 |
Fair Value | 22 | 23 |
Rabbi Trust [Member] | Government Obligations [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 108 | 89 |
Gross Unrealized Gains | 1 | 2 |
Gross Unrealized Losses | (1) | 0 |
Fair Value | 108 | 91 |
Rabbi Trust [Member] | Other Debt Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 82 | 74 |
Gross Unrealized Gains | 0 | 1 |
Gross Unrealized Losses | (1) | 0 |
Fair Value | 81 | 75 |
Rabbi Trust [Member] | Total Debt Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 190 | 163 |
Gross Unrealized Gains | 1 | 3 |
Gross Unrealized Losses | (2) | 0 |
Fair Value | 189 | 166 |
Rabbi Trust [Member] | Other Securities [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Cost | 2 | 2 |
Gross Unrealized Gains | 0 | 0 |
Gross Unrealized Losses | 0 | 0 |
Fair Value | 2 | 2 |
Rabbi Trust [Member] | Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Fair Value | $ 52 | $ 45 |
Available-For-Sale Securities78
Available-For-Sale Securities (Schedule Of Accounts Receivable And Accounts Payable) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Rabbi Trust [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Accounts Receivable | $ 1 | $ 1 |
Accounts Payable | 0 | 0 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Accounts Receivable | 17 | 10 |
Accounts Payable | $ 10 | $ 2 |
Available-For-Sale Securities79
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, 2015 | Dec. 31, 2014 | |
Nuclear Decommissioning Trust (NDT) Fund [Member] | Power [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | $ 618 | $ 356 | |
Gross Unrealized Losses, Less than 12 Months | (22) | (9) | |
Fair Value, Greater Than 12 Months | 56 | 59 | |
Gross Unrealized Losses, Greater Than 12 Months | (4) | (3) | |
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] | 151 | 162 |
Gross Unrealized Losses, Less than 12 Months | [1] | (13) | (8) |
Fair Value, Greater Than 12 Months | [1] | 1 | 1 |
Gross Unrealized Losses, Greater Than 12 Months | [1] | 0 | 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] | 245 | 95 |
Gross Unrealized Losses, Less than 12 Months | [2] | (2) | 0 |
Fair Value, Greater Than 12 Months | [2] | 19 | 28 |
Gross Unrealized Losses, Greater Than 12 Months | [2] | (1) | (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] | 222 | 99 |
Gross Unrealized Losses, Less than 12 Months | [3] | (7) | (1) |
Fair Value, Greater Than 12 Months | [3] | 36 | 30 |
Gross Unrealized Losses, Greater Than 12 Months | [3] | (3) | (2) |
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 | 467 | 194 | |
Gross Unrealized Losses, Less than 12 Months | (9) | (1) | |
Fair Value, Greater Than 12 Months | 55 | 58 | |
Gross Unrealized Losses, Greater Than 12 Months | (4) | (3) | |
Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Fair Value, Less Than 12 Months | 99 | 26 | |
Gross Unrealized Losses, Less than 12 Months | (2) | 0 | |
Fair Value, Greater Than 12 Months | 11 | 0 | |
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] | 53 | 2 |
Gross Unrealized Losses, Less than 12 Months | [5] | (1) | 0 |
Fair Value, Greater Than 12 Months | [5] | 2 | 0 |
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 | 24 |
Gross Unrealized Losses, Less than 12 Months | [6] | (1) | 0 |
Fair Value, Greater Than 12 Months | [6] | 9 | 0 |
Gross Unrealized Losses, Greater Than 12 Months | [6] | $ 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 companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015. | ||
[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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2015. | ||
[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, 2015. | ||
[4] | Equity Securities—Investments in marketable equity securities within the Rabbi Trust Fund is 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. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since PSEG does not intend to sell nor will it be more-likely-than-not required to sell. PSEG does not consider these securities to be other-than-temporarily impaired as of December 31, 2015. | ||
[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, 2015. |
Available-For-Sale Securities80
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | $ 1,397 | $ 1,448 | $ 1,070 |
Gross Realized Gains | 97 | 177 | 112 |
Gross Realized Losses | (37) | (23) | (26) |
Net Realized Gains (Losses) | 60 | 154 | 86 |
Rabbi Trust [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Proceeds from Sale and Maturity of Available-for-sale Securities | 104 | 467 | 89 |
Gross Realized Gains | 3 | 4 | 4 |
Gross Realized Losses | (2) | (3) | (3) |
Net Realized Gains (Losses) | $ 1 | $ 1 | $ 1 |
Available-For-Sale Securities81
Available-For-Sale Securities (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | $ 53 | $ 20 | $ 12 |
Power [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | 53 | $ 20 | $ 12 |
Nuclear Decommissioning Trust (NDT) Fund [Member] | |||
Schedule of Available-for-sale Securities [Line Items] | |||
Available For Sale Securities OTTI Charge | 53 | ||
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 | 86 | ||
Decommissioning Liability, Noncurrent | 429 | ||
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 Securities82
Available-For-Sale Securities (Amount Of Available-For-Sale Debt Securities By Maturity Periods) (Detail) $ in Millions | Dec. 31, 2015USD ($) |
Rabbi Trust [Member] | |
Schedule of Available-for-sale Securities [Line Items] | |
Available-for-sale debt securities, Less than one year | $ 3 |
Available-for-sale debt securities, 1-5 years | 49 |
Available-for-sale debt securities, 6-10 years | 44 |
Available-for-sale debt securities, 11-15 years | 5 |
Available-for-sale debt securities, 16-20 years | 8 |
Available-for-sale debt securities, Over 20 years | 80 |
Total Available-for-Sale Debt Securities | 189 |
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 | 16 |
Available-for-sale debt securities, 1-5 years | 209 |
Available-for-sale debt securities, 6-10 years | 200 |
Available-for-sale debt securities, 11-15 years | 57 |
Available-for-sale debt securities, 16-20 years | 49 |
Available-for-sale debt securities, Over 20 years | 316 |
Total Available-for-Sale Debt Securities | $ 847 |
Available-For-Sale Securities83
Available-For-Sale Securities (Fair Value Of Rabbi Trust) (Detail) - Rabbi Trust [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | $ 213 | $ 191 |
Power [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | 52 | 45 |
PSE&G [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | 42 | 41 |
Other [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Total Rabbi Trust Available-for-Sale Securities | $ 119 | $ 105 |
Goodwill And Other Intangible84
Goodwill And Other Intangibles (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Goodwill [Line Items] | ||
Goodwill | $ 16 | $ 16 |
Intangible assets | 102 | 84 |
Power [Member] | ||
Goodwill [Line Items] | ||
Goodwill | 16 | 16 |
Intangible assets | $ 102 | $ 84 |
Goodwill And Other Intangible85
Goodwill And Other Intangibles (Expenses Related To Emissions And Renewable Energy Requirements) (Details) - Power [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Goodwill [Line Items] | |||
Emissions Expense | $ 13 | $ 10 | $ 6 |
Renewable Energy Expense | $ 91 | $ 59 | $ 26 |
Asset Retirement Obligations 86
Asset Retirement Obligations (AROs) (Impact Of The Revisions On Asset Retirement Obligation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | $ 743 | $ 677 | |
Liabilities Settled | (5) | (2) | |
Liabilities Incurred | 14 | 23 | |
Accretion Expense | 26 | 30 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 16 | 15 |
ARO Liability, Ending Balance | 679 | 743 | |
Asset Retirement Obligation, Revision of Estimate | (115) | ||
PSE&G [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 290 | 274 | |
Liabilities Settled | (4) | (2) | |
Liabilities Incurred | 1 | 3 | |
Accretion Expense | 0 | 0 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 16 | 15 |
ARO Liability, Ending Balance | 218 | 290 | |
Asset Retirement Obligation, Revision of Estimate | (85) | ||
Power [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 450 | 400 | |
Liabilities Settled | (1) | 0 | |
Liabilities Incurred | 12 | 20 | |
Accretion Expense | 26 | 30 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 0 | 0 |
ARO Liability, Ending Balance | 457 | 450 | |
Asset Retirement Obligation, Revision of Estimate | (30) | ||
Other [Member] | |||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
ARO Liability, Beginning Balance | 3 | 3 | |
Liabilities Settled | 0 | 0 | |
Liabilities Incurred | 1 | 0 | |
Accretion Expense | 0 | 0 | |
Accretion Expense Deferred and Recovered in Rate Base | [1] | 0 | 0 |
ARO Liability, Ending Balance | 4 | $ 3 | |
Asset Retirement Obligation, Revision of Estimate | $ 0 | ||
[1] | Not reflected as expense in Consolidated Statements of Operations |
Pension, OPEB and Savings Pla87
Pension, OPEB and Savings Plans (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015USD ($)plan | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 114 | $ 126 | |
Number of PSEG's defined contribution plans | plan | 2 | ||
Historical annualized rate of return | 9.30% | ||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | $ 21 | ||
Defined benefit plan funded status of plan percentage | 91.00% | ||
Rabbi trust assets used to fund nonqualified pension plans | $ 213 | ||
Defined benefit plans, projected benefit and accumulated benefit obligations | 5,400 | 5,500 | |
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% | ||
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Impact of Mortality Table Change in Actuarial (Gain) Loss | $ 314 | ||
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax | 386 | 411 | |
Accumulated Other Comprehensive Income (Loss), Defined Benefit Pension and Other Postretirement Plans, Before Tax | 658 | 702 | |
Defined Benefit Plan, Net Periodic Benefit Cost | 74 | (23) | $ 152 |
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 487 | $ 440 | |
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 | $ 159 | ||
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Impact of Mortality Table Change in Actuarial (Gain) Loss | 79 | ||
Defined Benefit Plan, Net Periodic Benefit Cost | 87 | $ 70 | $ 91 |
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 1,228 | $ 1,277 | |
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] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 21 | $ (7) | $ 43 |
Power [Member] | Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 27 | 20 | $ 23 |
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] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 30 | 67 | |
Number of PSEG's defined contribution plans | plan | 2 | ||
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year | $ 28 | ||
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% | ||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 114 | 126 | |
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] | |||
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent | $ 375 | $ 452 | |
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% |
Pension, OPEB and Savings Pla88
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | $ 5,654 | |||||
Fair Value of Assets at End of Year | 5,413 | $ 5,654 | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (114) | (126) | ||||
Pension Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | [1] | 5,722 | 4,812 | |||
Service Cost | 123 | 104 | $ 116 | |||
Interest Cost | 234 | 234 | 215 | |||
Actuarial (Gain) Loss | (289) | [2] | 838 | |||
Gross Benefits Paid | (268) | (266) | ||||
Benefit Obligation at End of Year | [1] | 5,522 | [2] | 5,722 | 4,812 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 5,293 | 5,116 | ||||
Actual Return on Plan Assets | (11) | 433 | ||||
Employer Contributions | 25 | 10 | ||||
Gross Benefits Paid | (268) | (266) | ||||
Fair Value of Assets at End of Year | 5,039 | 5,293 | 5,116 | |||
Funded Status (Plan Assets less Benefit Obligation) | (483) | (429) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Assets | 14 | 21 | ||||
Current Accrued Benefit Cost | (10) | (10) | ||||
Noncurrent Accrued Benefit Cost | (487) | (440) | ||||
Amounts Recognized | (483) | (429) | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract] | ||||||
Prior Service Cost | [3] | (83) | (102) | |||
Net Actuarial Loss | [3] | 1,710 | 1,724 | |||
Total | (1,627) | (1,622) | ||||
Other Benefits [Member] | ||||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | ||||||
Benefit Obligation at Beginning of Year | [1] | 1,638 | 1,414 | |||
Service Cost | 22 | 18 | 21 | |||
Interest Cost | 67 | 69 | 63 | |||
Actuarial (Gain) Loss | (45) | [2] | 210 | |||
Gross Benefits Paid | (70) | (73) | ||||
Benefit Obligation at End of Year | [1] | 1,612 | [2] | 1,638 | 1,414 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 361 | 319 | ||||
Actual Return on Plan Assets | (1) | 28 | ||||
Employer Contributions | 84 | 87 | ||||
Gross Benefits Paid | (70) | (73) | ||||
Fair Value of Assets at End of Year | 374 | 361 | 319 | |||
Funded Status (Plan Assets less Benefit Obligation) | (1,238) | (1,277) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Assets | 0 | 0 | ||||
Current Accrued Benefit Cost | (10) | 0 | ||||
Noncurrent Accrued Benefit Cost | (1,228) | (1,277) | ||||
Amounts Recognized | (1,238) | (1,277) | ||||
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax [Abstract] | ||||||
Prior Service Cost | [3] | (25) | (39) | |||
Net Actuarial Loss | [3] | 438 | 495 | |||
Total | (413) | (456) | ||||
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 | 69 | |||||
Fair Value of Assets at End of Year | 97 | 69 | ||||
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 | 195 | [4] | 0 | |||
Service Cost | 26 | 20 | ||||
Interest Cost | 9 | 7 | ||||
Actuarial (Gain) Loss | (20) | 42 | ||||
Gross Benefits Paid | 0 | 0 | ||||
Plan Assumptions | 1 | 126 | ||||
Benefit Obligation at End of Year | 211 | [4] | 195 | [4] | 0 | |
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||||
Fair Value of Assets at Beginning of Year | 69 | 0 | ||||
Actual Return on Plan Assets | (2) | 2 | ||||
Employer Contributions | 30 | 67 | ||||
Gross Benefits Paid | 0 | 0 | ||||
Fair Value of Assets at End of Year | 97 | 69 | 0 | |||
Funded Status (Plan Assets less Benefit Obligation) | (114) | (126) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (114) | (126) | ||||
Amounts Recognized | [5] | (114) | (126) | |||
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 | 452 | [4] | 0 | |||
Service Cost | 17 | 13 | ||||
Interest Cost | 21 | 17 | ||||
Actuarial (Gain) Loss | (114) | 107 | ||||
Gross Benefits Paid | (1) | 0 | ||||
Plan Assumptions | 0 | 315 | ||||
Benefit Obligation at End of Year | 375 | [4] | 452 | [4] | 0 | |
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 | 1 | 0 | ||||
Gross Benefits Paid | (1) | 0 | ||||
Fair Value of Assets at End of Year | 0 | 0 | $ 0 | |||
Funded Status (Plan Assets less Benefit Obligation) | (375) | (452) | ||||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ||||||
Noncurrent Accrued Benefit Cost | (375) | (452) | ||||
Amounts Recognized | [5] | $ (375) | $ (452) | |||
[1] | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. | |||||
[2] | In October 2014, the Society of Actuaries’ Retirement Plans Experience Committee issued its final report on mortality tables (RP-2014 Mortality Tables Report). As of December 31, 2014, PSEG updated its mortality assumptions based on the information contained in this report. The impact of this change is reflected in Actuarial (Gain) Loss in 2014 and added $314 million and $79 million to the Benefit Obligations for Pension and OPEB, respectively, since December 31, 2013. | |||||
[3] | Includes $658 million ($386 million, after-tax) and $702 million ($411 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2015 and 2014, respectively. | |||||
[4] | Represents projected benefit obligation for pension benefits and the accumulated postretirement benefit obligation for other benefits. | |||||
[5] | Amounts equal to the accrued pension and OPEB costs of Servco are offset in Long-Term Receivable of VIE on PSEG's Consolidated Balance Sheet. |
Pension, OPEB and Savings Pla89
Pension, OPEB and Savings Plans (Components Of Net Periodic Benefit Cost) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | $ 123 | $ 104 | $ 116 |
Interest Cost | 234 | 234 | 215 |
Expected Return on Plan Assets | (414) | (399) | (348) |
Amortization of Prior Service Cost | (19) | (18) | (19) |
Amortization of Actuarial Loss | 150 | 56 | 188 |
Net Periodic Benefit Cost | 74 | (23) | 152 |
Total Benefit Costs, Including Effect of Regulatory Asset | 74 | (23) | 152 |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Service Cost | 22 | 18 | 21 |
