Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Entity Information [Line Items] | |||
Entity Registrant Name | FIRSTENERGY CORP | ||
Entity Central Index Key | 1,031,296 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock Shares Outstanding | 475,589,829 | ||
Entity Public Float | $ 12,919,874,051 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
FES | |||
Entity Information [Line Items] | |||
Entity Registrant Name | FirstEnergy Solutions Corp. | ||
Entity Central Index Key | 1,407,703 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock Shares Outstanding | 7 | ||
Entity Public Float | $ 0 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
Consolidated Statements of Inco
Consolidated Statements of Income (Loss) (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
REVENUES: | ||||
Regulated Distribution | $ 9,734 | $ 9,629 | $ 9,625 | |
Regulated Transmission | 1,325 | 1,144 | 1,003 | |
Unregulated businesses | 2,958 | 3,789 | 4,398 | |
Total revenues | [1] | 14,017 | 14,562 | 15,026 |
OPERATING EXPENSES: | ||||
Fuel | 1,383 | 1,666 | 1,855 | |
Purchased power | 3,194 | 3,843 | 4,423 | |
Other operating expenses | 4,232 | 3,851 | 3,740 | |
Pension and OPEB mark-to-market adjustment | 141 | 147 | 242 | |
Provision for depreciation | 1,138 | 1,313 | 1,282 | |
Amortization of regulatory assets, net | 308 | 297 | 172 | |
General taxes | 1,043 | 1,042 | 978 | |
Impairment of assets and related charges (Note 2) | 2,406 | 10,665 | 42 | |
Total operating expenses | 13,845 | 22,824 | 12,734 | |
OPERATING INCOME (LOSS) | 172 | (8,262) | 2,292 | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss) | 98 | 84 | (22) | |
Impairment of equity method investment (Note 1) | 0 | 0 | (362) | |
Interest expense | (1,178) | (1,157) | (1,132) | |
Capitalized financing costs | 79 | 103 | 117 | |
Total other expense | (1,001) | (970) | (1,399) | |
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (829) | (9,232) | 893 | |
INCOME TAXES (BENEFITS) | 895 | (3,055) | 315 | |
NET INCOME (LOSS) | $ (1,724) | $ (6,177) | $ 578 | |
EARNINGS (LOSS) PER SHARE OF COMMON STOCK: | ||||
Basic, in dollars per share | $ (3.88) | $ (14.49) | $ 1.37 | |
Diluted, in dollars per share | $ (3.88) | $ (14.49) | $ 1.37 | |
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: | ||||
Basic, in shares | 444 | 426 | 422 | |
Diluted, in shares | 444 | 426 | 424 | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share | $ 1.44 | $ 1.44 | $ 1.44 | |
[1] | Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. |
Consolidated Statements of Inc3
Consolidated Statements of Income (Loss) (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Excise tax collections included in Revenue | $ 390 | $ 406 | $ 416 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) (FirstEnergy Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | |||
NET INCOME (LOSS) | $ (1,724) | $ (6,177) | $ 578 |
OTHER COMPREHENSIVE INCOME (LOSS): | |||
Pension and OPEB prior service costs | (85) | (59) | (116) |
Amortized losses on derivative hedges | 10 | 8 | 5 |
Change in unrealized gain on available-for-sale securities | 22 | 55 | (11) |
Other comprehensive income (loss) | (53) | 4 | (122) |
Income taxes (benefits) on other comprehensive income (loss) | (21) | 1 | (47) |
Other comprehensive income (loss), net of tax | (32) | 3 | (75) |
COMPREHENSIVE INCOME (LOSS) | $ (1,756) | $ (6,174) | $ 503 |
Consolidated Balance Sheets (Fi
Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 589 | $ 199 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $51 in 2017 and $53 in 2016 | 1,463 | 1,440 |
Other, net of allowance for uncollectible accounts of $1 in 2017 and 2016 | 191 | 175 |
Materials and supplies, at average cost | 463 | 564 |
Derivatives | 37 | 140 |
Collateral | 146 | 176 |
Prepaid taxes and other | 219 | 256 |
Total current assets | 3,108 | 2,950 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 39,778 | 43,767 |
Less — Accumulated provision for depreciation | 11,925 | 15,731 |
Property, plant and equipment in service net of accumulated provision for depreciation | 27,853 | 28,036 |
Construction work in progress | 1,026 | 1,351 |
Total net property, plant and equipment | 28,879 | 29,387 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 2,678 | 2,514 |
Other | 506 | 512 |
Total other property and investments | 3,184 | 3,026 |
ASSETS HELD FOR SALE (Note 2) | 375 | 0 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Goodwill | 5,618 | 5,618 |
Regulatory assets | 40 | 1,014 |
Other | 1,053 | 1,153 |
Total deferred charges and other assets | 6,711 | 7,785 |
Total assets | 42,257 | 43,148 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,082 | 1,685 |
Short-term borrowings | 300 | 2,675 |
Accounts payable | 1,027 | 1,043 |
Accrued taxes | 571 | 580 |
Accrued compensation and benefits | 336 | 363 |
Collateral | 39 | 42 |
Other | 722 | 738 |
Total current liabilities | 4,077 | 7,126 |
Common stockholders’ equity- | ||
Common stock, $0.10 par value, authorized 700,000,000 and 490,000,000 shares - 445,334,111 and 442,344,218 shares outstanding as of December 31, 2017 and December 31, 2016, respectively | 44 | 44 |
Other paid-in capital | 10,001 | 10,555 |
Accumulated other comprehensive income | 142 | 174 |
Accumulated deficit | (6,262) | (4,532) |
Total common stockholders' equity | 3,925 | 6,241 |
Long-term debt and other long-term obligations | 21,115 | 18,192 |
Total capitalization | 25,040 | 24,433 |
NONCURRENT LIABILITIES: | ||
Accumulated deferred income taxes | 1,359 | 3,765 |
Retirement benefits | 3,975 | 3,719 |
Regulatory liabilities | 2,720 | 157 |
Asset retirement obligations | 2,515 | 1,482 |
Deferred gain on sale and leaseback transaction | 723 | 757 |
Adverse power contract liability | 130 | 162 |
Other | 1,718 | 1,547 |
Total noncurrent liabilities | 13,140 | 11,589 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | $ 42,257 | $ 43,148 |
Consolidated Balance Sheets (F6
Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Common stockholders’ equity- | ||
Common stock, par value (in dollars per share) | $ 0.1 | $ 0.1 |
Common stock, shares authorized | 700,000,000 | 490,000,000 |
Common stock, shares outstanding | 445,334,111 | 442,344,218 |
Customer [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 51 | $ 53 |
Other [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 1 | $ 1 |
Consolidated Statements of Comm
Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) - USD ($) $ in Millions | Total | Common Stock | Other Paid-In Capital | Accumulated Other Comprehensive Income | Retained Earnings (Accumulated Deficit) |
Beginning Balance, Shares at Dec. 31, 2014 | 421,102,570 | ||||
Beginning Balance at Dec. 31, 2014 | $ 42 | $ 9,847 | $ 246 | $ 2,285 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | $ 578 | 578 | |||