Interest Cost | 67 | 69 | 63 |
Expected Return on Plan Assets | (31) | (26) | (21) |
Amortization of Prior Service Cost | (14) | (14) | (14) |
Amortization of Actuarial Loss | 43 | 23 | 42 |
Net Periodic Benefit Cost | 87 | 70 | 91 |
Total Benefit Costs, Including Effect of Regulatory Asset | $ 87 | $ 70 | $ 91 |
Pension, OPEB and Savings Pla90
Pension, OPEB and Savings Plans (Schedule Of Pension And OPEB Costs) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 74 | $ (23) | $ 152 |
Total Benefit Costs | 74 | (23) | 152 |
Pension Benefits [Member] | PSE&G [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 40 | (19) | 91 |
Pension Benefits [Member] | Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 21 | (7) | 43 |
Pension Benefits [Member] | Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 13 | 3 | 18 |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 87 | 70 | 91 |
Total Benefit Costs | 87 | 70 | 91 |
Other Benefits [Member] | PSE&G [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 55 | 46 | 65 |
Other Benefits [Member] | Power [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | 27 | 20 | 23 |
Other Benefits [Member] | Other [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Net Periodic Benefit Cost | $ 5 | $ 4 | $ 3 |
Pension, OPEB and Savings Pla91
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, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net Actuarial (Gain) Loss in Current Period | $ 136 | $ 803 |
Amortization of Net Actuarial Gain (Loss) | (150) | (56) |
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax | 19 | 18 |
Total | 5 | 765 |
Other Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Net Actuarial (Gain) Loss in Current Period | (14) | 208 |
Amortization of Net Actuarial Gain (Loss) | (43) | (23) |
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax | 14 | 14 |
Total | $ (43) | $ 199 |
Pension, OPEB and Savings Pla92
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, 2015USD ($) | |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Actuarial (Gain) Loss | $ 158 |
Prior Service Cost | (18) |
Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Actuarial (Gain) Loss | 40 |
Prior Service Cost | $ (14) |
Pension, OPEB and Savings Pla93
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.54% | 4.20% | 5.00% |
Expected Return on Plan Assets | 8.00% | 8.00% | 8.00% |
Rate of Compensation Increase | 3.61% | 3.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.61% | 4.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.20% | 5.00% | 4.20% |
Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.58% | 4.21% | 5.01% |
Expected Return on Plan Assets | 8.00% | 8.00% | 8.00% |
Rate of Compensation Increase | 3.61% | 3.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase | 3.61% | 4.61% | 4.61% |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 4.21% | 5.01% | 4.20% |
Administrative Expense | 3.00% | 3.00% | 3.00% |
Immediate Rate | 7.75% | 7.40% | 7.83% |
Ultimate Rate | 4.75% | 5.00% | 5.00% |
Year Ultimate Rate Reached | 2,025 | 2,022 | 2,021 |
Total of Service Cost and Interest Cost effect of 1 percent increase | $ 12 | $ 13 | $ 12 |
Postretirement Benefit Obligation effect of 1 percent increase | 194 | 201 | 161 |
Total of Service Cost and Interest Cost effect of 1 percent decrease | (10) | (10) | (9) |
Postretirement Benefit Obligation effect of 1 percent decrease | $ (160) | $ (165) | $ (134) |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.92% | 4.50% | |
Expected Return on Plan Assets | 7.70% | ||
Rate of Compensation Increase | 3.25% | 3.25% | |
Administrative Expense | 5.00% | 5.00% | |
Immediate Rate | 7.55% | 7.33% | |
Ultimate Rate | 4.75% | 5.00% | |
Year Ultimate Rate Reached | 2,025 | 2,021 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount Rate | 4.97% | 4.60% | |
Rate of Compensation Increase | 3.25% | 3.25% | |
Postretirement Benefit Obligation effect of 1 percent increase | $ 75 | $ 160 | |
Postretirement Benefit Obligation effect of 1 percent decrease | $ (60) | $ (106) |
Pension, OPEB and Savings Pla94
Pension, OPEB and Savings Plans (Fair Value Measurements And The Levels Of Inputs Used In Determining Fair Values) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | $ 5,413 | $ 5,654 | ||||
Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [1] | 103 | 153 | |||
Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 1,980 | 2,292 | |||
Common Stocks Commingled - International [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 987 | 1,005 | |||
Other Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 816 | 727 | |||
Government (US & Foreign) Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 602 | 509 | |||
Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 906 | 943 | |||
Private Equity [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 19 | 25 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 3,885 | 4,116 | ||||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [1] | 102 | 92 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 1,980 | 2,292 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Common Stocks Commingled - International [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 987 | 1,005 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Other Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 816 | 727 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Government (US & Foreign) Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Quoted Market Prices for Identical Assets (Level 1) [Member] | Private Equity [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 1,509 | 1,513 | ||||
Significant Other Observable Inputs (Level 2) [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [1] | 1 | 61 | |||
Significant Other Observable Inputs (Level 2) [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Common Stocks Commingled - International [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | Government (US & Foreign) Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 602 | 509 | |||
Significant Other Observable Inputs (Level 2) [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 906 | 943 | |||
Significant Other Observable Inputs (Level 2) [Member] | Private Equity [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 19 | 25 | ||||
Pension And OPEB Plans Level 3 [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [1] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Common Stocks Commingled - International [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Other Securities [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [2] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Government (US & Foreign) Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [3] | 0 | 0 | |||
Pension And OPEB Plans Level 3 [Member] | Private Equity [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 19 | [3] | 25 | [3] | $ 25 | |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 97 | 69 | ||||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [4] | 0 | 1 | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [5] | 68 | 48 | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | [6] | 29 | 20 | |||
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 | 68 | 48 | ||||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 0 | [4] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 68 | 48 | [5] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Quoted Market Prices for Identical Assets (Level 1) [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 0 | [6] | |||
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 | 29 | 21 | ||||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 1 | [4] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 0 | [5] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 29 | 20 | [6] | |||
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] | Cash Equivalents [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 0 | [4] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Common Stocks Commingled - US [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | 0 | 0 | [5] | |||
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension And OPEB Plans Level 3 [Member] | Other Bonds [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Fair value of plan assets | $ 0 | $ 0 | [6] | |||
[1] | 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). | |||||
[2] | Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. | |||||
[3] | Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). | |||||
[4] | Certain temporary investments are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (Level 2). | |||||
[5] | Wherever possible, fair values of equity investments in commingled stock funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price. | |||||
[6] | Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). |
Pension, OPEB and Savings Pla95
Pension, OPEB and Savings Plans (Reconciliations Of The Beginning And Ending Balances Of Pension And OPEB Plans' Level 3 Assets) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | |||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair Value of Assets at Beginning of Year | $ 5,654 | |||
Fair Value of Assets at End of Year | 5,413 | $ 5,654 | ||
Pension And OPEB Plans Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair Value of Assets at Beginning of Year | 25 | |||
Fair Value of Assets at End of Year | 19 | 25 | ||
Private Equity [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair Value of Assets at Beginning of Year | [1] | 25 | ||
Fair Value of Assets at End of Year | [1] | 19 | 25 | |
Private Equity [Member] | Pension And OPEB Plans Level 3 [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Fair Value of Assets at Beginning of Year | 25 | [1] | 25 | |
Purchases/(Sales) | (10) | (5) | ||
Transfer In/ (Out) | 0 | 0 | ||
Actual Return on Asset Sales | 1 | 3 | ||
Actual Return on Assets Still Held | 3 | 2 | ||
Fair Value of Assets at End of Year | [1] | $ 19 | $ 25 | |
[1] | Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). |
Pension, OPEB and Savings Pla96
Pension, OPEB and Savings Plans (Schedule Of Percentage Of Fair Value Of Total Plan Assets) (Details) | Dec. 31, 2015 | Dec. 31, 2014 |
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% | 71.00% |
Fixed Income Securities [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 28.00% | 26.00% |
Other Investments [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 2.00% | 3.00% |
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% | 70.00% |
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% |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Investments [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Actual plan asset allocation, percent | 0.00% | 1.00% |
Pension, OPEB and Savings Pla97
Pension, OPEB and Savings Plans (Estimated Future Benefit Payments) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | $ 285 |
2,017 | 295 |
2,018 | 305 |
2,019 | 317 |
2,020 | 329 |
2021-2025 | 1,818 |
Total Estimated Future Benefit Payments | 3,349 |
Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | 81 |
2,017 | 84 |
2,018 | 87 |
2,019 | 91 |
2,020 | 95 |
2021-2025 | 518 |
Total Estimated Future Benefit Payments | 956 |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | 1 |
2,017 | 2 |
2,018 | 3 |
2,019 | 4 |
2,020 | 6 |
2021-2025 | 60 |
Total Estimated Future Benefit Payments | 76 |
Long Island Electric Utility Servco LLC Pension and OPEB [Member] | Other Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,016 | 3 |
2,017 | 5 |
2,018 | 7 |
2,019 | 8 |
2,020 | 10 |
2021-2025 | 80 |
Total Estimated Future Benefit Payments | $ 113 |
Pension, OPEB and Savings Pla98
Pension, OPEB and Savings Plans (Schedule Of Amount Paid For Employer Matching Contributions) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | $ 39 | $ 36 | $ 33 |
Power [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | 12 | 11 | 10 |
PSE&G [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | 22 | 20 | 19 |
Other [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Total Employer Matching Contributions | $ 5 | $ 5 | $ 4 |
Commitments And Contingent Li99
Commitments And Contingent Liabilities (Face Value Of Outstanding Guarantees, Current Exposure And Margin Positions) (Detail) - Power [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Other Commitments [Line Items] | ||
Face Value of Outstanding Guarantees | $ 1,734 | $ 1,814 |
Exposure under Current Guarantees | 172 | 273 |
Letters of Credit Margin Posted | 122 | 159 |
Letters of Credit Margin Received | 192 | 40 |
Counterparty Cash Margin Deposited | 0 | 0 |
Counterparty Cash Margin Received | (15) | (13) |
Net Broker Balance Deposited (Received) | (5) | 115 |
Additional Collateral that could be Required | 864 | 945 |
Liquidity Available under PSEG's and Power's Credit Facilities to Post Collateral | 3,215 | 3,495 |
Other Letters of Credit | 51 | $ 45 |
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 L100
Commitments And Contingent Liabilities (Environmental Matters) (Detail) | 1 Months Ended | 12 Months Ended | ||||||
Jun. 30, 2008USD ($) | Dec. 31, 2015USD ($)Potentially_Responsible_PartysiteentityStationPlantmi | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Sep. 30, 2015USD ($) | 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 | $ 415,000,000 | $ 417,000,000 | ||||||
New Salem facility cooling towers estimated cost total | 1,000,000,000 | |||||||
Operation and Maintenance | 2,978,000,000 | 3,150,000,000 | $ 2,887,000,000 | |||||
New England Generation Fleet | 11,842,000,000 | 11,153,000,000 | ||||||
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 | 365,000,000 | 364,000,000 | ||||||
Regulatory assets | 3,360,000,000 | 3,764,000,000 | ||||||
Operation and Maintenance | 1,560,000,000 | 1,558,000,000 | 1,639,000,000 | |||||
New England Generation Fleet | 569,000,000 | 521,000,000 | ||||||
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% | |||||||
New Salem facility cooling towers estimated cost total | $ 575,000,000 | |||||||
Operation and Maintenance | 1,057,000,000 | 1,186,000,000 | $ 1,224,000,000 | |||||
New England Generation Fleet | 11,273,000,000 | $ 10,632,000,000 | ||||||
New Jersey Clean Energy Program Unfavorable Regulatory Action [Member] | ||||||||
Site Contingency [Line Items] | ||||||||
Loss Contingency, Estimate of Possible Loss | 345,000,000 | |||||||
New Jersey Clean Energy Program Unfavorable Regulatory Action [Member] | PSE&G [Member] | ||||||||
Site Contingency [Line Items] | ||||||||
Loss Contingency, Estimate of Possible Loss | 200,000,000 | |||||||
Clean Energy Program Current | 142,000,000 | |||||||
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 | 431,000,000 | |||||||
Estimated expenditures, high end of range | 499,000,000 | |||||||
Accrued environmental costs | 431,000,000 | |||||||
Remediation liability recorded as other current liabilities | 76,000,000 | |||||||
Remediation liability recorded as environmental costs in noncurrent liabilities | 355,000,000 | |||||||
Regulatory assets | 431,000,000 | |||||||
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 | $ 163,000,000 | |||||||
Number Of Potentially Responsible Parties In Connection With Environmental Liabilities For Operations Conducted Near Passaic River | Potentially_Responsible_Party | 54 | 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 | $ 147,000,000 | |||||||
Company Share of Total Spend of Study to date | 10,000,000 | |||||||
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-low estimate | 365,000,000 | |||||||
Estimated cleanup costs-high estimate | 3,250,000,000 | |||||||
Estimated Cleanup Costs EPA Preferred Method | 1,700,000,000 | |||||||
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 | |||||||
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 | |||||||
Passaic River Site Contingency [Member] | Power [Member] | ||||||||
Site Contingency [Line Items] | ||||||||
CPG Targeted Method Cleanup Costs Low Estimate | $ 3,000,000 | |||||||
New England Fleet [Member] | Power [Member] | ||||||||
Site Contingency [Line Items] | ||||||||
New England Generation Fleet | $ 210,000,000 |
Commitments And Contingent L101
Commitments And Contingent Liabilities (Basic Generation Service (BGS) And Basic Gas Supply Service (BGSS)) (Detail) cf in Billions | 12 Months Ended | |
Dec. 31, 2015cf$ / mwh$ / mwdMW | ||
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 2013 [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
36-Month Terms Ending | May 31, 2016 | |
Load (MW) | MW | 2,800 | |
Dollars Per Megawatt Hour | $ / mwh | 92.18 | |
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 | |
$ per kWh | $ / mwd | 272.78 | |