Amortized gain (loss) on derivative hedges, net of income taxes | 4 | ||||
Change in unrealized gain on investments, net of income taxes | (7) | ||||
Pensions and OPEB, net of income taxes | (72) | ||||
Stock-based compensation | 45 | ||||
Cash dividends declared on common stock | (607) | ||||
Stock Investment Plan and certain share-based benefit plans, shares | 2,457,827 | ||||
Stock Investment Plan and certain share-based benefit plans | 60 | ||||
Ending Balance, Shares at Dec. 31, 2015 | 423,560,397 | ||||
Ending Balance at Dec. 31, 2015 | $ 42 | 9,952 | 171 | 2,256 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | $ (6,177) | (6,177) | |||
Amortized gain (loss) on derivative hedges, net of income taxes | 5 | ||||
Change in unrealized gain on investments, net of income taxes | 34 | ||||
Pensions and OPEB, net of income taxes | (36) | ||||
Stock-based compensation | 49 | ||||
Cash dividends declared on common stock | (611) | ||||
Stock Investment Plan and certain share-based benefit plans, shares | 2,685,946 | ||||
Stock Investment Plan and certain share-based benefit plans | 56 | ||||
Stock issuance (Note 12), Shares | 16,097,875 | ||||
Stock issuance (Note 12) | $ 2 | 498 | |||
Ending Balance, Shares at Dec. 31, 2016 | 442,344,218 | 442,344,218 | |||
Ending Balance at Dec. 31, 2016 | $ 44 | 10,555 | 174 | (4,532) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | $ (1,724) | (1,724) | |||
Amortized gain (loss) on derivative hedges, net of income taxes | 6 | ||||
Change in unrealized gain on investments, net of income taxes | 15 | ||||
Pensions and OPEB, net of income taxes | (53) | ||||
Stock-based compensation | 36 | ||||
Cash dividends declared on common stock | (639) | ||||
Stock Investment Plan and certain share-based benefit plans, shares | 2,989,893 | ||||
Stock Investment Plan and certain share-based benefit plans | 56 | ||||
Reclass to liability awards (Note 5) | (7) | ||||
Ending Balance, Shares at Dec. 31, 2017 | 445,334,111 | 445,334,111 | |||
Ending Balance at Dec. 31, 2017 | $ 44 | $ 10,001 | $ 142 | (6,262) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Share-based compensation accounting change (Note 1) | $ (6) |
Consolidated Statements of Com8
Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Stockholders' Equity [Abstract] | |||
Unrealized gain (loss) on derivative hedges, taxes | $ 4 | $ 3 | $ 1 |
Unrealized gain (loss) on investment, taxes | 7 | 21 | 4 |
Pension and OPEB, taxes | $ (32) | $ (23) | $ (44) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ (1,724) | $ (6,177) | $ 578 |
Adjustments to reconcile net income (loss) to net cash from operating activities- | |||
Depreciation and amortization, including nuclear fuel, intangible assets and deferred debt-related costs | 1,700 | 1,974 | 1,826 |
Impairment of assets and related charges (Note 2) | 2,406 | 10,665 | 42 |
Investment impairments, including equity method investments | 13 | 21 | 464 |
Pension and OPEB mark-to-market adjustment | 141 | 147 | 242 |
Deferred income taxes and investment tax credits, net | 839 | (3,063) | 284 |
Deferred costs on sale leaseback transaction, net | 49 | 49 | 48 |
Asset removal costs charged to income | 22 | 54 | 55 |
Retirement benefits, net of payments | 29 | 64 | (20) |
Unrealized (gain) loss on derivative transactions (Note 11) | 81 | 9 | (73) |
Pension trust contributions | 0 | (382) | (143) |
Gain on sale of investment securities held in trusts | (63) | (50) | (23) |
Lease payments on sale and leaseback transaction | (73) | (120) | (131) |
Changes in current assets and liabilities- | |||
Receivables | (39) | (11) | 184 |
Materials and supplies | (6) | 41 | (15) |
Prepaid taxes and other | 30 | 27 | (10) |
Accounts payable | 72 | (37) | (243) |
Accrued taxes | (9) | 61 | 29 |
Accrued compensation and benefits | (27) | 29 | 5 |
Other current liabilities | 20 | 56 | 69 |
Cash collateral, net | 27 | (116) | 140 |
Other | 320 | 142 | 152 |
Net cash provided from operating activities | 3,808 | 3,383 | 3,460 |
New Financing- | |||
Long-term debt | 4,675 | 1,976 | 1,311 |
Short-term borrowings, net | 0 | 975 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (2,291) | (2,331) | (879) |
Short-term borrowings, net | (2,375) | 0 | (91) |
Common stock dividend payments | (639) | (611) | (607) |
Other | (72) | (43) | (26) |
Net cash used for financing activities | (702) | (34) | (292) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,587) | (2,835) | (2,704) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 388 | 15 | 20 |
Sales of investment securities held in trusts | 2,170 | 1,678 | 1,534 |
Purchases of investment securities held in trusts | (2,268) | (1,789) | (1,648) |
Asset removal costs | (172) | (145) | (142) |
Other | 7 | 27 | 8 |
Net cash used for investing activities | (2,716) | (3,281) | (3,122) |
Net change in cash and cash equivalents | 390 | 68 | 46 |
Cash and cash equivalents at beginning of period | 199 | 131 | 85 |
Cash and cash equivalents at end of period | 589 | 199 | 131 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Non-cash transaction: stock contribution to pension plan | 0 | 500 | 0 |
Interest (net of amounts capitalized) | 1,039 | 1,050 | 1,028 |
Income taxes, net of refunds | $ 53 | $ (16) | $ 37 |
Consolidated Statements of In10
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
REVENUES: | ||||
Electric sales | $ 2,958 | $ 3,789 | $ 4,398 | |
Total revenues | [1] | 14,017 | 14,562 | 15,026 |
OPERATING EXPENSES: | ||||
Fuel | 1,383 | 1,666 | 1,855 | |
Purchased power | 3,194 | 3,843 | 4,423 | |
Other operating expenses | 4,232 | 3,851 | 3,740 | |
Pension and OPEB mark-to-market adjustment | 141 | 147 | 242 | |
Provision for depreciation | 1,138 | 1,313 | 1,282 | |
General taxes | 1,043 | 1,042 | 978 | |
Impairment of assets and related charges (Note 2) | 2,406 | 10,665 | 42 | |
Total operating expenses | 13,845 | 22,824 | 12,734 | |
OPERATING INCOME (LOSS) | 172 | (8,262) | 2,292 | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss) | 98 | 84 | (22) | |
Interest expense | (1,178) | (1,157) | (1,132) | |
Capitalized interest | 79 | 103 | 117 | |
Total other expense | (1,001) | (970) | (1,399) | |
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (829) | (9,232) | 893 | |
INCOME TAXES (BENEFITS) | 895 | (3,055) | 315 | |
NET INCOME (LOSS) | (1,724) | (6,177) | 578 | |
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||
NET INCOME (LOSS) | (1,724) | (6,177) | 578 | |
OTHER COMPREHENSIVE INCOME (LOSS): | ||||
Pension and OPEB prior service costs | (85) | (59) | (116) | |
Amortized gain on derivative hedges | 10 | 8 | 5 | |
Change in unrealized gain on available-for-sale securities | 22 | 55 | (11) | |
Other comprehensive income (loss) | (53) | 4 | (122) | |
Income taxes (benefits) on other comprehensive income (loss) | (21) | 1 | (47) | |
Other comprehensive income (loss), net of tax | (32) | 3 | (75) | |
FES | ||||
REVENUES: | ||||
Other | 65 | 160 | 188 | |
Total revenues | [2] | 3,098 | 4,398 | 5,005 |
OPERATING EXPENSES: | ||||
Fuel | 599 | 780 | 871 | |
Other operating expenses | 1,514 | 1,277 | 1,308 | |
Pension and OPEB mark-to-market adjustment | 24 | 48 | 57 | |
Provision for depreciation | 109 | 336 | 324 | |
General taxes | 58 | 88 | 98 | |
Impairment of assets and related charges (Note 2) | 2,031 | 8,622 | 33 | |
Total operating expenses | 5,164 | 12,795 | 4,728 | |
OPERATING INCOME (LOSS) | (2,066) | (8,397) | 277 | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss) | 94 | 67 | (14) | |
Miscellaneous income | 7 | 7 | 3 | |
Capitalized interest | 26 | 34 | 35 | |
Total other expense | (30) | (46) | (130) | |
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (2,096) | (8,443) | 147 | |
INCOME TAXES (BENEFITS) | 295 | (2,988) | 65 | |
NET INCOME (LOSS) | (2,391) | (5,455) | 82 | |
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||
NET INCOME (LOSS) | (2,391) | (5,455) | 82 | |
OTHER COMPREHENSIVE INCOME (LOSS): | ||||
Pension and OPEB prior service costs | (14) | (14) | (6) | |
Amortized gain on derivative hedges | 2 | 0 | (3) | |
Change in unrealized gain on available-for-sale securities | 30 | 52 | (9) | |
Other comprehensive income (loss) | 18 | 38 | (18) | |
Income taxes (benefits) on other comprehensive income (loss) | 6 | 15 | (7) | |
Other comprehensive income (loss), net of tax | 12 | 23 | (11) | |
COMPREHENSIVE INCOME (LOSS) | (2,379) | (5,432) | 71 | |
FES | Affiliates | ||||
REVENUES: | ||||
Electric sales | 366 | 459 | 666 | |
OPERATING EXPENSES: | ||||
Purchased power | 201 | 624 | 353 | |
OTHER INCOME (EXPENSE): | ||||
Interest expense | (19) | (7) | (7) | |
FES | Non-Affiliates | ||||
REVENUES: | ||||
Electric sales | 2,667 | 3,779 | 4,151 | |
OPERATING EXPENSES: | ||||
Purchased power | 628 | 1,020 | 1,684 | |
OTHER INCOME (EXPENSE): | ||||
Interest expense | $ (138) | $ (147) | $ (147) | |
[1] | Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. | |||
[2] | Includes excise tax collections of $20 million, $28 million and $44 million in 2017, 2016 and 2015, respectively. |
Consolidated Statements of In11
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Excise tax collections included in Revenue | $ 390 | $ 406 | $ 416 |
FES | |||
Excise tax collections included in Revenue | $ 20 | $ 28 | $ 44 |
Consolidated Balance Sheets (12
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 589 | $ 199 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $2 in 2017 and $5 in 2016 | 1,463 | 1,440 |
Other | 191 | 175 |
Materials and supplies | 463 | 564 |
Derivatives | 37 | 140 |
Collateral | 146 | 176 |
Total current assets | 3,108 | 2,950 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 39,778 | 43,767 |
Less — Accumulated provision for depreciation | 11,925 | 15,731 |
Property, plant and equipment in service net of accumulated provision for depreciation | 27,853 | 28,036 |
Construction work in progress | 1,026 | 1,351 |
Total net property, plant and equipment | 28,879 | 29,387 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 2,678 | 2,514 |
Other | 506 | 512 |
Total other property and investments | 3,184 | 3,026 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Other | 1,053 | 1,153 |
Total deferred charges and other assets | 6,711 | 7,785 |
Total assets | 42,257 | 43,148 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,082 | 1,685 |
Short-term borrowings - affiliated companies | ||
Short-term borrowings | 300 | 2,675 |
Accounts payable- | ||
Accrued taxes | 571 | 580 |
Other | 722 | 738 |
Total current liabilities | 4,077 | 7,126 |
Common stockholders’ equity- | ||
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of December 31, 2017 and 2016 | 44 | 44 |
Accumulated other comprehensive income | 142 | 174 |
Accumulated deficit | (6,262) | (4,532) |
Long-term debt and other long-term obligations | 21,115 | 18,192 |
Total capitalization | 25,040 | 24,433 |
NONCURRENT LIABILITIES: | ||
Deferred gain on sale and leaseback transaction | 723 | 757 |
Retirement benefits | 3,975 | 3,719 |
Asset retirement obligations | 2,515 | 1,482 |
Other | 1,718 | 1,547 |
Total noncurrent liabilities | 13,140 | 11,589 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | 42,257 | 43,148 |
FES | ||
CURRENT ASSETS: | ||
Cash and cash equivalents | 1 | 2 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $2 in 2017 and $5 in 2016 | 181 | 213 |
Affiliated companies | 224 | 452 |
Other | 21 | 27 |
Notes receivable from affiliated companies | 0 | 29 |
Materials and supplies | 183 | 267 |
Derivatives | 34 | 137 |
Collateral | 130 | 157 |
Prepaid taxes and other | 22 | 63 |
Total current assets | 796 | 1,347 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 2,495 | 7,057 |
Less — Accumulated provision for depreciation | 1,823 | 5,929 |
Property, plant and equipment in service net of accumulated provision for depreciation | 672 | 1,128 |
Construction work in progress | 22 | 427 |
Total net property, plant and equipment | 694 | 1,555 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 1,856 | 1,552 |
Other | 9 | 10 |
Total other property and investments | 1,865 | 1,562 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Accumulated deferred income taxes | 1,754 | 2,279 |
Property taxes | 25 | 40 |
Derivatives | 0 | 77 |
Other | 380 | 381 |
Total deferred charges and other assets | 2,159 | 2,777 |
Total assets | 5,514 | 7,241 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 524 | 179 |
Short-term borrowings - affiliated companies | ||
Short-term borrowings | 102 | 101 |
Accounts payable- | ||
Affiliated companies | 255 | 550 |
Other | 105 | 110 |
Accrued taxes | 72 | 143 |
Derivatives | 24 | 77 |
Other | 169 | 156 |
Total current liabilities | 1,254 | 1,316 |
Common stockholders’ equity- | ||
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of December 31, 2017 and 2016 | 3,749 | 3,658 |
Accumulated other comprehensive income | 81 | 69 |
Accumulated deficit | (5,900) | (3,509) |
Total common stockholders’ equity | (2,070) | 218 |
Long-term debt and other long-term obligations | 2,299 | 2,813 |
Total capitalization | 229 | 3,031 |
NONCURRENT LIABILITIES: | ||
Deferred gain on sale and leaseback transaction | 723 | 757 |
Retirement benefits | 153 | 197 |
Asset retirement obligations | 1,945 | 901 |
Other | 1,210 | 1,039 |
Total noncurrent liabilities | 4,031 | 2,894 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | 5,514 | 7,241 |
FES | Affiliates | ||
Short-term borrowings - affiliated companies | ||
Other Short-term Borrowings | $ 105 | $ 101 |