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 | |
$ per kWh | $ / mwd | 335.33 | |
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 | [1] |
Load (MW) | MW | 2,800 | |
Dollars Per Megawatt Hour | $ / mwh | 96.38 | |
[1] | Prices set in the 2016 BGS auction will become effective on June 1, 2016 when the 2013 BGS auction agreements expire. |
Commitments And Contingent L102
Commitments And Contingent Liabilities (Minimum Fuel Purchase Requirements) (Detail) - Power [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
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 | $ 475 |
Commitments Through 2017 [Member] | Nuclear Fuel Enrichment [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 394 |
Commitments Through 2017 [Member] | Nuclear Fuel Fabrication [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 204 |
Commitments Through 2017 [Member] | Natural Gas [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | 1,023 |
Commitments Through 2017 [Member] | Coal [Member] | |
Long-term Purchase Commitment [Line Items] | |
Total minimum purchase requirements | $ 300 |
Commitments And Contingent L103
Commitments And Contingent Liabilities (Regulatory Proceedings) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | 30 Months Ended | 39 Months Ended | |||
Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 30, 2015 | Mar. 31, 2015 | |
Loss Contingencies [Line Items] | |||||||
Costs recognized in Operation and Maintenance Expense | $ 2,978 | $ 3,150 | $ 2,887 | ||||
Insured Event, Gain (Loss) | 28 | ||||||
New Jersey Clean Energy Program [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Aggregate funding for New Jersey Clean Energy Program | 345 | ||||||
Superstorm Sandy [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Proceeds from insurance recoveries | $ 55 | $ 159 | 214 | $ 264 | |||
PSE&G [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Costs recognized in Operation and Maintenance Expense | 1,560 | 1,558 | 1,639 | ||||
Insured Event, Gain (Loss) | 0 | ||||||
PSE&G [Member] | New Jersey Clean Energy Program [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Aggregate funding for New Jersey Clean Energy Program | 200 | ||||||
PSE&G [Member] | Superstorm Sandy [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Costs recognized in Operation and Maintenance Expense | (10) | 40 | |||||
Costs incurred to restore service | 295 | ||||||
Utilities, Costs Incurred to Restore Service portion attributable to insured property | 36 | ||||||
Utilities, Costs Incurred to Repair Infrastructure to Pre-Storm Conditions | 5 | ||||||
Cost recorded as Property, Plant and Equipment | (11) | 75 | |||||
Costs recorded as Regulatory Asset | (20) | 180 | |||||
Proceeds from insurance recoveries | 35 | 6 | |||||
Power [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Costs recognized in Operation and Maintenance Expense | 1,057 | 1,186 | 1,224 | ||||
Insured Event, Gain (Loss) | 28 | ||||||
Power [Member] | Regulatory Agency [Domain] | |||||||
Loss Contingencies [Line Items] | |||||||
Loss Contingency, Loss in Period | $ 25 | ||||||
Power [Member] | Superstorm Sandy [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Costs recognized in Operation and Maintenance Expense | 2 | $ 193 | |||||
Proceeds from insurance recoveries | 179 | $ 44 | |||||
Property, Plant and Equipment [Member] | Power [Member] | Superstorm Sandy [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Insured Event, Gain (Loss) | 6 | ||||||
Operation and Maintenance Expense [Member] | Power [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Insured Event, Gain (Loss) | 145 | ||||||
Other Income [Member] | Power [Member] | |||||||
Loss Contingencies [Line Items] | |||||||
Insured Event, Gain (Loss) | $ 28 |
Commitments And Contingent L104
Commitments And Contingent Liabilities (Nuclear Insurance Coverages and Assessments) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2015USD ($)MW | ||
Other Commitments [Line Items] | ||
Retrospective Assessment Power Generation | MW | 100 | |
Inflation Adjustment For Assessment Years | 5 years | |
Nuclear Insurance Aggregate Limit | $ 3,200 | |
Limit Of Liability Per Price Anderson Act | 13,500 | |
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 | 13,488 | [1] |
Property Damage, Total | 2,100 | |
Replacement Power Total | 1,016 | |
Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Nuclear Liability, Total | 401 | |
Property Damage, Total | 52 | |
Replacement Power Total | 24 | |
Power With Exelon Generation [Member] | ||
Other Commitments [Line Items] | ||
Blanket limit shared | 600 | |
ANI [Member] | Total Site Coverage [Member] | ||
Other Commitments [Line Items] | ||
Public and Nuclear Worker Liability, Primary Layer | 375 | [2] |
ANI [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Public and Nuclear Worker Liability, Primary Layer | 0 | |
Price-Anderson Act [Member] | Total Site Coverage [Member] | ||
Other Commitments [Line Items] | ||
Nuclear Liability, Excess Layer | 13,113 | [3] |
Price-Anderson Act [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Nuclear Liability, Excess Layer | 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 | 600 | [4] |
NEIL II (Salem/Hope Creek/Peach Bottom) [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Property Damage, Primary Layer | 46 | |
Property Damage, Excess Layers | 6 | |
NEIL I (Peach Bottom) [Member] | ||
Other Commitments [Line Items] | ||
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] | Total Site Coverage [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | $ 245 | [5] |
NEIL I (Peach Bottom) [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | 8 | |
NEIL I (Salem) [Member] | ||
Other Commitments [Line Items] | ||
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 I (Salem) [Member] | Total Site Coverage [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | $ 281 | [5] |
NEIL I (Salem) [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | 9 | |
NEIL I (Hope Creek) [Member] | ||
Other Commitments [Line Items] | ||
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] | Total Site Coverage [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | $ 490 | [5] |
NEIL I (Hope Creek) [Member] | Retrospective Assessments [Member] | ||
Other Commitments [Line Items] | ||
Accidental Outage | $ 7 | |
[1] | Limit of liability under the Price-Anderson Act for each nuclear incident. | |
[2] | The primary limit for Public Liability is a per site aggregate limit with no potential for 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 participates in a $600 million nuclear event Blanket Limit Policy. The blanket limit policy is shared with Exelon Generation and covers the following facilities: Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 Peach Bottom, Salem and Hope Creek. This limit is not subject to reinstatement in the event of a loss. Participation in this program reduces Power’s premium and the associated potential assessment. In addition, for non-nuclear event limits in excess of $1.5 billion, Power maintains a $600 million limit shared by the Salem and Hope Creek facilities. Exelon maintains a $600 million non-nuclear event limit shared by Peach Bottom, Braidwood, Byron, Clinton, Dresden, LaSalle, Limerick, Oyster Creek, Quad Cities, and the TMI-1 facilities. | |
[5] | Peach Bottom 2 and 3 have an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem 1 and 2 have an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 76 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. |
Commitments And Contingent L105
Commitments And Contingent Liabilities (Future Minimum Lease Payments) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Other Commitments [Line Items] | |
2,016 | $ 29 |
2,017 | 25 |
2,018 | 24 |
2,019 | 22 |
2,020 | 22 |
Thereafter | 245 |
Capital Leases, Future Minimum Payments Due | 367 |
PSE&G [Member] | |
Other Commitments [Line Items] | |
2,016 | 12 |
2,017 | 9 |
2,018 | 8 |
2,019 | 7 |
2,020 | 6 |
Thereafter | 66 |
Capital Leases, Future Minimum Payments Due | 108 |
Power [Member] | |
Other Commitments [Line Items] | |
2,016 | 2 |
2,017 | 2 |
2,018 | 2 |
2,019 | 2 |
2,020 | 3 |
Thereafter | 33 |
Capital Leases, Future Minimum Payments Due | 44 |
Services [Member] | |
Other Commitments [Line Items] | |
2,016 | 13 |
2,017 | 13 |
2,018 | 13 |
2,019 | 13 |
2,020 | 13 |
Thereafter | 146 |
Capital Leases, Future Minimum Payments Due | 211 |
Other [Member] | |
Other Commitments [Line Items] | |
2,016 | 2 |
2,017 | 1 |
2,018 | 1 |
2,019 | 0 |
2,020 | 0 |
Thereafter | 0 |
Capital Leases, Future Minimum Payments Due | $ 4 |
Schedule Of Consolidated Deb106
Schedule Of Consolidated Debt (Long-Term Debt) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2009 | ||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 9,639 | |||
Long-term Debt, Current Maturities | (734) | $ (624) | ||
PSEG [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | 500 | |||
Fair Value Of Swaps | [1] | 6 | 22 | |
Long-term Debt, Current Maturities | (6) | (8) | ||
Net Unamortized Discount and Debt Issuance Costs | [2] | 0 | 8 | |
Current Portion of Unamortized Discount on Debt Exchange | [2] | 3 | ||
Total Long-Term Debt | 500 | 6 | ||
PSEG [Member] | Variable Rate Term Loan due 2017 [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | 500 | 0 | ||
PSE&G [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term Debt, Current Maturities | (171) | (300) | ||
Total Long-Term Debt | 6,650 | 5,975 | ||
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] | $ 171 | 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 | $ 320 | 320 | ||
PSE&G [Member] | Pollution Control Bonds Due On 2033 [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | [3],[4] | $ 50 | 50 | |
Maturity Year | [3],[4] | 2,033 | ||
PSE&G [Member] | Pollution Control Bonds Due On 2046 [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | [3],[4] | $ 50 | 50 | |
Maturity Year | [3],[4] | 2,046 | ||
PSE&G [Member] | Pollution Control Bonds [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 100 | 100 | ||
PSE&G [Member] | Medium Term Notes Two Point Seven Zero Percentage Due On Two Thousand Fifteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | [3] | $ 0 | 300 | |
Stated interest rate of debt instrument | 2.70% | |||
Maturity Year | [3] | 2,015 | ||
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 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 | 0 | |
Stated interest rate of debt instrument | 3.00% | |||
Maturity Year | [3] | 2,025 | ||
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 | 0 | |
Stated interest rate of debt instrument | 4.15% | |||
Maturity Year | [3] | 2,045 | ||
PSE&G [Member] | Total Medium Term Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 6,459 | 5,909 | ||
PSE&G [Member] | Securitization Bonds Six Point Eight Nine Percentage Due On Two Thousand Fourteen To Two Thousand Fifteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 0 | 251 | ||
Stated interest rate of debt instrument | 6.89% | |||
Maturity Year | 2014-2015 | |||
PSE&G [Member] | Transition Funding [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 0 | 251 | ||
Long-term Debt, Current Maturities | 0 | (251) | ||
Total Long-Term Debt | 0 | 0 | ||
PSE&G [Member] | Securitization Bonds Four Point Five Seven Percentage Due On Two Thousand Thirteen To Two Thousand Fifteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 0 | 8 | ||
Stated interest rate of debt instrument | 4.57% | |||
Maturity Year | 2014-2015 | |||
PSE&G [Member] | Transition Funding II [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 0 | 8 | ||
Long-term Debt, Current Maturities | 0 | (8) | ||
Total Long-Term Debt | 0 | 0 | ||
Power [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | 2,253 | 2,553 | ||
Long-term Debt, Current Maturities | (553) | (300) | ||
Net Unamortized Discount and Debt Issuance Costs | 16 | 19 | ||
Total Long-Term Debt | 1,684 | 2,234 | ||
Power [Member] | Senior Notes Five Point Five Zero Percentage Due Two Thousand Fifteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 0 | 300 | ||
Stated interest rate of debt instrument | 5.50% | |||
Maturity Year | 2,015 | |||
Power [Member] | Senior Notes Five Point Three Two Percentage Due Two Thousand Sixteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 303 | 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 | $ 250 | 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 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 | $ 2,209 | 2,509 | ||
Power [Member] | Pollution Control Notes Floating Rate Due On Two Thousand Fourteen [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | [4] | $ 44 | 44 | |
Maturity Year | [4] | 2,019 | ||
Power [Member] | Pollution Control Notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 44 | 44 | ||
PSE&G Excluding Transition Funding and Transition Funding II [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | 6,879 | 6,329 | ||
Long-term Debt, Current Maturities | (171) | (300) | ||
Net Unamortized Discount and Debt Issuance Costs | 58 | 54 | ||
Total Long-Term Debt | 6,650 | $ 5,975 | ||
Energy Holdings [Member] | ||||
Debt Instrument [Line Items] | ||||
Principal Amount Outstanding | $ 7 | |||
Senior Notes 8.50% Due On 2011 [Member] | Energy Holdings [Member] | ||||
Debt Instrument [Line Items] | ||||
Stated interest rate of debt instrument | 8.50% | |||
[1] | 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 15. Financial Risk Management Activities. | |||
[2] | In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The remaining deferred amount of $3 million as of December 31, 2015 is reflected as an offset to Long-Term Debt due within one year on PSEG’s Consolidated Balance Sheets. | |||
[3] | Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage. | |||
[4] | The Pollution Control Financing Authority of Salem County bonds and the Pennsylvania Economic Development Authority (PEDFA) bond that are serviced and secured by PSE&G Pollution Control Bonds and Power Pollution Control Notes, respectively, are variable rate bonds that are in weekly reset mode. In October 2014, Power executed an extension of the letter of credit backing the PEDFA bond which expires on November 30, 2019. |
Schedule Of Consolidated Deb107
Schedule Of Consolidated Debt (Long-Term Debt Maturities) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
2,016 | $ 731 | |
2,017 | 500 | |
2,018 | 1,000 | |
2,019 | 544 | |
2,020 | 665 | |
Thereafter | 6,199 | |
Total | 9,639 | |
PSEG [Member] | ||
Debt Instrument [Line Items] | ||
2,016 | 0 | |
2,017 | 500 | |
2,018 | 0 | |
2,019 | 0 | |
2,020 | 0 | |
Thereafter | 0 | |
Total | 500 | |
PSE&G | ||
Debt Instrument [Line Items] | ||
2,016 | 171 | |
2,017 | 0 | |
2,018 | 750 | |
2,019 | 500 | |
2,020 | 259 | |
Thereafter | 5,199 | |
Total | 6,879 | $ 6,329 |
Power [Member] | ||
Debt Instrument [Line Items] | ||
2,016 | 553 | |
2,017 | 0 | |
2,018 | 250 | |
2,019 | 44 | |
2,020 | 406 | |
Thereafter | 1,000 | |
Total | 2,253 | $ 2,553 |
Energy Holdings [Member] | ||
Debt Instrument [Line Items] | ||
2,016 | 7 | |
2,017 | 0 | |
2,018 | 0 | |
2,019 | 0 | |
2,020 | 0 | |
Thereafter | 0 | |
Total | $ 7 |
Schedule Of Consolidated Deb108
Schedule Of Consolidated Debt (Long-Term Debt Financing Transactions) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended |
Jan. 31, 2016 | Dec. 31, 2015 | |
PSEG [Member] | Variable Rate Term Loan | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 500 | |
PSE&G [Member] | Medium Term Notes Three Point Zero Percent Due In Two Thousand Twenty Five [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 350 | |
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] | ||
Debt Instrument, Face Amount | $ 250 | |
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] | ||
Proceeds from Issuance of Long-term Debt | $ 250 | |
Stated interest rate of debt instrument | 4.15% | |
PSE&G [Member] | Medium Term Notes Two Point Seven Zero Percentage Due On Two Thousand Fifteen [Member] | ||
Debt Instrument [Line Items] | ||
Stated interest rate of debt instrument | 2.70% | |
Repayments of Long-term Debt | $ 300 | |
PSE&G [Member] | Transition Fundings Securitization Debt [Member] | ||
Debt Instrument [Line Items] | ||
Repayments of Long-term Debt | 251 | |
PSE&G [Member] | Transition Fundings Ii Securitization Debt [Member] | ||
Debt Instrument [Line Items] | ||
Repayments of Long-term Debt | $ 8 | |
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% | |
Power [Member] | Senior Notes Five Point Five Zero Percentage Due Two Thousand Fifteen [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Face Amount | $ 300 | |
Stated interest rate of debt instrument | 5.50% | |
Subsequent Event [Member] | PSE&G [Member] | First And Refunding Mortgage Bonds Six Point Seven Five Percentage Due On Two Thousand Sixteen [Member] | ||