Consolidated Balance Sheets (13
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Common stockholders’ equity- | ||
Common stock, shares authorized | 700,000,000 | 490,000,000 |
Common stock, shares outstanding | 445,334,111 | 442,344,218 |
Customer [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 51 | $ 53 |
FES | ||
Common stockholders’ equity- | ||
Common stock, no par value | ||
Common stock, shares authorized | 750 | 750 |
Common stock, shares outstanding | 7 | 7 |
FES | Customer [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 2 | $ 5 |
Consolidated Statements of Co14
Consolidated Statements of Common Stockholders' Equity (Deficit) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | Total | Common Stock | Accumulated Other Comprehensive Income | Retained Earnings (Accumulated Deficit) | FES | FESCommon Stock | FESAccumulated Other Comprehensive Income | FESRetained Earnings (Accumulated Deficit) |
Beginning Balance, Shares at Dec. 31, 2014 | 421,102,570 | 7 | ||||||
Beginning Balance at Dec. 31, 2014 | $ 42 | $ 246 | $ 2,285 | $ 3,594 | $ 57 | $ 1,934 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income (loss) | $ 578 | 578 | $ 82 | 82 | ||||
Amortized loss on derivative hedges, net of income taxes | 4 | (2) | ||||||
Change in unrealized gain on investments, net of income taxes | (7) | (5) | ||||||
Pensions and OPEB, net of income taxes | (72) | (4) | ||||||
Stock-based compensation | 10 | |||||||
Consolidated tax benefit allocation | $ 9 | |||||||
Cash dividends declared on common stock | (607) | (70) | ||||||
Ending Balance, Shares at Dec. 31, 2015 | 423,560,397 | 7 | ||||||
Ending Balance at Dec. 31, 2015 | $ 42 | 171 | 2,256 | $ 3,613 | 46 | 1,946 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income (loss) | $ (6,177) | (6,177) | $ (5,455) | (5,455) | ||||
Amortized loss on derivative hedges, net of income taxes | 5 | |||||||
Change in unrealized gain on investments, net of income taxes | 34 | 32 | ||||||
Pensions and OPEB, net of income taxes | (36) | (9) | ||||||
Inter-company asset transfer (Note 14) | 28 | |||||||
Stock-based compensation | 9 | |||||||
Consolidated tax benefit allocation | $ 8 | |||||||
Cash dividends declared on common stock | (611) | |||||||
Ending Balance, Shares at Dec. 31, 2016 | 442,344,218 | 442,344,218 | 7 | 7 | ||||
Ending Balance at Dec. 31, 2016 | $ 44 | 174 | (4,532) | $ 218 | $ 3,658 | 69 | (3,509) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net income (loss) | $ (1,724) | (1,724) | $ (2,391) | (2,391) | ||||
Amortized loss on derivative hedges, net of income taxes | 6 | 1 | ||||||
Change in unrealized gain on investments, net of income taxes | 15 | 20 | ||||||
Pensions and OPEB, net of income taxes | (53) | (9) | ||||||
Inter-company asset transfer (Note 14) | 73 | |||||||
Stock-based compensation | 3 | |||||||
Consolidated tax benefit allocation | $ 18 | |||||||
Ending Balance, Shares at Dec. 31, 2017 | 445,334,111 | 445,334,111 | 7 | 7 | ||||
Ending Balance at Dec. 31, 2017 | $ 44 | $ 142 | $ (6,262) | $ (2,070) | $ 3,749 | $ 81 | $ (5,900) | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Reclass to liability awards (Note 5) | $ (3) |
Consolidated Statements of Co15
Consolidated Statements of Common Stockholders' Equity (Deficit) (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Unrealized gain (loss) on derivative hedges, taxes | $ 4 | $ 3 | $ 1 |
Unrealized gain (loss) on investment, taxes | 7 | 21 | 4 |
Pension and OPEB, taxes | (32) | (23) | (44) |
FES | |||
Unrealized gain (loss) on derivative hedges, taxes | 1 | 0 | (1) |
Unrealized gain (loss) on investment, taxes | 10 | 20 | (4) |
Pension and OPEB, taxes | $ (5) | $ (5) | $ (2) |
Consolidated Statements of Ca16
Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | $ (1,724) | $ (6,177) | $ 578 |
Adjustments to reconcile net income (loss) to net cash from operating activities- | |||
Depreciation and amortization, including nuclear fuel, intangible assets and deferred debt-related costs | 1,700 | 1,974 | 1,826 |
Investment impairments | 13 | 21 | 464 |
Pension and OPEB mark-to-market adjustment | 141 | 147 | 242 |
Deferred income taxes and investment tax credits, net | 839 | (3,063) | 284 |
Deferred costs on sale leaseback transaction, net | 49 | 49 | 48 |
Impairment of assets and related charges (Note 2) | 2,406 | 10,665 | 42 |
Pension trust contribution | 0 | (382) | (143) |
Gain on investment securities held in trusts | (63) | (50) | (23) |
Unrealized (gain) loss on derivative transactions (Note 11) | 81 | 9 | (73) |
Lease payments on sale and leaseback transaction | (73) | (120) | (131) |
Changes in current assets and liabilities- | |||
Receivables | (39) | (11) | 184 |
Materials and supplies | (6) | 41 | (15) |
Prepaid taxes and other | 30 | 27 | (10) |
Accounts payable | 72 | (37) | (243) |
Accrued taxes | (9) | 61 | 29 |
Other current liabilities | 20 | 56 | 69 |
Cash collateral, net | 27 | (116) | 140 |
Other | 320 | 142 | 152 |
Net cash provided from operating activities | 3,808 | 3,383 | 3,460 |
New financing- | |||
Long-term debt | 4,675 | 1,976 | 1,311 |
Short-term borrowings, net | 0 | 975 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (2,291) | (2,331) | (879) |
Short-term borrowings, net | (2,375) | 0 | (91) |
Common stock dividend payments | (639) | (611) | (607) |
Other | (72) | (43) | (26) |
Net cash used for financing activities | (702) | (34) | (292) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,587) | (2,835) | (2,704) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 388 | 15 | 20 |
Sales of investment securities held in trusts | 2,170 | 1,678 | 1,534 |
Purchases of investment securities held in trusts | (2,268) | (1,789) | (1,648) |
Other | 7 | 27 | 8 |
Net cash used for investing activities | (2,716) | (3,281) | (3,122) |
Net change in cash and cash equivalents | 390 | 68 | 46 |
Cash and cash equivalents at beginning of period | 199 | 131 | 85 |
Cash and cash equivalents at end of period | 589 | 199 | 131 |
Cash paid (received) during the year - | |||
Interest (net of amounts capitalized) | 1,039 | 1,050 | 1,028 |
Income taxes, net of refunds | 53 | (16) | 37 |
FES | |||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net income (loss) | (2,391) | (5,455) | 82 |
Adjustments to reconcile net income (loss) to net cash from operating activities- | |||
Depreciation and amortization, including nuclear fuel, intangible assets and deferred debt-related costs | 333 | 633 | 579 |
Investment impairments | 13 | 19 | 90 |
Pension and OPEB mark-to-market adjustment | 24 | 48 | 57 |
Deferred income taxes and investment tax credits, net | 455 | (2,920) | 119 |
Deferred costs on sale leaseback transaction, net | 49 | 49 | 48 |