Debt Instrument [Line Items] | ||
Repayments of Long-term Debt | $ 171 |
Schedule Of Consolidated Deb109
Schedule Of Consolidated Debt (Short-Term Liquidity) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | ||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | $ 4,200 | ||
Line of Credit Facility, Amount Outstanding | 552 | ||
Available Liquidity | 3,648 | ||
Commercial Paper and Loans | $ 364 | $ 0 | |
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 | 221 | ||
Available Liquidity | 779 | ||
PSE&G [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 600 | ||
Line of Credit Facility, Amount Outstanding | 167 | ||
Available Liquidity | 433 | ||
Commercial Paper and Loans | 153 | $ 0 | |
Power [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | 2,600 | ||
Line of Credit Facility, Amount Outstanding | 164 | ||
Available Liquidity | 2,436 | ||
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 | Apr 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 | 161 | ||
Available Liquidity | $ 1,439 | ||
Expiration Date | Apr 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] | 211 | |
Available Liquidity | 289 | ||
Commercial Paper and Loans | [2] | $ 211 | |
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in April 2016 | [3] | $ 23 | |
Credit Facility Reduction in March 2018 | [3] | $ 12 | |
Short-term Debt, Weighted Average Interest Rate | [2] | 0.96% | |
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] | 167 | |
Available Liquidity | 433 | ||
Commercial Paper and Loans | [2] | $ 153 | |
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in April 2016 | [3] | $ 29 | |
Credit Facility Reduction in March 2018 | [3] | $ 14 | |
Short-term Debt, Weighted Average Interest Rate | [2] | 0.91% | |
Five Year Credit Facility Maturing on April 2020 [Member] | Power [Member] | |||
Short-term Debt [Line Items] | |||
Line of Credit Facility, Maximum Borrowing Capacity | [3] | $ 1,000 | |
Line of Credit Facility, Amount Outstanding | 3 | ||
Available Liquidity | $ 997 | ||
Expiration Date | Apr 2,020 | ||
Credit Facility Reduction in April 2016 | [3] | $ 48 | |
Credit Facility Reduction in March 2018 | [3] | $ 24 | |
[1] | PSEG facility will be reduced by $23 million in April 2016 and $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, 2015, $211 million and $153 million, respectively, were outstanding. The weighted average interest rates on PSEG's and PSE&G's Commercial Paper Programs were 0.96% and 0.91%, respectively, at December 31, 2015. | ||
[3] | PSE&G facility will be reduced by $29 million in April 2016 and $14 million in March 2018. | ||
[4] | Power facility will be reduced by $48 million in April 2016 and $24 million in March 2018. |
Schedule Of Consolidated Deb110
Schedule Of Consolidated Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 9,568 | $ 9,098 | |
Long-term Debt, Fair Value | 10,256 | 10,149 | |
PSEG [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 503 | 14 | |
Long-term Debt, Fair Value | [1] | 506 | 22 |
PSE&G | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 6,821 | 6,275 | |
Long-term Debt, Fair Value | [2] | 7,235 | 6,912 |
Transition Funding [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 0 | 251 | |
Long-term Debt, Fair Value | [2] | 0 | 261 |
Transition Funding II [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 0 | 8 | |
Long-term Debt, Fair Value | [2] | 0 | 8 |
Power [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 2,237 | 2,534 | |
Long-term Debt, Fair Value | [2] | 2,508 | 2,930 |
Energy Holdings [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 7 | 16 | |
Long-term Debt, Fair Value | [3] | $ 7 | $ 16 |
[1] | . | ||
[2] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjEzNGM1ZjNhZTdjZTQzNzE4NjgyYzYxZmQ0OWExMWNjfFRleHRTZWxlY3Rpb246QUY1MUNBNzREQTEzNTVCODBCRDdBOTAwM0RGNzMxRkYM} | ||
[3] | Non-recourse project debt is valued as equivalent to the amortized cost and is classified as a Level 3 measurement. |
Schedule Of Consolidated Cap111
Schedule Of Consolidated Capital Stock (Consolidated Capital Stock) (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Class of Stock [Line Items] | |||
Common Stock, authorized | 1,000,000,000 | 1,000,000,000 | |
Common Stock, Shares, outstanding | [1] | 505,282,421 | 505,836,592 |
Common Stock, book value | [1] | $ 4,244 | $ 4,241 |
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 2015 or 2014. 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, 2015. |
Financial Risk Management Ac112
Financial Risk Management Activities (Schedule Of Derivative Transactions Designated And Effective As Cash Flow Hedges) (Detail) - Power [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative [Line Items] | ||
Fair Value of Cash Flow Hedges | $ 0 | $ 18 |
Impact on Accumulated Other Comprehensive Income (Loss) (after tax) | $ 0 | $ 10 |
Financial Risk Management Ac113
Financial Risk Management Activities (Narrative) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | $ (55) | $ 24 | |
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral | 78 | 127 | |
Additional collateral aggregate fair value | 864 | 945 | |
PSEG [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Aggregate amount of series of interest rate swaps converting to variable-rate debt | 550 | ||
Fair value of interest rate swaps designated as underlying hedges | 6 | 22 | |
Aggregate fair value of derivative contracts in a liability position that contains triggers for additional collateral | 12 | 18 | |
Additional collateral aggregate fair value | 66 | 109 | |
Amount of reduction in interest expense attributed to interest rate swaps designated as fair value hedges | 19 | 20 | $ 19 |
PSEG [Member] | Senior Notes 5.5% Due December 2015 [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Senior Notes converted into variable rate debt | $ 300 | ||
PSEG [Member] | Senior Notes 5.32% Due September 2016 [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Stated interest rate of debt instrument | 5.32% | ||
PSEG [Member] | Senior Notes 2.75% Due September 2016 [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Senior Notes converted into variable rate debt | $ 250 | ||
Stated interest rate of debt instrument | 2.75% | ||
Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net Credit Exposure With Counterparties After Applying Collateral | $ 312 | ||
Power [Member] | Senior Notes 5.32% Due September 2016 [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Senior Notes converted into variable rate debt | 303 | ||
Non Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | (16) | (8) | |
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | 12 | 32 | |
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | 2 | 4 | |
Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Net cash collateral received in connection with net derivative contracts | $ (53) | $ (4) |
Financial Risk Management Ac114
Financial Risk Management Activities (Schedule Of Derivative Instruments Fair Value In Balance Sheets) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ (55) | $ 24 | |
Derivative Contracts, Current Assets | 242 | 240 | |
Derivative Contracts, Noncurrent Assets | 77 | 77 | |
Total Mark-to-Market Derivative Assets | 319 | 317 | |
Derivative Contracts, Current Liabilities | (76) | (132) | |
Derivative Contracts, Noncurrent Liabilities | (27) | (33) | |
Total Mark-to-Market Derivative (Liabilities) | (103) | (165) | |
Net Mark-to-Market Derivative Assets (Liabilities) | 216 | 152 | |
Power [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 223 | 207 | [1] |
Derivative Contracts, Noncurrent Assets | 77 | 62 | [1] |
Total Mark-to-Market Derivative Assets | 300 | 269 | [1] |
Derivative Contracts, Current Liabilities | (76) | (132) | [1] |
Derivative Contracts, Noncurrent Liabilities | (16) | (33) | [1] |
Total Mark-to-Market Derivative (Liabilities) | (92) | (165) | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 208 | 104 | [1] |
Power [Member] | Netting [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | (477) | (408) | [1],[2] |
Derivative Contracts, Noncurrent Assets | (131) | (109) | [1],[2] |
Total Mark-to-Market Derivative Assets | (608) | (517) | [1],[2] |
Derivative Contracts, Current Liabilities | 437 | 436 | [1],[2] |
Derivative Contracts, Noncurrent Liabilities | 116 | 105 | [1],[2] |
Total Mark-to-Market Derivative (Liabilities) | 553 | 541 | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | (55) | 24 | [1],[2] |
Power [Member] | Energy-Related Contracts [Member] | Cash Flow Hedging [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 0 | 18 | [1] |
Derivative Contracts, Noncurrent Assets | 0 | 0 | [1] |
Total Mark-to-Market Derivative Assets | 0 | 18 | [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) | 0 | 18 | [1] |
PSE&G [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 13 | 18 | |
Derivative Contracts, Noncurrent Assets | 0 | 8 | |
Derivative Contracts, Noncurrent Liabilities | (11) | 0 | |
PSEG [Member] | Interest Rate Swaps [Member] | Fair Value Hedging [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 6 | 15 | [1] |
Derivative Contracts, Noncurrent Assets | 0 | 7 | [1] |
Total Mark-to-Market Derivative Assets | 6 | 22 | [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) | 6 | 22 | [1] |
Not Designated as Hedging Instrument [Member] | Power [Member] | Energy-Related Contracts [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 700 | 597 | [1] |
Derivative Contracts, Noncurrent Assets | 208 | 171 | [1] |
Total Mark-to-Market Derivative Assets | 908 | 768 | [1] |
Derivative Contracts, Current Liabilities | (513) | (568) | [1] |
Derivative Contracts, Noncurrent Liabilities | (132) | (138) | [1] |
Total Mark-to-Market Derivative (Liabilities) | (645) | (706) | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 263 | 62 | [1] |
Not Designated as Hedging Instrument [Member] | PSE&G [Member] | Energy-Related Contracts [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative Contracts, Current Assets | 13 | 18 | [1] |
Derivative Contracts, Noncurrent Assets | 0 | 8 | [1] |
Total Mark-to-Market Derivative Assets | 13 | 26 | [1] |
Derivative Contracts, Current Liabilities | 0 | 0 | [1] |
Derivative Contracts, Noncurrent Liabilities | (11) | 0 | [1] |
Total Mark-to-Market Derivative (Liabilities) | (11) | 0 | [1] |
Net Mark-to-Market Derivative Assets (Liabilities) | 2 | 26 | [1] |
Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (53) | (4) | |
Non Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (16) | (8) | |
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 12 | 32 | |
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ 2 | $ 4 | |
[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, 2015 and 2014. 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 in the Consolidated Balance Sheets. As of December 31, 2015 and 2014, net cash collateral (received) paid of $(55) million and $24 million, respectively, were netted against the corresponding net derivative contract positions. Of the $(55) million as of December 31, 2015, $(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. Of the $24 million as of December 31, 2014, cash collateral of $(4) million and $(8) million were netted against current assets and noncurrent assets, respectively, and $32 million and $4 million were netted against current liabilities and noncurrent liabilities, respectively. |
Financial Risk Management Ac115
Financial Risk Management Activities (Schedule Of Derivative Instruments Designated As Cash Flow Hedges) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
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 | $ 12 | $ (4) | |||
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 20 | (9) | 12 | |||
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | 0 | 0 | (1) | |||
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) | 3 | 12 | (4) | |||
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 20 | (9) | 13 | |||
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | 0 | 0 | (1) | |||
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) | 3 | 12 | (4) | |||
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 20 | (9) | 13 | |||
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | 0 | 0 | (1) | |||
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) | 3 | 12 | (4) | |||
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 20 | (9) | 13 | |||
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | 0 | 0 | (1) | |||
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) | [1] | 0 | 0 | 0 | ||
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income, Effective Portion | 0 | 0 | [1] | 1 | [1] | |
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) | [1] | $ 0 | $ 0 | $ 0 | ||
[1] | Includes amounts for PSEG parent. |
Financial Risk Management Ac116
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative [Line Items] | |||
Gain (Loss) Recognized in AOCI, After-Tax | $ (30) | $ (135) | $ 299 |
Less: Gain Reclassified to Income, After-Tax | 18 | (53) | (6) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Derivative [Line Items] | |||
Balance as of Beginning of Year | 17 | (4) | |
Gain (Loss) Recognized in AOCI, Pre-Tax | 3 | 12 | |
Less: Gain Reclassified into Income, Pre-Tax | (20) | 9 | (12) |
Balance as of End of Year | 0 | 17 | (4) |
Balance as of Beginning of Year | 10 | (2) | |
Gain (Loss) Recognized in AOCI, After-Tax | 2 | 7 | (2) |
Less: Gain Reclassified to Income, After-Tax | (12) | 5 | (7) |
Balance as of End of Year | $ 0 | $ 10 | $ (2) |
Financial Risk Management Ac117
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | $ 404 | $ (316) | $ (22) |
Operating Revenues [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | 412 | (348) | (128) |
Energy Costs [Member] | Energy-Related Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Pre-Tax Gain (Loss) Recognized in Income on Derivatives | $ (8) | $ 32 | $ 106 |
Financial Risk Management Ac118
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, 2015$ / DTH$ / mwh$ / Derivative | Dec. 31, 2014$ / DTH$ / mwh$ / Derivative | |
Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 201 | 274 |
Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 299 | 310 |
FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 23 | 15 |
Interest Rate Swaps [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / Derivative | 550 | 850 |
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 | 550 | 850 |
Power [Member] | Natural Gas Dth [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | $ / DTH | 168 | 216 |
Power [Member] | Electricity MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 299 | 310 |
Power [Member] | FTRs MWh [Member] | ||
Derivative [Line Items] | ||
Gross volume of derivative on absolute value basis | 23 | 15 |
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 | 33 | 58 |
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 Ac119
Financial Risk Management Activities (Schedule Providing Credit Risk From Others, Net Of Collateral) (Detail) - Power [Member] $ in Millions | 12 Months Ended | |
Dec. 31, 2015USD ($)Counterparty | ||
Derivative [Line Items] | ||
Current Exposure | $ 488 | |
Collateral held from counterparties | 176 | |
Net Credit Exposure With Counterparties After Applying Collateral | 312 | |
Number of Counterparties greater than 10% | 1 | |
Net Exposure of Counterparties greater than 10% | $ 160 | |
Number of active counterparties on credit risk derivatives | Counterparty | 133 | |
Investment Grade - External Rating [Member] | ||
Derivative [Line Items] | ||
Credit exposure, percentage | 92.00% | |
Current Exposure | $ 451 | |
Collateral held from counterparties | 175 | |
Net Credit Exposure With Counterparties After Applying Collateral | 276 | |
Number of Counterparties greater than 10% | 1 | |
Net Exposure of Counterparties greater than 10% | 160 | [1] |
Non-Investment Grade - External Rating [Member] | ||
Derivative [Line Items] | ||
Current Exposure | 24 | |
Collateral held from counterparties | 0 | |
Net Credit Exposure With Counterparties After Applying Collateral | 24 | |
Number of Counterparties greater than 10% | 0 | |
Net Exposure of Counterparties greater than 10% | 0 | |
Investment Grade - No External Rating [Member] | ||
Derivative [Line Items] | ||
Current Exposure | 12 | |
Collateral held from counterparties | 1 | |
Net Credit Exposure With Counterparties After Applying Collateral | 11 | |
Number of Counterparties greater than 10% | 0 | |
Net Exposure of Counterparties greater than 10% | 0 | |
Non-Investment Grade - No External Rating [Member] | ||
Derivative [Line Items] | ||
Current Exposure | 1 | |
Collateral held from counterparties | 0 | |
Net Credit Exposure With Counterparties After Applying Collateral | 1 | |
Number of Counterparties greater than 10% | 0 | |
Net Exposure of Counterparties greater than 10% | 0 | |
Cash [Member] | ||
Derivative [Line Items] | ||
Collateral held from counterparties | 14 | |
Letter of Credit [Member] | ||
Derivative [Line Items] | ||
Collateral held from counterparties | $ 162 | |
[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, 2015 | Dec. 31, 2014 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | $ (55) | $ 24 | ||
Total Mark-to-Market Derivative Assets | 319 | 317 | ||
Total Mark-to-Market Derivative (Liabilities) | (103) | (165) | ||
Power [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative Assets | 300 | 269 | [1] | |
Total Mark-to-Market Derivative (Liabilities) | (92) | (165) | [1] | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2] | 326 | 365 | |
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 | [3] | 865 | 896 | |
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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 42 | 106 | |
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 | [3] | 22 | 23 | |
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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 2 | 0 | |
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 | [3] | 865 | 896 | |
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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 42 | 106 | |
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 | [3] | 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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 1 | 0 | |
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 | [2] | 160 | 294 | |
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 | [3] | 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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 0 | 0 | |
Quoted Market Prices for Identical Assets (Level 1) [Member] | PSE&G [Member] | Energy Related Contracts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative (Liabilities) | 0 | |||
Significant Other Observable Inputs (Level 2) [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2] | 0 | 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 | [3] | 0 | 1 | |
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 | [3] | 488 | 438 | |
Significant Other Observable Inputs (Level 2) [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 359 | 339 | |
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 | [3] | 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 | [3] | 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 | [3] | 108 | 91 | |
Significant Other Observable Inputs (Level 2) [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 81 | 75 | |
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 | [3] | 0 | 2 | |
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 | [3] | 0 | 1 | |
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 | [3] | 488 | 438 | |
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 359 | 339 | |
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 | [3] | 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 | [3] | 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 | [3] | 26 | 21 | |
Significant Other Observable Inputs (Level 2) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 20 | 18 | |
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 | [3] | 0 | 1 | |
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 | [2] | 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 | [3] | 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 | [3] | 21 | 20 | |
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 16 | 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 | [3] | 0 | 0 | |
Significant Other Observable Inputs (Level 2) [Member] | PSE&G [Member] | Energy Related Contracts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative (Liabilities) | 0 | |||
Significant Unobservable Inputs (Level 3) [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2] | 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 | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 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 | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 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 | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 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 | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 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 | [2] | 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 | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 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 | [3] | 0 | 0 | |
Significant Unobservable Inputs (Level 3) [Member] | PSE&G [Member] | Energy Related Contracts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative (Liabilities) | (11) | |||
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 | [4] | 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 | [4] | 6 | 22 | |
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 | [4] | 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 | [5] | 0 | 0 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | 0 | 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 | [5] | 0 | 0 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | 0 | 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 | [5] | 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 | [5] | 896 | 774 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (644) | (705) | |
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 | [5] | 896 | 774 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (644) | (705) | |
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 | [5] | 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 | [5] | 25 | 38 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (12) | (1) | |
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 | [5] | 12 | 12 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (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 | [5] | 13 | 26 | |
Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | (69) | (12) | ||
Other Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative, Fair Value, Amount Offset Against Collateral, Net | 14 | 36 | ||
Cash Collateral Netting [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Equity Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Government Obligations [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Other Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Power [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | PSE&G [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3],[6] | 0 | 0 | |
Cash Collateral Netting [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 | [3],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | PSE&G [Member] | Energy Related Contracts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative (Liabilities) | 0 | |||
Cash Collateral Netting [Member] | Interest Rate Swaps [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative Assets | [4],[6] | 0 | 0 | |
Cash Collateral Netting [Member] | Energy-Related Contracts [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total Mark-to-Market Derivative Assets | [5],[6] | (608) | (517) | |
Total Mark-to-Market Derivative (Liabilities) | [5],[6] | 553 | 541 | |
Cash Collateral Netting [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 | [5],[6] | (608) | (517) | |
Total Mark-to-Market Derivative (Liabilities) | [5],[6] | 553 | 541 | |
Cash Collateral Netting [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 | [5],[6] | 0 | 0 | |
Total Estimate Of Fair Value [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash Equivalents | [2] | 326 | 365 | |
Total Mark-to-Market Derivative Assets | [4] | 6 | ||
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 | [3] | 865 | 897 | |
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 | [3] | 488 | 438 | |
Total Estimate Of Fair Value [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 359 | 339 | |
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 | [3] | 42 | $ 106 | |
Total Estimate Of Fair Value [Member] | Rabbi Trusts - Mutual Funds [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | ||||
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 | [3] | 22 | $ 23 | |
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 | [3] | 108 | 91 | |
Total Estimate Of Fair Value [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 81 | 75 | |
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 | [3] | 2 | 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 | [3] | 865 | 897 | |
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 | [3] | 488 | 438 | |
Total Estimate Of Fair Value [Member] | Power [Member] | Other Debt Securities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 359 | 339 | |
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 | [3] | 42 | 106 | |
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 | [3] | 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 | [3] | 26 | 21 | |
Total Estimate Of Fair Value [Member] | Power [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 20 | 18 | |
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 | [3] | 1 | 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 | [2] | 160 | 294 | |
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 | [3] | 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 | [3] | 21 | 20 | |
Total Estimate Of Fair Value [Member] | PSE&G [Member] | Rabbi Trust - Debt Securities-Other [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measured on Recurring Basis, Investments | [3] | 16 | 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 | [3] | 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 | [4] | 22 | ||
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 | [5] | 313 | 295 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (103) | (165) | |
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 | [5] | 300 | 269 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | (92) | (165) | |
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 | [5] | 13 | $ 26 | |
Total Mark-to-Market Derivative (Liabilities) | [5] | $ (11) | ||
[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, 2015 and 2014. PSE&G does not have any derivative contracts subject to master netting or similar agreements. | |||
[2] | Represents money market mutual funds. | |||
[3] | 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 are limited to investment grade corporate bonds, collateralized mortgage obligations, asset backed securities and government obligations or Federal Agency asset-backed securities 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. 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. | |||
[4] | 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. | |||
[5] | 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 the average of the bid/ask midpoints from multiple broker or dealer quotes 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. | |||
[6] | 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 Consolidated Balance Sheets. 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. As of December 31, 2014, net cash collateral (received) paid of $24 million was netted against the corresponding net derivative contract positions. Of the $24 million of cash collateral as of December 31, 2014, $(12) million was netted against assets and $36 million was netted against liabilities. |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Quantitative Information About Level 3 Fair Value Measurements) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | |||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Assets, Fair Value Disclosure | $ 25 | $ 38 | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (12) | (1) | ||
PSE&G [Member] | ||||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Assets, Fair Value Disclosure | 13 | 26 | ||
Financial and Nonfinancial Liabilities, Fair Value Disclosure | (11) | 0 | ||
Power [Member] | ||||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Assets, Fair Value Disclosure | 12 | 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 | 13 | 26 | [1] | |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ (11) | $ 0 | [1] | |
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] | Megawatt Hours [Member] | PSE&G [Member] | Minimum [Member] | ||||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Transportation Costs | 0.60 | 0.70 | ||
Forward Contracts [Member] | Megawatt Hours [Member] | PSE&G [Member] | Maximum [Member] | ||||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Transportation Costs | 0.80 | 1 | ||
Electric Load Contracts [Member] | Power [Member] | ||||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||||
Assets, Fair Value Disclosure | $ 11 | $ 12 | ||
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 | $ 1 | [2] | $ 0 | [1] |
Financial and Nonfinancial Liabilities, Fair Value Disclosure | $ 0 | [2] | $ 0 | [1] |
[1] | Includes gas supply positions and long-term electric capacity positions which were immaterial as of December 31, 2014. | |||
[2] | Includes long-term electric capacity positions which were immaterial as of December 31, 2015. |
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Settlements | $ (20) | $ 51 | ||
Net Assets Measured At Fair Value On A Recurring Basis | 2,500 | 2,500 | ||
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3 | 13 | 37 | ||
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 | 20 | (31) | ||
Gains and losses attributable to changes in net derivative assets and liabilities, unrealized | 22 | |||
Derivative [Member] | Power [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Transfers, Net | (3) | |||
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 | 37 | $ 88 | ||
Opening Balance | 37 | |||
Included in Income | [1] | (20) | 31 | |
Included in Regulatory Assets/Liabilities | [2] | (24) | (68) | |
Purchases, (Sales) | 0 | 0 | ||
Issuances (Settlements) | [3] | 20 | (51) | |
Transfers In (Out) | [4] | 0 | 3 | |
Closing Balance | 13 | 37 | ||
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 | (6) | ||
Opening Balance | 11 | |||
Included in Income | [1] | (20) | 31 | |
Included in Regulatory Assets/Liabilities | [2] | 0 | 0 | |
Purchases, (Sales) | 0 | 0 | ||
Issuances (Settlements) | [3] | 20 | (51) | |
Transfers In (Out) | [4] | 0 | 3 | |
Closing Balance | 11 | 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 | 26 | $ 94 | ||
Opening Balance | 26 | |||
Included in Income | [1] | 0 | 0 | |
Included in Regulatory Assets/Liabilities | [2] | (24) | (68) | |
Purchases, (Sales) | 0 | 0 | ||
Issuances (Settlements) | [3] | 0 | 0 | |
Transfers In (Out) | [4] | 0 | 0 | |
Closing Balance | $ 2 | $ 26 | ||
[1] | PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $20 million and $(31) million in Operating Income in 2015 and 2014, respectively. The $20 million in Operating Income in 2015 is realized. Of the $(31) million in Operating Income in 2014, $22 million is unrealized. | |||
[2] | Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or Accumulated Other Comprehensive Income (Loss), as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. | |||
[3] | Represents $(20) million and $51 million in settlements for derivative contracts in 2015 and 2014, respectively. | |||
[4] | During the year ended December 31, 2014, $(3) million of net derivatives assets/liabilities were transferred from Level 3 to Level 2 due to more observable pricing for the underlying securities. The transfers were recognized as of the beginning of the quarters (i.e. the quarter in which the transfers occurred), as per PSEG’s policy. |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Detail) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | ||
Net Assets Measured At Fair Value On A Recurring Basis | $ 2,500 | $ 2,500 |
Net Assets Measured At Fair Value On A Recurring Basis Measured Using Unobservable Input And Classified As Level3 | $ 13 | $ 37 |
Stock Based Compensation (Accru
Stock Based Compensation (Accrual Adjustments) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Compensation Cost included in Operation and Maintenance Expense | $ 34 | $ 32 | $ 32 |
Income Tax Benefit Recognized in Consolidated Statement of Operations | $ 14 | $ 13 | $ 13 |
Stock Based Compensation (Stock
Stock Based Compensation (Stock Option Activity) (Details) | 12 Months Ended |
Dec. 31, 2015USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Options, Beginning of Year | shares | 2,075,850 |
Options, Exercised | shares | 368,600 |
Options, Canceled/Forfeited | shares | 0 |
Options, End of Year | shares | 1,707,250 |