Impairment of assets and related charges (Note 2) | 2,031 | 8,622 | 33 |
Pension trust contribution | 0 | (138) | 0 |
Gain on investment securities held in trusts | (62) | (48) | (24) |
Unrealized (gain) loss on derivative transactions (Note 11) | 78 | 9 | (74) |
Lease payments on sale and leaseback transaction | (73) | (120) | (131) |
Changes in current assets and liabilities- | |||
Receivables | 282 | 89 | 277 |
Materials and supplies | (24) | 26 | (25) |
Prepaid taxes and other | 43 | (8) | 14 |
Accounts payable | (167) | (30) | (76) |
Accrued taxes | (71) | 76 | (26) |
Other current liabilities | 0 | 15 | 43 |
Cash collateral, net | 27 | (87) | 159 |
Other | 180 | 6 | 7 |
Net cash provided from operating activities | 727 | 786 | 1,152 |
New financing- | |||
Long-term debt | 0 | 471 | 341 |
Short-term borrowings, net | 4 | 101 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (163) | (507) | (411) |
Short-term borrowings, net | 0 | 0 | (126) |
Common stock dividend payments | 0 | 0 | (70) |
Other | (7) | (9) | (7) |
Net cash used for financing activities | (166) | 56 | (273) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (275) | (546) | (627) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 0 | 9 | 13 |
Sales of investment securities held in trusts | 940 | 717 | 733 |
Purchases of investment securities held in trusts | (999) | (783) | (791) |
Cash investments | (3) | 10 | (10) |
Loans to affiliated companies, net | 29 | (18) | (11) |
Other | 0 | 1 | 4 |
Net cash used for investing activities | (562) | (842) | (879) |
Net change in cash and cash equivalents | (1) | 0 | 0 |
Cash and cash equivalents at beginning of period | 2 | 2 | 2 |
Cash and cash equivalents at end of period | 1 | 2 | 2 |
Cash paid (received) during the year - | |||
Interest (net of amounts capitalized) | 128 | 111 | 114 |
Income taxes, net of refunds | (152) | (193) | (5) |
Non-cash transaction: Affiliated net asset transfer (Note 14) | $ 73 | $ 28 | $ 0 |
Organization, Basis of Presenta
Organization, Basis of Presentation | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
ORGANIZATION AND BASIS OF PRESENTATION | ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP, FET and its principal subsidiaries (ATSI, MAIT and TrAIL), and AESC. In addition, FE holds all of the outstanding equity of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc. and Allegheny Ventures, Inc. FE and its subsidiaries are principally involved in the generation, transmission and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control over 16,000 MWs of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. FES, a subsidiary of FE, was incorporated under Ohio law in 1997. FES provides energy-related products and services to retail and wholesale customers. FES also owns and operates, through its FG subsidiary, fossil generating facilities and owns, through its NG subsidiary, nuclear generating facilities, which are operated by FENOC. On December 21, 2015, FES agreed, under a PSA, to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective on April 1, 2017. FES complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NRC and applicable state regulatory authorities. FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 9, "Variable Interest Entities"). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). These Notes to Consolidated Financial Statements are combined for FirstEnergy and FES. Certain prior year amounts have been reclassified to conform to the current year presentation, including the reclassification of $30 million and $105 million of deferred purchased power and fuel costs previously included in Purchased power to Amortization of regulatory assets, net, for the years ended December 31, 2016 and 2015, respectively. Strategic Review of Competitive Operations FirstEnergy’s strategy is to be a fully regulated utility company, focusing on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission. The Company continues to focus on its regulated growth strategy and in November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation at CES, which is primarily comprised of the operations of FES and AE Supply. In connection with this strategic review, AE Supply and AGC entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply’s interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County ( 1,615 MWs of combined capacity) for an all-cash purchase price of $825 million , subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $ 388 million . The sale of AE Supply’s interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $ 375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. Additionally, on March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station ( 1,300 MWs) for approximately $195 million , resulting from an RFP issued by MP to address its generation shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of the Pleasants Power Station, subject to certain conditions as further described in Note 15, "Regulatory Matters - West Virginia," below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million . With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $100 million senior notes, which are expected to require the payment of “make-whole” premiums currently estimated to be approximately $95 million based on current interest rates. For additional information see Note 2, "Asset Sales and Impairments." The strategic options to exit the remaining portion of the CES portfolio, which is primarily at FES, are limited. The credit quality of FES, including its unsecured debt rating of Ca at Moody’s, C at S&P, and C at Fitch and the negative outlook from Moody’s and S&P, has challenged its ability to consummate asset sales. Furthermore, the inability to obtain legislative support under the Department of Energy’s recent NOPR, which was rejected by FERC, limits FES’ strategic options to plant deactivations, restructuring its debt and other financial obligations with its creditors, and/or to seek protection under U.S. bankruptcy laws. As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre-tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. For additional information see Note 2, "Asset Sales and Impairments." Going Concern at FES Although FES has access to a $500 million secured line of credit with FE, all of which was available as of January 31, 2018, its current credit rating and the current forward wholesale pricing environment present significant challenges to FES. As previously disclosed, FES has $515 million of maturing debt in 2018 (excluding intra-company debt), beginning with a $ 100 million principal payment due April 2, 2018. Based on FES' current senior unsecured debt rating, capital structure and long-term cash flow projections, the debt maturities are unlikely to be refinanced. Although management continues to explore cost reductions and other options to improve cash flow, these obligations and their impact to liquidity raise substantial doubt about FES’ ability to meet its obligations as they come due over the next twelve months and, as such, its ability to continue as a going concern. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, MAIT and TrAIL since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income (Loss) concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. As a result of the Tax Act, FirstEnergy adjusted its net deferred tax liabilities at December 31, 2017, for the reduction in the corporate income tax rate from 35% to 21%. For the portions of FirstEnergy’s business that apply regulatory accounting, the impact of reducing the net deferred tax liabilities was offset with a regulatory liability, as appropriate, for amounts expected to be refunded to rate payers in future rates, with the remainder recorded to deferred income tax expense. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2017 and December 31, 2016 , and the changes during the year ended December 31, 2017 : Net Regulatory Assets (Liabilities) by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 46 $ 90 $ (44 ) Customer receivables (payables) for future income taxes (2,765 ) 468 (3,233 ) Nuclear decommissioning and spent fuel disposal costs (323 ) (304 ) (19 ) Asset removal costs (774 ) (770 ) (4 ) Deferred transmission costs 187 122 65 Deferred generation costs 198 331 (133 ) Deferred distribution costs 258 296 (38 ) Contract valuations 118 153 (35 ) Storm-related costs 329 397 (68 ) Other 46 74 (28 ) Net Regulatory Assets (Liabilities) included on the Consolidated Balance Sheets $ (2,680 ) $ 857 $ (3,537 ) Regulatory assets that do not earn a current return totaled approximately $7 million and $ 153 million as of December 31, 2017 and 2016 , respectively, primarily related to storm damage costs, and are currently being recovered through rates. REVENUES AND RECEIVABLES Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, FirstEnergy accrues the estimated unbilled amount as revenue and reverses the related prior period estimate. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to customers for FES. There was no material concentration of receivables as of December 31, 2017 and 2016 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2017 and 2016 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2017 Billed $ 860 $ 106 Unbilled 603 75 Total $ 1,463 $ 181 December 31, 2016 Billed $ 833 $ 123 Unbilled 607 90 Total $ 1,440 $ 213 EARNINGS (LOSS) PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. As discussed below in "New Accounting Pronouncements," FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," beginning January 1, 2017. For the year ended December 31, 2017 , there were no material impacts to the basic or diluted earnings per share due to the new standard. Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock 2017 2016 2015 (In millions, except per share amounts) Net income (loss) $ (1,724 ) $ (6,177 ) $ 578 Weighted average number of basic shares outstanding 444 426 422 Assumed exercise of dilutive stock options and awards (1) — — 2 Weighted average number of diluted shares outstanding 444 426 424 Basic earnings (loss) per share of common stock $ (3.88 ) $ (14.49 ) $ 1.37 Diluted earnings (loss) per share of common stock $ (3.88 ) $ (14.49 ) $ 1.37 (1) For the years ended December 31, 2017, 2016 and 2015, approximately three million , three million and one million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and in the case of 2016 and 2017, a result of the net loss for the period. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. The cost of nuclear fuel is capitalized within the CES segment's Property, plant and equipment and charged to fuel expense using the specific identification method. Property, plant and equipment balances by segment as of December 31, 2017 and 2016 were as follows: December 31, 2017 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution $ 25,950 $ (7,503 ) $ 18,447 $ 469 $ 18,916 Regulated Transmission 10,102 (2,055 ) 8,047 480 8,527 Competitive Energy Services (2) 2,902 (1,958 ) 944 28 972 Corporate/Other 824 (409 ) 415 49 464 Total $ 39,778 $ (11,925 ) $ 27,853 $ 1,026 $ 28,879 December 31, 2016 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution $ 24,979 $ (7,169 ) $ 17,810 $ 472 $ 18,282 Regulated Transmission 9,342 (1,948 ) 7,394 383 7,777 Competitive Energy Services (2) 8,680 (6,267 ) 2,413 453 2,866 Corporate/Other 766 (347 ) 419 43 462 Total $ 43,767 $ (15,731 ) $ 28,036 $ 1,351 $ 29,387 (1) Includes capital leases of $238 million and $244 million at December 31, 2017 and 2016, respectively. (2) Primarily consists of generating assets and nuclear fuel as discussed above. In 2017, FirstEnergy fully impaired the value of its nuclear generating assets and nuclear fuel. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above, with the exception of Regulated Distribution, which has approximately $2.1 billion of regulated generation property, plant and equipment. Property, plant and equipment balances for FES as of December 31, 2017 and 2016 were as follows: December 31, 2017 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 2,344 $ (1,743 ) $ 601 $ 19 $ 620 Other 151 (80 ) 71 3 74 Total $ 2,495 $ (1,823 ) $ 672 $ 22 $ 694 December 31, 2016 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 2,212 $ (1,720 ) $ 492 $ 63 $ 555 Nuclear Generation 2,065 (1,723 ) 342 118 460 Nuclear Fuel 2,637 (2,418 ) 219 241 460 Other 143 (68 ) 75 5 80 Total $ 7,057 $ (5,929 ) $ 1,128 $ 427 $ 1,555 FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FirstEnergy's and FES' electric plant in 2017 , 2016 and 2015 are shown in the following table: Annual Composite Depreciation Rate 2017 2016 2015 FirstEnergy 2.4 % 2.5 % 2.5 % FES 4.4 % 3.3 % 3.2 % During the third quarter of 2016, FirstEnergy recorded a reduction to depreciation expense of $21 million ( $19 million prior to January 1, 2016) that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life for a component of a certain power station. Management determined this adjustment was not material to 2016 or any prior periods. For the years ended December 31, 2017 , 2016 and 2015 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $35 million , $37 million and $49 million , respectively, of allowance for equity funds used during construction and $44 million , $66 million and $68 million , respectively, of capitalized interest. For the years ended December 31, 2017 , 2016 and 2015 , capitalized financing costs on FES' Consolidated Statements of Income (Loss) includes $26 million , $34 million and $35 million , respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 40% interest ( 1,200 MWs) in a 3,003 MW pumped storage, hydroelectric station in Bath County, Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Net Property, plant and equipment includes $531 million representing AGC's share in this facility as of December 31, 2017 of which $365 million is unregulated and included within the CES segment. AGC is obligated to pay its share of the costs of this jointly-owned facility in the same proportion as its ownership interest using its own financing. AGC's share of direct expenses of the joint plant is included in FE's operating expenses on the Consolidated Statements of Income (Loss). Approximately 59% of AGC is owned by AE Supply and approximately 41% by MP. As part of FE's strategic review of its competitive operations, on January 18, 2017, AGC entered into an asset purchase agreement (which was subsequently amended and restated) with a subsidiary of LS Power to sell AE Supply's indirect interest ( 23.75% ) in Bath County, as discussed in Note 2, "Asset Sales and Impairments." Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO, considering the expected timing of settlement of the ARO based on the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives). The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2017 , are described further in Note 14, "Asset Retirement Obligations." Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. See Note 2, "Asset Sales and Impairments," for long-lived asset impairments recognized in 2017 and 2016. GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents goodwill by reporting unit for the year ended December 31, 2017 : Goodwill Regulated Distribution Regulated Transmission Consolidated (In millions) Balance as of December 31, 2017 $ 5,004 $ 614 $ 5,618 FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential impairment arise. As of July 31, 2017, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment include: growth rates, interest rates, expected capital expenditures, utility sector market performance and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying value and a quantitative analysis was not necessary. See Note 2, "Asset Sales and Impairments," for goodwill impairment recognized in 2016 at CES. INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets or liabilities. In 2017 , 2016 and 2015 , FirstEnergy recognized $13 million , $21 million and $102 million , respectively, of OTTI. During the same periods, FES recognized OTTI of $13 million , $19 million and $90 million , respectively. The fair values of FirstEnergy’s investments are disclosed in Note 10, "Fair Value Measurements." The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. FirstEnergy holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. In 2015, Global Holding incurred losses primarily as a result of declines in coal prices due to weakening global and U.S. coal demand. Based on the significant decline in coal pricing and the outlook for the coal market, including the significant decline in the market capitalization of coal companies in 2015, FirstEnergy assessed the value of its investment in Global Holding and determined there was a decline in the fair value of the investment below its carrying value that was other than temporary, resulting in a pre-tax impairment charge of $362 million recognized in 2015. Key assumptions incorporated into the discounted cash flow analysis utilized in the impairment analysis included the discount rate, future long-term coal prices, production levels, sales forecasts, projected capital and operating costs. The impairment charge is classified as a component of Other Income (Expense) in the Consolidated Statement of Income (Loss). See Note 9, "Variable Interest Entities," for further discussion of FirstEnergy's investment in Global Holding. INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed. See Note 2, "Asset Sales and Impairments," for inventory-related charges recognized in 2017. NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2016-09, " Improvements to Employee Share-Based Payment Accounting " (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million and $13 million from operating activities to financing activities in the 2016 and 2015 Consolidated Statements of Cash Flows, respectively. ASU 2016-15, " Classification of Certain Cash Receipts and Cash Payments " (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2017. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance: establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy has evaluated its revenues and the new guidance will have limited impacts to current revenue recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy will not record a cumulative adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes will be implemented. FirstEnergy expects to disaggregate revenue by type of service in future revenue disclosures. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (issued January 2016): ASU 2016-01 primarily affects the accounting for equity inve |
Asset Sales and Impairments
Asset Sales and Impairments | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Asset Sales and Impairments | ASSET SALES AND IMPAIRMENTS YEAR ENDED DECEMBER 31, 2017 Early Retirement of Nuclear Generating Assets As previously disclosed, FirstEnergy announced a strategic review to exit commodity-exposed generation at CES, which included one or more of the following options: • legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits, • restructuring FES' debt with its creditors, • seeking protection under U.S. bankruptcy laws for FES and likely FENOC, and/or • asset sales and/or plant deactivations. As part of the strategic review, FES evaluated its options with respect to its nuclear power plants. Factors considered as part of this review included current and forecasted market conditions, such as wholesale power and capacity prices, legislative and regulatory solutions that recognize their environmental and energy security benefits, and many other factors, including the significant capital and operating costs associated with operating a safe and reliable nuclear fleet. Based on this analysis, given the weak power and capacity price environment and the lack of legislative and regulatory solutions achieved to date, FES concluded that it would be increasingly difficult to operate these facilities in this environment and absent significant change concluded that it was probable that the facilities would be either deactivated or sold before the end of their estimated useful lives. As a result, FES recorded a pre-tax charge of $2.0 billion in the fourth quarter of 2017 to fully impair the nuclear facilities, including the generating plants and