Options, Exercisable at End of Year | shares | 1,707,250 |
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 | $ 35.35 |
Options, Exercised, Weighted Average Exercise Price | $ / shares | 32.37 |
Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ / shares | 0 |
Options, End of Year, Weighted Average Exercise Price | $ / shares | 36 |
Options, Exercisable at End of Year, Weighted Average Exercise Price | $ / shares | $ 36 |
Options, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 2 years 9 months 18 days |
Options, Exercisable at End of Year, Weighted Average Remaining Years Contractual Term | 2 years 9 months 18 days |
Options, Outstanding at End of Year, Aggregate Intrinsic Value | $ | $ 8,120,788 |
Options, Exercisable at End of Year, Aggregate Intrinsic Value | $ | $ 8,120,788 |
Stock Based Compensation (Optio
Stock Based Compensation (Options Exercised) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||
Total Intrinsic Value of Options Exercised | $ 3 | $ 4 | $ 1 |
Cash Received from Options Exercised | 12 | 16 | 7 |
Tax Benefit Realized from Options Exercised | $ 0 | $ 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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | 1,069,029 | ||
Shares, Granted | 318,805 | ||
Shares, Vested | (963,387) | ||
Shares, Canceled | (15,940) | ||
Shares, Outstanding at End of Year | 408,507 | 1,069,029 | |
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 | $ 32.49 | ||
Shares, Granted, Weighted Average Grant Date Fair Value | 39.65 | $ 35.16 | $ 31.41 |
Shares, Vested, Weighted Average Grant Date Fair Value | 33.73 | ||
Shares, Canceled, Weighted Average Grant Date Fair Value | 37.28 | ||
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value | $ 34.95 | $ 32.49 | |
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 1 year 1 month 5 days | ||
Shares, Outstanding at End of Year, Aggregate Intrinsic Value | $ 15,805,175 |
Stock Based Compensation (Perfo
Stock Based Compensation (Performance Units Information) (Details) - Performance Units [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | 765,633 | ||
Shares, Granted | 337,585 | ||
Shares, Vested | (655,201) | ||
Shares, Canceled | (44,056) | ||
Shares, Outstanding at End of Year | 403,961 | 765,633 | |
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 | $ 36.86 | ||
Shares, Granted, Weighted Average Grant Date Fair Value | 41.32 | $ 38.94 | $ 35.07 |
Shares, Vested, Weighted Average Grant Date Fair Value | 36.82 | ||
Shares, Cancelled, Weighted Average Grant Date Fair Value | 38.97 | ||
Shares, Outstanding at End of Year, Weighted Average Grant Date Fair Value | $ 40.42 | $ 36.86 | |
Shares, Outstanding at End of Year, Weighted Average Remaining Years Contractual Term | 1 year 7 months 6 days | ||
Shares, Outstanding at End of Year, Aggregate Intrinsic Value | $ 15,629,251 |
Stock Based Compensation (Narra
Stock Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | 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 | 1,000,000 | |||
Total Fair Value of stock options vested | $ 1 | |||
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 | 250,499 | 207,248 | 257,513 | |
Shares issued under employee purchase plan, Average price per share | $ 36.66 | $ 36.07 | $ 30.57 | |
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 | $ 39.65 | $ 35.16 | 31.41 | |
Unrecognized compensation cost related to stock options expected to be recognized | $ 5 | |||
Weighted average period for recognizing unrecognized compensation cost | 1 year | |||
Total intrinsic value of restricted stock units vested | $ 11 | $ 12 | $ 4 | |
Dividend equivalents accrued on stock units | 43,081 | |||
Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Weighted average grant date fair value of granted shares | $ 41.32 | $ 38.94 | $ 35.07 | |
Total intrinsic value of performance units vested | $ 13 | $ 6 | $ 5 | |
Unrecognized compensation cost related to stock options expected to be recognized | $ 15 | |||
Weighted average period for recognizing unrecognized compensation cost | 1 year | |||
Dividend equivalents accrued on stock units | 44,559 | |||
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 | 3,700,000 | |||
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of Other Income [Roll Forward] | |||
NDT Fund Gains, Interest, Dividend and Other Income | $ 138 | $ 219 | $ 152 |
Allowance for Funds Used During Construction | 48 | 31 | 24 |
Solar Loan Interest | 23 | 24 | 23 |
Insured Event, Gain (Loss) | 28 | ||
Other | (17) | (16) | (14) |
Total Other Income | 254 | 290 | 213 |
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 | 48 | 31 | 24 |
Solar Loan Interest | 23 | 24 | 23 |
Insured Event, Gain (Loss) | 0 | ||
Other | (8) | (6) | (7) |
Total Other Income | 79 | 61 | 54 |
Power [Member] | |||
Components of Other Income [Roll Forward] | |||
NDT Fund Gains, Interest, Dividend and Other Income | 138 | 219 | 152 |
Allowance for Funds Used During Construction | 0 | 0 | 0 |
Solar Loan Interest | 0 | 0 | 0 |
Insured Event, Gain (Loss) | 28 | ||
Other | (3) | (3) | (2) |
Total Other Income | 169 | 222 | 154 |
Other [Member] | |||
Components of Other Income [Roll Forward] | |||
NDT Fund Gains, Interest, Dividend and Other Income | 0 | 0 | 0 |
Allowance for Funds Used During Construction | 0 | 0 | 0 |
Solar Loan Interest | 0 | 0 | 0 |
Insured Event, Gain (Loss) | 0 | ||
Other | (6) | (7) | (5) |
Total Other Income | $ 6 | $ 7 | $ 5 |
Other Income And Deductions 131
Other Income And Deductions (Schedule Of Other Deductions) (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | $ 45 | $ 31 | $ 34 | |
Other | 57 | 30 | 20 | |
Total Other Deductions | 102 | 61 | 54 | |
PSE&G [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | 0 | 0 | 0 | |
Other | 4 | 3 | 3 | |
Total Other Deductions | 4 | 3 | 3 | |
Power [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | 45 | 31 | 34 | |
Other | 27 | 21 | 15 | |
Total Other Deductions | 72 | 52 | 49 | |
Other [Member] | ||||
Components of Other Deductions [Roll Forward] | ||||
NDT Fund Realized Losses and Expenses | [1] | 0 | 0 | 0 |
Other | [1] | 26 | 6 | 2 |
Total Other Deductions | [1] | $ 26 | $ 6 | $ 2 |
[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, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Taxes [Line Items] | |||||||||||
Net Income | $ 309 | $ 439 | $ 345 | $ 586 | $ 476 | $ 444 | $ 212 | $ 386 | |||
Net Income | $ 1,679 | $ 1,518 | $ 1,243 | ||||||||
Federal | 243 | 335 | 487 | ||||||||
State | 85 | 58 | 42 | ||||||||
Total Current | 328 | 393 | 529 | ||||||||
Federal | 540 | 262 | 147 | ||||||||
State | 104 | 260 | 118 | ||||||||
Total Deferred | 644 | 522 | 265 | ||||||||
Investment tax credit | 29 | 23 | 18 | ||||||||
Total Income Tax | 1,001 | 938 | 812 | ||||||||
Pre-Tax Income | 2,680 | 2,456 | 2,055 | ||||||||
Tax Computed at Statutory Rate @ 35% | 938 | 860 | 719 | ||||||||
State Income Taxes (net of federal income tax) | 129 | 145 | 108 | ||||||||
Uncertain Tax Positions | 7 | (9) | 10 | ||||||||
Manufacturing Deduction | (10) | (16) | (9) | ||||||||
Nuclear Decommissioning Trust | 7 | 14 | 12 | ||||||||
Plant-Related Items | (20) | (13) | (14) | ||||||||
Tax Credits | (13) | (14) | (9) | ||||||||
Audit Settlement | 0 | (12) | 0 | ||||||||
Nuclear Decommissiong Tax Carryback | (33) | 0 | 0 | ||||||||
Other | (4) | (17) | (5) | ||||||||
Sub-Total | 63 | 78 | 93 | ||||||||
Total Income Tax Provision | $ 1,001 | $ 938 | $ 812 | ||||||||
Effective income tax rate | 37.40% | 38.20% | 39.50% | ||||||||
PSE&G [Member] | |||||||||||
Income Taxes [Line Items] | |||||||||||
Net Income | 156 | 222 | 167 | 242 | 160 | 200 | 151 | 214 | |||
Net Income | $ 787 | $ 725 | $ 612 | ||||||||
Federal | 32 | 124 | 183 | ||||||||
State | 52 | 16 | 0 | ||||||||
Total Current | 84 | 140 | 183 | ||||||||
Federal | 325 | 214 | 101 | ||||||||
State | 52 | 84 | 92 | ||||||||
Total Deferred | 377 | 298 | 193 | ||||||||
Investment tax credit | 9 | 11 | 5 | ||||||||
Total Income Tax | 470 | 449 | 381 | ||||||||
Pre-Tax Income | 1,257 | 1,174 | 993 | ||||||||
Tax Computed at Statutory Rate @ 35% | 440 | 411 | 348 | ||||||||
State Income Taxes (net of federal income tax) | 67 | 65 | 59 | ||||||||
Uncertain Tax Positions | (14) | 0 | 0 | ||||||||
Plant-Related Items | (20) | (13) | (14) | ||||||||
Tax Credits | (6) | (7) | (6) | ||||||||
Audit Settlement | 0 | 1 | 0 | ||||||||
Other | 3 | (8) | (6) | ||||||||
Sub-Total | 30 | 38 | 33 | ||||||||
Total Income Tax Provision | $ 470 | $ 449 | $ 381 | ||||||||
Effective income tax rate | 37.40% | 38.20% | 38.40% | ||||||||
Power [Member] | |||||||||||
Income Taxes [Line Items] | |||||||||||
Net Income | $ 149 | $ 206 | $ 166 | $ 335 | $ 320 | $ 222 | $ 54 | $ 164 | |||
Net Income | $ 856 | $ 760 | $ 644 | ||||||||
Federal | 220 | 231 | 262 | ||||||||
State | 30 | 39 | 40 | ||||||||
Total Current | 250 | 270 | 302 | ||||||||
Federal | 189 | 163 | 69 | ||||||||
State | 52 | 48 | 35 | ||||||||
Total Deferred | 241 | 211 | 104 | ||||||||
Investment tax credit | 20 | 10 | 13 | ||||||||
Total Income Tax | 511 | 491 | 419 | ||||||||
Pre-Tax Income | 1,367 | 1,251 | 1,063 | ||||||||
Tax Computed at Statutory Rate @ 35% | 478 | 438 | 372 | ||||||||
State Income Taxes (net of federal income tax) | 59 | 58 | 51 | ||||||||
Uncertain Tax Positions | 22 | (8) | 3 | ||||||||
Manufacturing Deduction | (10) | (16) | (10) | ||||||||
Nuclear Decommissioning Trust | 7 | 15 | 12 | ||||||||
Tax Credits | (7) | (6) | (2) | ||||||||
Audit Settlement | 0 | (4) | 0 | ||||||||
Nuclear Decommissiong Tax Carryback | (33) | 0 | 0 | ||||||||
Other | (5) | 14 | (7) | ||||||||
Sub-Total | 33 | 53 | 47 | ||||||||
Total Income Tax Provision | $ 511 | $ 491 | $ 419 | ||||||||
Effective income tax rate | 37.40% | 39.20% | 39.40% |
Income Taxes (Deferred Income T
Income Taxes (Deferred Income Tax) (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Income Taxes [Line Items] | ||
Current (net) | $ 0 | $ 11 |
OPEB | 256 | 269 |
Related to Uncertain Tax Positions | 160 | 160 |
Deferred Tax Assets - Securitization Overcollection | 27 | 55 |
Total Noncurrent Assets | 443 | 484 |
Total Assets | 443 | 495 |
Current (net) | 0 | 173 |
Current Deferred Tax Liabilities Securitization | 0 | 163 |
Current Deferred Tax Liabilities Other | 0 | 10 |
Plant-Related Items | 6,174 | 5,422 |
New Jersey Corporate Business Tax | 615 | 535 |
Leasing Activities | 612 | 623 |
Pension Costs | 218 | 219 |
AROs and NDT Fund | 393 | 419 |
Taxes Recoverable Through Future Rate (net) | 191 | 196 |
Deferred Tax Liabilities, Other | 244 | 240 |
Total Non-Current Liabilities | 8,447 | 7,654 |
Total Liabilities | 8,447 | 7,827 |
Net Current Deferred Tax Assets | 0 | 11 |
Net Current Deferred Income Tax Liabilities | 0 | 173 |
Net Noncurrent Deferred Income Tax Liabilities | 8,004 | 7,170 |
Accumulated Deferred Investment Tax Credit | 162 | 133 |
Net Total Noncurrent Deferred Income Taxes and ITC | 8,166 | 7,303 |
PSE&G [Member] | ||
Income Taxes [Line Items] | ||
Current (net) | 0 | 24 |
OPEB | 164 | 173 |
Deferred Tax Assets - Securitization Overcollection | 27 | 55 |
Total Noncurrent Assets | 191 | 228 |
Total Assets | 191 | 252 |
Current (net) | 0 | 165 |
Current Deferred Tax Liabilities Securitization | 0 | 163 |
Current Deferred Tax Liabilities Other | 0 | 2 |
Plant-Related Items | 4,435 | 3,869 |
New Jersey Corporate Business Tax | 312 | 268 |
Conservation Costs | 40 | 48 |
Pension Costs | 262 | 269 |
Taxes Recoverable Through Future Rate (net) | 191 | 196 |
Deferred Tax Liabilities, Other | 54 | 84 |
Total Non-Current Liabilities | 5,294 | 4,734 |
Total Liabilities | 5,294 | 4,899 |
Net Current Deferred Tax Assets | 0 | 24 |
Net Current Deferred Income Tax Liabilities | 0 | 165 |
Net Noncurrent Deferred Income Tax Liabilities | 5,103 | 4,506 |
Accumulated Deferred Investment Tax Credit | 78 | 69 |
Net Total Noncurrent Deferred Income Taxes and ITC | 5,181 | 4,575 |
Power [Member] | ||
Income Taxes [Line Items] | ||
Current (net) | 0 | 0 |
Contractual Liabilities & Environmental Costs | 18 | 18 |
Related to Uncertain Tax Positions | 47 | 23 |
Other | 0 | 70 |
Total Noncurrent Assets | 121 | 163 |
Total Assets | 121 | 163 |
Current (net) | 0 | 43 |
Plant-Related Items | 1,736 | 1,552 |
New Jersey Corporate Business Tax | 243 | 192 |
AROs and NDT Fund | 395 | 420 |
Deferred Tax Liabilities, Other | 10 | 0 |
Total Non-Current Liabilities | 2,384 | 2,164 |
Total Liabilities | 2,384 | 2,207 |
Net Current Deferred Tax Assets | 0 | 0 |
Net Current Deferred Income Tax Liabilities | 0 | 43 |
Net Noncurrent Deferred Income Tax Liabilities | 2,263 | 2,001 |
Accumulated Deferred Investment Tax Credit | 84 | 64 |
Net Total Noncurrent Deferred Income Taxes and ITC | 2,347 | 2,065 |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Pensions | $ 56 | $ 52 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Sep. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Sep. 09, 2014 | |
Income Taxes [Line Items] | |||||
Bonus depreciation for tax purposes | 50.00% | ||||
Current ITC rate for qualified property | 30.00% | ||||
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority | $ 121 | ||||
Income Tax Examination, Tax Expense | $ (12) | ||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | $ 10 | $ 60 | $ 0 | ||
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions | $ 50 | 190 | 30 | ||
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% | ||||
PSE&G [Member] | |||||
Income Taxes [Line Items] | |||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | $ 0 | 32 | 0 | ||
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions | 43 | 92 | 9 | ||
Power [Member] | |||||
Income Taxes [Line Items] | |||||
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities | 4 | 24 | 0 | ||
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions | $ 6 | $ 80 | $ 19 |
Income Taxes (Unrecognized Tax
Income Taxes (Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | $ 332 | $ 478 | $ 402 |
Increases as a Result of Positions Taken in a Prior Period | 87 | 82 | 83 |
Decreases as a Result of Positions Taken in a Prior Period | (50) | (190) | (30) |
Increases as a Result of Positions Taken during the Current Period | 28 | 30 | 23 |
Decreases as a Result of Positions Taken during the Current Period | (1) | (8) | 0 |
Decreases as a Result of Settlements with Taxing Authorities | (10) | (60) | 0 |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 386 | 332 | 478 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (264) | (225) | (320) |
Regulatory Asset-Unrecognized Tax Benefits | (27) | (27) | (30) |
Amount of unrecognized tax benefits that would affect the effective tax rate | 95 | 80 | 128 |
Power [Member] | |||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Total Amount of Unrecognized Tax Benefits at January | 70 | 156 | 134 |
Increases as a Result of Positions Taken in a Prior Period | 28 | 17 | 33 |
Decreases as a Result of Positions Taken in a Prior Period | (6) | (80) | (19) |
Increases as a Result of Positions Taken during the Current Period | 23 | 9 | 8 |
Decreases as a Result of Positions Taken during the Current Period | 0 | (8) | 0 |
Decreases as a Result of Settlements with Taxing Authorities | (4) | (24) | 0 |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 111 | 70 | 156 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (68) | (52) | (105) |
Regulatory Asset-Unrecognized Tax Benefits | 0 | 0 | 0 |
Amount of unrecognized tax benefits that would affect the effective tax rate | 43 | 18 | 51 |
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 | 165 | 208 | 163 |
Increases as a Result of Positions Taken in a Prior Period | 55 | 65 | 39 |
Decreases as a Result of Positions Taken in a Prior Period | (43) | (92) | (9) |
Increases as a Result of Positions Taken during the Current Period | 5 | 16 | 15 |
Decreases as a Result of Positions Taken during the Current Period | (1) | 0 | 0 |
Decreases as a Result of Settlements with Taxing Authorities | 0 | (32) | 0 |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 181 | 165 | 208 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (162) | (138) | (177) |
Regulatory Asset-Unrecognized Tax Benefits | (27) | (27) | (30) |
Amount of unrecognized tax benefits that would affect the effective tax rate | (8) | 0 | 1 |
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 | 95 | 110 | 101 |
Increases as a Result of Positions Taken in a Prior Period | 4 | 0 | 11 |
Decreases as a Result of Positions Taken in a Prior Period | (1) | (18) | (2) |
Increases as a Result of Positions Taken during the Current Period | 0 | 5 | 0 |
Decreases as a Result of Positions Taken during the Current Period | 0 | 0 | 0 |
Decreases as a Result of Settlements with Taxing Authorities | (5) | (2) | 0 |
Decreases due to Lapses of Applicable Statute of Limitations | 0 | 0 | 0 |
Total Amount of Unrecognized Tax Benefits at December | 93 | 95 | 110 |
Accumulated Deferred Income Taxes Associated with Unrecognized Tax Benefits | (34) | (35) | (37) |
Regulatory Asset-Unrecognized Tax Benefits | 0 | 0 | 0 |
Amount of unrecognized tax benefits that would affect the effective tax rate | $ 59 | $ 60 | $ 73 |
Income Taxes (Interest And Pena
Income Taxes (Interest And Penalties Related To Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | $ 66 | $ 69 | $ 48 |
PSE&G [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | 20 | 15 | 6 |
Power [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | 6 | 9 | (2) |
Energy Holdings [Member] | |||
Income Taxes [Line Items] | |||
Accumulated Interest and Penalties on Uncertain Tax Positions | $ 40 | $ 45 | $ 44 |
Income Taxes (Possible Decrease
Income Taxes (Possible Decrease In Total Unrecognized Tax Benefits Including Interest) (Details) $ in Millions | Dec. 31, 2015USD ($) |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | $ 158 |
Power [Member] | |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | 102 |
PSE&G [Member] | |
Income Taxes [Line Items] | |
Possible Decrease in Total Unrecognized Tax Benefits including Interest in next twelve months | $ 42 |
Income Taxes (Description Of In
Income Taxes (Description Of Income Tax Years By Material Jurisdictions) (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Federal [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2011-2014 |
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 | 2006-2014 |
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 | 2006-2014 |
Pennsylvania [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2006-2014 |
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 | 2006-2014 |
Connecticut [Member] | PSEG [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2002-2014 |
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 | 2007-2014 |
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 | 2003-2014 |
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 | 2011-2014 |
New York [Member] | Power [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | 2011-2014 |
New York [Member] | PSE&G [Member] | |
Income Taxes [Line Items] | |
Income Tax Year Subject to Examination by Material Jurisdictions | N/A |
Accumulated Other Comprehens139
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | $ (283) | $ (95) | $ (388) |
Other Comprehensive Income before Reclassifications | (30) | (135) | 299 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 18 | (53) | (6) |
Net Current Period Other Comprehensive Income (Loss) | (12) | (188) | 293 |
Ending Balance | (295) | (283) | (95) |
Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (228) | (63) | (328) |
Other Comprehensive Income before Reclassifications | (27) | (110) | 276 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 15 | (55) | (11) |
Net Current Period Other Comprehensive Income (Loss) | (12) | (165) | 265 |
Ending Balance | (240) | (228) | (63) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 10 | (2) | 7 |
Other Comprehensive Income before Reclassifications | 2 | 7 | (2) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | (12) | 5 | (7) |
Net Current Period Other Comprehensive Income (Loss) | (10) | 12 | (9) |
Ending Balance | 0 | 10 | (2) |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 11 | (1) | 9 |
Other Comprehensive Income before Reclassifications | 1 | 7 | (2) |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | (12) | 5 | (8) |
Net Current Period Other Comprehensive Income (Loss) | (11) | 12 | (10) |
Ending Balance | 0 | 11 | (1) |
Accumulated Defined Benefit Plans Adjustment [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (411) | (238) | (485) |
Other Comprehensive Income before Reclassifications | (7) | (184) | 210 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 32 | 11 | 37 |
Net Current Period Other Comprehensive Income (Loss) | 25 | (173) | 247 |
Ending Balance | (386) | (411) | (238) |
Accumulated Defined Benefit Plans Adjustment [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | (351) | (204) | (422) |
Other Comprehensive Income before Reclassifications | (4) | (156) | 185 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | 28 | 9 | 33 |
Net Current Period Other Comprehensive Income (Loss) | 24 | (147) | 218 |
Ending Balance | (327) | (351) | (204) |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 118 | 145 | 90 |
Other Comprehensive Income before Reclassifications | (25) | 42 | 91 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | (2) | (69) | (36) |
Net Current Period Other Comprehensive Income (Loss) | (27) | (27) | 55 |
Ending Balance | 91 | 118 | 145 |
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning Balance | 112 | 142 | 85 |
Other Comprehensive Income before Reclassifications | (24) | 39 | 93 |
Amounts Reclassified from Accumulated Other Comprehensive Income (Loss) | (1) | (69) | (36) |
Net Current Period Other Comprehensive Income (Loss) | (25) | (30) | 57 |
Ending Balance | $ 87 | $ 112 | $ 142 |
Accumulated Other Comprehens140
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax | $ (28) | $ 108 | $ 23 |
Amount Reclassified from Accumulated Other Comprehensive Income, Tax | 10 | (55) | (17) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (18) | 53 | 6 |
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 | 8 | 135 | 75 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (6) | (66) | (39) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (2) | (69) | (36) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 2 | 69 | 36 |
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) | (18) | (64) |
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax | 24 | 7 | 27 |
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax | (32) | (11) | (37) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (32) | (11) | (37) |
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) | 12 |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | (5) |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | 7 |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 12 | (5) | 7 |
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) | 13 |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | (5) |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | 8 |
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 | 10 | 11 |
Amortization of Prior Service (Cost) Credit, Tax | (3) | (4) | (4) |
Amortization of Prior Service (Cost) Credit, After-Tax | 9 | 6 | 7 |
Amortization of Actuarial Loss, Pre-Tax | (68) | (28) | (75) |
Amortization of Actuarial Loss, Tax | (27) | (11) | (31) |
Amortization of Actuarial Loss, After-Tax | (41) | (17) | (44) |
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 | 100 | 181 | 116 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (52) | (89) | (59) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 48 | 92 | 57 |
Interest Expense [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 | (1) | ||
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | 0 | ||
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | (1) | ||
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 | (39) | (26) | (29) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 20 | 13 | 14 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (19) | (13) | (15) |
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 | (53) | (20) | (12) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 26 | 10 | 6 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 27 | 10 | 6 |
Power [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Amount Reclassified from Accumulated Other Comprehensive Income, Pre-Tax | (22) | 109 | 32 |
Amount Reclassified from Accumulated Other Comprehensive Income, Tax | 7 | (54) | (21) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (15) | 55 | 11 |
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 | 7 | 134 | 74 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (6) | (65) | (38) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (1) | (69) | (36) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 1 | 69 | 36 |
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 | (49) | (16) | (55) |
Amount Reclassified from AOCI for Pension and OPEB Plans, Tax | 21 | 7 | 22 |
Amount Reclassified from AOCI for Pension and OPEB Plans, After-Tax | (28) | (9) | (33) |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | (28) | (9) | (33) |
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) | 13 |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | (5) |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | 8 |
Amount Reclassified from Accumulated Other Comprehensive Income, After-Tax | 12 | (5) | 8 |
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) | 13 |
Amount Reclassified from AOCI for Cash Flow Hedges, Tax | (8) | 4 | (5) |
Amount Reclassified from AOCI for Cash Flow Hedges, After-Tax | 12 | (5) | 8 |
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 | 9 | 9 |
Amortization of Prior Service (Cost) Credit, Tax | (3) | (4) | (4) |
Amortization of Prior Service (Cost) Credit, After-Tax | 8 | 5 | 5 |
Amortization of Actuarial Loss, Pre-Tax | (60) | (25) | (64) |
Amortization of Actuarial Loss, Tax | (24) | (11) | (26) |
Amortization of Actuarial Loss, After-Tax | (36) | (14) | (38) |
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 | 98 | 178 | 112 |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | (51) | (87) | (57) |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | 47 | 91 | 55 |
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 | (38) | (24) | (26) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 19 | 12 | 13 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | (19) | (12) | (13) |
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 | (53) | (20) | (12) |
Amount Reclassified from AOCI for Available for Sale Securities, Tax | 26 | 10 | 6 |
Amount Reclassified from AOCI for Available for Sale Securities, After-Tax | $ 27 | $ 10 | $ 6 |
Earnings Per Share (EPS) And141
Earnings Per Share (EPS) And Dividends (Basic And Diluted Earnings Per Share Computation) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Earnings Per Share, Diluted [Line Items] | |||||||||||
Net Income | $ 1,679 | $ 1,518 | $ 1,243 | ||||||||
Effect of Stock Based Compensation Awards, Basic | 0 | 0 | 0 | ||||||||
Total Shares, Basic | 505 | 505 | 506 | 506 | 506 | 506 | 506 | 506 | 505 | 506 | 506 |
Effect of Stock Based Compensation Awards, Diluted | 3 | 2 | 2 | ||||||||
Total Shares, Diluted | 508 | 508 | 508 | 508 | 508 | 507 | 508 | 508 | 508 | 508 | 508 |
Weighted Average Common Shares Outstanding Before Various Effects Basic | 505 | 506 | 506 | ||||||||
Weighted Average Common Shares Outstanding Before Various Effects Diluted | 505 | 506 | 506 | ||||||||
Earnings Per Share, Basic | $ 0.61 | $ 0.87 | $ 0.68 | $ 1.16 | $ 0.94 | $ 0.88 | $ 0.42 | $ 0.76 | $ 3.32 | $ 3 | $ 2.46 |
Earnings Per Share, Diluted | $ 0.60 | $ 0.87 | $ 0.68 | $ 1.15 | $ 0.94 | $ 0.87 | $ 0.42 | $ 0.76 | $ 3.30 | $ 2.99 | $ 2.45 |
Stock Options Excluded from Weighted Average Common Shares used for diluted EPS | 0.5 | 0.4 | 1.6 |
Earnings Per Share (EPS) And142
Earnings Per Share (EPS) And Dividends (Dividend Payments On Common Stock) (Detail) - USD ($) $ / shares in Units, $ in Millions | Feb. 16, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Earnings Per Share, Diluted [Line Items] | ||||
Dividend Payments on Common Stock, Per Share | $ 1.56 | $ 1.48 | $ 1.44 | |
Dividend Payments on Common Stock | $ 789 | $ 748 | $ 728 | |
Subsequent Event [Member] | ||||
Earnings Per Share, Diluted [Line Items] | ||||
Common stock dividends per share | $ 0.41 |
Financial Information By Bus143
Financial Information By Business Segments (Financial Information By Business Segments) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Operating Revenues | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 2,773 | $ 2,641 | $ 2,249 | $ 3,223 | $ 10,415 | $ 10,886 | $ 9,968 | |||||
Depreciation and Amortization | 1,214 | 1,227 | 1,178 | |||||||||||||
Operating Income (Loss) | 532 | $ 814 | $ 568 | $ 1,048 | 807 | $ 746 | $ 365 | $ 705 | 2,962 | 2,623 | 2,299 | |||||
Income from Equity Method Investments | 12 | 13 | 11 | |||||||||||||
Interest Income | 31 | 30 | 29 | |||||||||||||
Interest Expense | (393) | (389) | (402) | |||||||||||||
Income (Loss) before Income Taxes | 2,680 | 2,456 | 2,055 | |||||||||||||
Income Tax Expense (Benefit) | 1,001 | 938 | 812 | |||||||||||||
Net Income (Loss) | 1,679 | 1,518 | 1,243 | |||||||||||||
Gross Additions to Long-Lived Assets | 3,863 | 2,820 | 2,811 | |||||||||||||
Total Assets | 37,535 | 35,287 | 37,535 | 35,287 | 32,480 | |||||||||||
Investments in Equity Method Subsidiaries | 119 | 123 | 119 | 123 | 126 | |||||||||||
Retained Earnings [Member] | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Net Income (Loss) | 1,679 | 1,518 | 1,243 | |||||||||||||
Operating Segments [Member] | Power [Member] | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Operating Revenues | 4,928 | 5,434 | 5,063 | |||||||||||||
Depreciation and Amortization | 291 | 292 | 273 | |||||||||||||
Operating Income (Loss) | 1,430 | 1,209 | 1,070 | |||||||||||||
Income from Equity Method Investments | 14 | 14 | 16 | |||||||||||||
Interest Income | 2 | 1 | 1 | |||||||||||||
Interest Expense | (121) | (122) | (116) | |||||||||||||
Income (Loss) before Income Taxes | 1,367 | 1,251 | 1,063 | |||||||||||||
Income Tax Expense (Benefit) | 511 | 491 | 419 | |||||||||||||
Net Income (Loss) | 856 | 760 | 644 | |||||||||||||
Gross Additions to Long-Lived Assets | 1,117 | 626 | 609 | |||||||||||||
Total Assets | 12,250 | 12,037 | 12,250 | 12,037 | 11,991 | |||||||||||
Investments in Equity Method Subsidiaries | 119 | 121 | 119 | 121 | 123 | |||||||||||
Operating Segments [Member] | PSE&G [Member] | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Operating Revenues | 6,636 | 6,766 | 6,655 | |||||||||||||
Depreciation and Amortization | 892 | 906 | 872 | |||||||||||||
Operating Income (Loss) | 1,462 | 1,393 | 1,235 | |||||||||||||
Income from Equity Method Investments | 0 | 0 | 0 | |||||||||||||
Interest Income | 25 | 26 | 25 | |||||||||||||
Interest Expense | (280) | (277) | (293) | |||||||||||||
Income (Loss) before Income Taxes | 1,257 | 1,174 | 993 | |||||||||||||
Income Tax Expense (Benefit) | 470 | 449 | 381 | |||||||||||||
Net Income (Loss) | 787 | 725 | 612 | |||||||||||||
Gross Additions to Long-Lived Assets | 2,692 | 2,164 | 2,175 | |||||||||||||
Total Assets | 23,677 | 22,186 | 23,677 | 22,186 | 19,689 | |||||||||||
Investments in Equity Method Subsidiaries | 0 | 0 | 0 | 0 | 0 | |||||||||||
Operating Segments [Member] | Other [Member] | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Operating Revenues | 462 | 455 | 52 | |||||||||||||
Depreciation and Amortization | 31 | 29 | 33 | |||||||||||||
Operating Income (Loss) | 70 | 21 | (6) | |||||||||||||
Income from Equity Method Investments | (2) | (1) | (5) | |||||||||||||
Interest Income | 33 | 25 | 25 | |||||||||||||
Interest Expense | (21) | (12) | (15) | |||||||||||||
Income (Loss) before Income Taxes | 56 | 31 | (1) | |||||||||||||
Income Tax Expense (Benefit) | 20 | (2) | 12 | |||||||||||||
Net Income (Loss) | 36 | 33 | (13) | |||||||||||||
Gross Additions to Long-Lived Assets | 54 | 30 | 27 | |||||||||||||
Total Assets | 2,810 | 2,799 | 2,810 | 2,799 | 4,025 | |||||||||||
Investments in Equity Method Subsidiaries | 0 | 2 | 0 | 2 | 3 | |||||||||||
Eliminations [Member] | ||||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||||
Operating Revenues | [1] | (1,611) | (1,769) | (1,802) | ||||||||||||
Depreciation and Amortization | [1] | 0 | 0 | 0 | ||||||||||||
Operating Income (Loss) | [1] | 0 | 0 | 0 | ||||||||||||
Income from Equity Method Investments | [1] | 0 | 0 | 0 | ||||||||||||
Interest Income | [1] | (29) | (22) | (22) | ||||||||||||
Interest Expense | [1] | 29 | 22 | 22 | ||||||||||||
Income (Loss) before Income Taxes | [1] | 0 | 0 | 0 | ||||||||||||
Income Tax Expense (Benefit) | [1] | 0 | 0 | 0 | ||||||||||||
Net Income (Loss) | [1] | 0 | 0 | 0 | ||||||||||||
Gross Additions to Long-Lived Assets | [1] | 0 | 0 | |||||||||||||
Total Assets | [1] | (1,202) | (1,735) | (1,202) | (1,735) | (3,225) | ||||||||||
Investments in Equity Method Subsidiaries | $ 0 | [1] | $ 0 | [1] | $ 0 | [1] | $ 0 | [1] | $ 0 | |||||||
[1] | 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 23. 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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
PSE&G [Member] | ||||
Related Party Transaction [Line Items] | ||||
Billings from Power through BGSS and BGS | [1] | $ 1,630 | $ 1,771 | $ 1,797 |
Administrative Billings from Services | [2] | 274 | 248 | 255 |
Total Expense Billings from Affiliates | 1,904 | 2,019 | 2,052 | |
Power [Member] | ||||
Related Party Transaction [Line Items] | ||||
Administrative Billings from Services | [2] | $ 187 | $ 165 | $ 178 |
[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. | |||
[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 (145
Related-Party Transactions (Schedule Of Related Party Transactions, Receivables) (Detail) - Power [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Receivable from PSE&G through BGS and BGSS Contracts | [1] | $ 212 | $ 313 |
Receivable from (Payable to) Services | [2] | (33) | (23) |
Payable to Parent | [3] | 0 | 95 |
Accounts Payable-Affiliated Companies | (33) | (118) | |
Receivable from (Payable to) PSEG | [1] | 64 | 0 |
Accounts Receivable-Affilated Companies, net | 276 | 313 | |
Short-Term Loan to Affiliate (Demand Note to PSEG) | 363 | 584 | |
Working Capital Advances to Services | [4] | 17 | 17 |
Accounts Payable, Related Parties, Noncurrent | $ 35 | $ 41 | |
[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. | ||
[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. |
Related-Party Transactions Rela
Related-Party Transactions Related-Party Revenues and Expenses (Details) - Power [Member] - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Related Party Transaction [Line Items] | ||||||
Billings To PSE&G through BGSS and BGS | $ 1,630 | [1] | $ 1,771 | $ 1,797 | [1] | |
Administrative Billings from Services | [2] | $ 187 | $ 165 | $ 178 | ||
[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. | |||||
[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, Payables) (Detail) - PSE&G [Member] - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | |
Related Party Transaction [Line Items] | |||
Payable to Power through BGS and BGSS Contracts | [1] | $ (212) | $ (313) |
Receivable from (Payable to) Services | [2] | (80) | (66) |
Receivable from (Payable to) PSEG | [3] | 222 | 274 |
Accounts Payable-Affiliated Companies | 292 | 379 | |
Working Capital Advances to Services | [4] | 33 | 33 |
Long-Term Accrued Taxes Receivable (Payable) | $ (109) | $ (116) | |
[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. | ||
[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, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Quarterly Data [Line Items] | |||||||||||
Operating Revenues | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 2,773 | $ 2,641 | $ 2,249 | $ 3,223 | $ 10,415 | $ 10,886 | $ 9,968 |
Operating Income (Loss) | 532 | 814 | 568 | 1,048 | 807 | 746 | 365 | 705 | 2,962 | 2,623 | 2,299 |
Net Income (Loss) | $ 309 | $ 439 | $ 345 | $ 586 | $ 476 | $ 444 | $ 212 | $ 386 | |||
Net Income (Loss) | $ 1,679 | $ 1,518 | $ 1,243 | ||||||||
Basic | 505 | 505 | 506 | 506 | 506 | 506 | 506 | 506 | 505 | 506 | 506 |
Diluted | 508 | 508 | 508 | 508 | 508 | 507 | 508 | 508 | 508 | 508 | 508 |
Earnings Per Share, Basic | $ 0.61 | $ 0.87 | $ 0.68 | $ 1.16 | $ 0.94 | $ 0.88 | $ 0.42 | $ 0.76 | $ 3.32 | $ 3 | $ 2.46 |
Earnings Per Share, Diluted | $ 0.60 | $ 0.87 | $ 0.68 | $ 1.15 | $ 0.94 | $ 0.87 | $ 0.42 | $ 0.76 | $ 3.30 | $ 2.99 | $ 2.45 |
PSE&G [Member] | |||||||||||
Schedule of Quarterly Data [Line Items] | |||||||||||
Operating Revenues | $ 1,402 | $ 1,766 | $ 1,466 | $ 2,002 | $ 1,531 | $ 1,655 | $ 1,435 | $ 2,145 | $ 6,636 | $ 6,766 | $ 6,655 |
Operating Income (Loss) | 287 | 404 | 320 | 451 | 308 | 383 | 291 | 411 | 1,462 | 1,393 | 1,235 |
Net Income (Loss) | 156 | 222 | 167 | 242 | 160 | 200 | 151 | 214 | |||
Net Income (Loss) | 787 | 725 | 612 | ||||||||
Power [Member] | |||||||||||
Schedule of Quarterly Data [Line Items] | |||||||||||
Operating Revenues | 1,082 | 1,096 | 1,025 | 1,725 | 1,610 | 1,138 | 986 | 1,700 | 4,928 | 5,434 | 5,063 |
Operating Income (Loss) | 227 | 391 | 228 | 584 | 507 | 353 | 67 | 282 | 1,430 | 1,209 | 1,070 |
Net Income (Loss) | $ 149 | $ 206 | $ 166 | $ 335 | $ 320 | $ 222 | $ 54 | $ 164 | |||
Net Income (Loss) | $ 856 | $ 760 | $ 644 |
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, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | $ 2,278 | $ 2,688 | $ 2,314 | $ 3,135 | $ 2,773 | $ 2,641 | $ 2,249 | $ 3,223 | $ 10,415 | $ 10,886 | $ 9,968 | |
Operating Expenses | 7,453 | 8,263 | 7,669 | |||||||||
Operating Income (Loss) | 532 | 814 | 568 | 1,048 | 807 | 746 | 365 | 705 | 2,962 | 2,623 | 2,299 | |
Equity Earnings (Losses) of Subsidiaries | 12 | 13 | 11 | |||||||||
Other Income | 254 | 290 | 213 | |||||||||
Other Deductions | (102) | (61) | (54) | |||||||||
Other-than-Temporary-Impairments | (53) | (20) | (12) | |||||||||
Interest Expense | (393) | (389) | (402) | |||||||||
Income Tax Benefit (Expense) | (1,001) | (938) | (812) | |||||||||
Net Income | 1,679 | 1,518 | 1,243 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 3,919 | 3,160 | 3,158 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (3,942) | (2,892) | (2,801) | |||||||||
Net Cash Provided By (Used In) Financing Activities | 15 | (359) | (243) | |||||||||
Current Assets | 3,494 | 4,119 | 3,494 | 4,119 | ||||||||
Property, Plant and Equipment, net | 26,539 | 23,589 | 26,539 | 23,589 | ||||||||
Noncurrent Assets | 7,502 | 7,579 | 7,502 | 7,579 | ||||||||
Total Assets | 37,535 | 35,287 | 37,535 | 35,287 | 32,480 | |||||||
Current Liabilities | 3,575 | 3,478 | 3,575 | 3,478 | ||||||||
Noncurrent Liabilities | 12,059 | 11,408 | 12,059 | 11,408 | ||||||||
Member's Equity | 13,067 | 12,186 | 13,067 | 12,186 | 11,609 | $ 10,781 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | 37,535 | 35,287 | 37,535 | 35,287 | ||||||||
Power [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | 1,082 | 1,096 | 1,025 | 1,725 | 1,610 | 1,138 | 986 | 1,700 | 4,928 | 5,434 | 5,063 | |
Operating Expenses | 3,498 | 4,225 | 3,993 | |||||||||
Operating Income (Loss) | 227 | $ 391 | $ 228 | $ 584 | 507 | $ 353 | $ 67 | $ 282 | 1,430 | 1,209 | 1,070 | |
Equity Earnings (Losses) of Subsidiaries | 14 | 14 | 16 | |||||||||
Other Income | 169 | 222 | 154 | |||||||||
Other Deductions | (72) | (52) | (49) | |||||||||
Other-than-Temporary-Impairments | (53) | (20) | (12) | |||||||||
Interest Expense | (121) | (122) | (116) | |||||||||
Income Tax Benefit (Expense) | (511) | (491) | (419) | |||||||||
Net Income | 856 | 760 | 644 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 1,706 | 1,425 | 1,347 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (1,001) | (524) | (861) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (702) | (898) | (487) | |||||||||
Current Assets | 1,949 | 2,359 | 1,949 | 2,359 | ||||||||
Property, Plant and Equipment, net | 8,127 | 7,515 | 8,127 | 7,515 | ||||||||
Noncurrent Assets | 2,174 | 2,163 | 2,174 | 2,163 | ||||||||
Total Assets | 12,250 | 12,037 | 12,250 | 12,037 | ||||||||
Current Liabilities | 1,226 | 1,184 | 1,226 | 1,184 | ||||||||
Noncurrent Liabilities | 3,338 | 3,061 | 3,338 | 3,061 | ||||||||
Total Long-Term Debt | 1,684 | 2,234 | 1,684 | 2,234 | ||||||||
Member's Equity | 6,002 | 5,558 | 6,002 | 5,558 | 5,858 | $ 5,630 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION | 12,250 | 12,037 | 12,250 | 12,037 | ||||||||
Power Senior Notes [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | 4,928 | 5,434 | 5,063 | |||||||||
Operating Expenses | 3,498 | 4,225 | 3,993 | |||||||||
Operating Income (Loss) | 1,430 | 1,209 | 1,070 | |||||||||
Equity Earnings (Losses) of Subsidiaries | 14 | 14 | 16 | |||||||||
Other Income | 169 | 222 | 154 | |||||||||
Other Deductions | (72) | (52) | (49) | |||||||||
Other-than-Temporary-Impairments | (53) | (20) | (12) | |||||||||
Interest Expense | (121) | (122) | (116) | |||||||||
Income Tax Benefit (Expense) | (511) | (491) | (419) | |||||||||
Net Income | 856 | 760 | 644 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 844 | 595 | 909 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 1,706 | 1,425 | 1,347 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (1,001) | (524) | (861) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (702) | (898) | (487) | |||||||||
Current Assets | 1,949 | 2,359 | 1,949 | 2,359 | ||||||||
Property, Plant and Equipment, net | 8,127 | 7,515 | 8,127 | 7,515 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | 0 | 0 | ||||||||
Noncurrent Assets | 2,174 | 2,163 | 2,174 | 2,163 | ||||||||
Total Assets | 12,250 | 12,037 | 12,250 | 12,037 | ||||||||
Current Liabilities | 1,226 | 1,184 | 1,226 | 1,184 | ||||||||
Noncurrent Liabilities | 3,338 | 3,061 | 3,338 | 3,061 | ||||||||
Total Long-Term Debt | 1,684 | 2,234 | 1,684 | 2,234 | ||||||||
Member's Equity | 6,002 | 5,558 | 6,002 | 5,558 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 12,250 | 12,037 | 12,250 | 12,037 | ||||||||
Power Senior Notes [Member] | Guarantor Subsidiaries [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | 4,883 | 5,390 | 5,022 | |||||||||
Operating Expenses | 3,451 | 4,175 | 3,945 | |||||||||
Operating Income (Loss) | 1,432 | 1,215 | 1,077 | |||||||||
Equity Earnings (Losses) of Subsidiaries | (4) | (5) | (5) | |||||||||
Other Income | 174 | 222 | 157 | |||||||||
Other Deductions | (45) | (32) | (35) | |||||||||
Other-than-Temporary-Impairments | (53) | (20) | (12) | |||||||||
Interest Expense | (39) | (35) | (42) | |||||||||
Income Tax Benefit (Expense) | (574) | (558) | (474) | |||||||||
Net Income | 891 | 787 | 666 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 855 | 768 | 713 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 2,089 | 1,674 | 1,503 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (1,519) | (856) | (1,092) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (571) | (818) | (412) | |||||||||
Current Assets | 1,912 | 2,037 | 1,912 | 2,037 | ||||||||
Property, Plant and Equipment, net | 6,502 | 6,265 | 6,502 | 6,265 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 346 | 120 | 346 | 120 | ||||||||
Noncurrent Assets | 1,959 | 1,952 | 1,959 | 1,952 | ||||||||
Total Assets | 10,719 | 10,374 | 10,719 | 10,374 | ||||||||
Current Liabilities | 3,866 | 3,606 | 3,866 | 3,606 | ||||||||
Noncurrent Liabilities | 2,597 | 2,442 | 2,597 | 2,442 | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | 4,256 | 4,326 | 4,256 | 4,326 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 10,719 | 10,374 | 10,719 | 10,374 | ||||||||
Power Senior Notes [Member] | Non-Guarantor Subsidiaries [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | 179 | 153 | 190 | |||||||||
Operating Expenses | 169 | 143 | 174 | |||||||||
Operating Income (Loss) | 10 | 10 | 16 | |||||||||
Equity Earnings (Losses) of Subsidiaries | 14 | 14 | 16 | |||||||||
Other Income | 0 | 0 | 0 | |||||||||
Other Deductions | 0 | 0 | 0 | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | (19) | (19) | (19) | |||||||||
Income Tax Benefit (Expense) | 6 | 2 | 0 | |||||||||
Net Income | 11 | 7 | 13 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 11 | 7 | 11 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 80 | 76 | 82 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (430) | (42) | (71) | |||||||||
Net Cash Provided By (Used In) Financing Activities | 354 | (32) | (11) | |||||||||
Current Assets | 364 | 150 | 364 | 150 | ||||||||
Property, Plant and Equipment, net | 1,542 | 1,169 | 1,542 | 1,169 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | 0 | 0 | ||||||||
Noncurrent Assets | 136 | 137 | 136 | 137 | ||||||||
Total Assets | 2,042 | 1,456 | 2,042 | 1,456 | ||||||||
Current Liabilities | 1,076 | 786 | 1,076 | 786 | ||||||||
Noncurrent Liabilities | 375 | 360 | 375 | 360 | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | 591 | 310 | 591 | 310 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | 2,042 | 1,456 | 2,042 | 1,456 | ||||||||
Power Senior Notes [Member] | Consolidation, Eliminations [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | (134) | (109) | (149) | |||||||||
Operating Expenses | (134) | (109) | (149) | |||||||||
Operating Income (Loss) | 0 | 0 | 0 | |||||||||
Equity Earnings (Losses) of Subsidiaries | (902) | (794) | (679) | |||||||||
Other Income | (53) | (34) | (38) | |||||||||
Other Deductions | 0 | 0 | 0 | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | 53 | 34 | 38 | |||||||||
Income Tax Benefit (Expense) | 0 | 0 | 0 | |||||||||
Net Income | (902) | (794) | (679) | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | (866) | (775) | (724) | |||||||||
Net Cash Provided By (Used In) Operating Activities | (1,034) | (902) | (526) | |||||||||
Net Cash Provided By (Used In) Investing Activities | 1,314 | 226 | 697 | |||||||||
Net Cash Provided By (Used In) Financing Activities | (280) | 676 | (171) | |||||||||
Current Assets | (4,828) | (4,091) | (4,828) | (4,091) | ||||||||
Property, Plant and Equipment, net | 0 | 0 | 0 | 0 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | (4,847) | (4,636) | (4,847) | (4,636) | ||||||||
Noncurrent Assets | (76) | (195) | (76) | (195) | ||||||||
Total Assets | (9,751) | (8,922) | (9,751) | (8,922) | ||||||||
Current Liabilities | (4,828) | (4,091) | (4,828) | (4,091) | ||||||||
Noncurrent Liabilities | (76) | (195) | (76) | (195) | ||||||||
Total Long-Term Debt | 0 | 0 | 0 | 0 | ||||||||
Member's Equity | (4,847) | (4,636) | (4,847) | (4,636) | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | (9,751) | (8,922) | (9,751) | (8,922) | ||||||||
Power Senior Notes [Member] | Power Parent [Member] | ||||||||||||
Subsidiary or Equity Method Investee [Line Items] | ||||||||||||
Operating Revenues | 0 | 0 | 0 | |||||||||
Operating Expenses | 12 | 16 | 23 | |||||||||
Operating Income (Loss) | (12) | (16) | (23) | |||||||||
Equity Earnings (Losses) of Subsidiaries | 906 | 799 | 684 | |||||||||
Other Income | 48 | 34 | 35 | |||||||||
Other Deductions | (27) | (20) | (14) | |||||||||
Other-than-Temporary-Impairments | 0 | 0 | 0 | |||||||||
Interest Expense | (116) | (102) | (93) | |||||||||
Income Tax Benefit (Expense) | 57 | 65 | 55 | |||||||||
Net Income | 856 | 760 | 644 | |||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 844 | 595 | 909 | |||||||||
Net Cash Provided By (Used In) Operating Activities | 571 | 577 | 288 | |||||||||
Net Cash Provided By (Used In) Investing Activities | (366) | 148 | (395) | |||||||||
Net Cash Provided By (Used In) Financing Activities | (205) | (724) | $ 107 | |||||||||
Current Assets | 4,501 | 4,263 | 4,501 | 4,263 | ||||||||
Property, Plant and Equipment, net | 83 | 81 | 83 | 81 | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 4,501 | 4,516 | 4,501 | 4,516 | ||||||||
Noncurrent Assets | 155 | 269 | 155 | 269 | ||||||||
Total Assets | 9,240 | 9,129 | 9,240 | 9,129 | ||||||||
Current Liabilities | 1,112 | 883 | 1,112 | 883 | ||||||||
Noncurrent Liabilities | 442 | 454 | 442 | 454 | ||||||||
Total Long-Term Debt | 1,684 | 2,234 | 1,684 | 2,234 | ||||||||
Member's Equity | 6,002 | 5,558 | 6,002 | 5,558 | ||||||||
TOTAL LIABILITIES AND CAPITALIZATION | $ 9,240 | $ 9,129 | $ 9,240 | $ 9,129 |
Valuation And Qualifying Acc150
Valuation And Qualifying Accounts (Schedule Of Valuation And Qualifying Accounts) (Details) - USD ($) $ in Millions | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
Allowance For Doubtful Accounts [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | $ 52 | $ 56 | $ 56 | |||
Additions, Charged to cost and expenses | 101 | 86 | 90 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [1] | 86 | 90 | 90 | ||
Balance at End of Period | 67 | 52 | 56 | |||
Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 15 | 8 | 22 | |||
Additions, Charged to cost and expenses | 2 | 9 | 2 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | 6 | 2 | [2] | 16 | [2] | |
Balance at End of Period | 11 | 15 | 8 | |||
PSE&G [Member] | Allowance For Doubtful Accounts [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 52 | 56 | 56 | |||
Additions, Charged to cost and expenses | 101 | 86 | 90 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | [3] | 86 | 90 | 90 | ||
Balance at End of Period | 67 | 52 | 56 | |||
PSE&G [Member] | Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 2 | 0 | ||||
Additions, Charged to cost and expenses | 0 | 2 | ||||
Additions, Charged to other accounts-describe | 0 | 0 | ||||
Deductions-describe | 1 | 0 | ||||
Balance at End of Period | 1 | 2 | 0 | |||
Power [Member] | Materials And Supplies Valuation Reserve [Member] | ||||||
Valuation and Qualifying Accounts Disclosure [Line Items] | ||||||
Balance at Beginning of Period | 13 | 8 | 22 | |||
Additions, Charged to cost and expenses | 2 | 7 | 2 | |||
Additions, Charged to other accounts-describe | 0 | 0 | 0 | |||
Deductions-describe | 5 | 2 | [4] | 16 | [4] | |
Balance at End of Period | $ 10 | $ 13 | $ 8 | |||
[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. |