nuclear fuel as well as to reserve against the value of materials and supplies inventory and to increase its asset retirement obligation. The charges consisted of the following: (In millions) Pre-tax charge Nuclear generating asset Beaver Valley $ 107 Davis Besse 420 Perry 124 Nuclear fuel 369 Materials and supplies 81 Asset retirement obligation 944 Total non-cash charges $ 2,045 The fair value analysis for the generating assets was based on the income approach, a discounted cash flow method, to determine the amount of the impairment. Key assumptions used in determining the pre-tax non-cash charge included forward power and capacity price projections, the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives), the timing of decommissioning activities, and operating and capital costs, all of which are subject to a high degree of judgment and complexity. In addition to these one-time non-cash impairment charges, there will be ongoing charges to earnings primarily related to ongoing capital and nuclear fuel spend, as well as additional ARO accretion expense. Pleasants Power Station On March 6, 2017, AE Supply and MP entered into an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station ( 1,300 MWs) for approximately $195 million , resulting from an RFP issued by MP to address its generation shortfall. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. On January 26, 2018, the WVPSC approved the transfer of Pleasants, subject to certain conditions as further described below, which included MP assuming significant commodity risk. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement and on February 16, 2018, AE Supply announced its intent to exit operations of the Pleasants Power Station by January 1, 2019, through either sale or deactivation, which resulted in a pre-tax impairment charge of $120 million in the fourth quarter of 2017 to reduce the carrying value to $75 million . Competitive Generation Asset Sale FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County ( 1,615 MWs of combined capacity) for an all-cash purchase price of $825 million , subject to adjustments and through multiple, independent closings. On December 13, 2017, AE Supply completed the sale of the natural gas generating plants with net proceeds, subject to post-closing adjustments, of approximately $388 million. The sale of AE Supply's interests in the Bath County hydroelectric power station and the Buchanan Generating facility is expected to generate net proceeds of $375 million and is anticipated to close in the first half of 2018, subject in each case to various customary and other closing conditions, including, without limitation, receipt of regulatory approvals. As part of the closing of the natural gas generating plants, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC arising under the amended and restated purchase agreement. With the sale of the gas plants completed, upon the consummation of the sale of AGC's interest in the Bath County hydroelectric power station or the sale or deactivation of the Pleasants Power Station, AE Supply is obligated under the amended and restated purchase agreement and AE Supply's applicable debt agreements to satisfy and discharge approximately $305 million of currently outstanding senior notes, as well as its $142 million of pollution control notes and AGC's $ 100 million senior notes, which are expected to require the payment of "make-whole" premiums currently estimated to be approximately $95 million based on current interest rates. On October 20, 2017, the parties filed an application with the VSCC for approval of the sale of approximately 59% of AGC's interest in the Bath County hydroelectric power station. On December 12, 2017, FERC issued an order authorizing the partial transfer of the related hydroelectric license for Bath County under Part I of the FPA. In December 2017, AGC, AE Supply and MP filed with FERC and AGC and AE Supply filed with the VSCC, applications for approval of AGC redeeming AE Supply’s shares in AGC upon consummation of the Bath County transaction. On February 2, 2018, the VSCC issued an order finding that approval of the proposed stock redemption is not required, and on February 16, 2018, FERC issued an order authorizing the redemption. Upon the consummation of the redemption, AGC will become a wholly-owned subsidiary of MP. On December 28, 2017, FERC issued an order authorizing the sale of BU Energy’s Buchanan interests. Additional filings have been submitted to FERC for the purpose of amending affected FERC-jurisdictional rates and implementing the transaction once the sales are consummated. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the remaining transactions will be consummated. As a result of the amended asset purchase agreement, CES recorded non-cash pre-tax impairment charges of $193 million in 2017, reflecting the $825 million purchase price as well as certain purchase price adjustments based on timing of the closing of the transaction. Assets held for sale related to this transaction as of December 31, 2017 , include property, plant and equipment (net of accumulated provision for depreciation) of $354 million , investments of $19 million , and materials and supplies inventory of $2 million . Transmission Formula Rate Settlements As described in Note 15, "Regulatory Matters," on October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, MAIT recorded a pre-tax impairment charge of $13 million in the third quarter of 2017. As described in Note 15, "Regulatory Matters," on December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC, which is subject to a final order. As a result of the settlement agreement, JCP&L recorded a pre-tax impairment charge of $28 million in the fourth quarter of 2017. YEAR ENDED DECEMBER 31, 2016 Competitive Generation Deactivations and Other Exit Activities On July 22, 2016, FirstEnergy and FES announced its intent to exit operations of the Bay Shore Unit 1 generating station ( 136 MWs) by October 1, 2020, through either sale or deactivation and to deactivate Units 1-4 of the W. H. Sammis generating station ( 720 MWs) by May 31, 2020. As a result, FirstEnergy recorded a non-cash pre-tax impairment charge of $647 million ( $517 million - FES) in the second quarter of 2016. PJM and the Independent Market Monitor have approved the W.H. Sammis Units 1-4 and Bay Shore Unit 1 deactivations. In addition, FirstEnergy and FES recorded termination and settlement costs on fuel contracts of approximately $58 million (pre-tax) in the second quarter of 2016 resulting from plant retirements and deactivations, which is included in the caption of Fuel in the Consolidated Statement of Income (Loss). As disclosed in Note 1, "Organization and Basis of Presentation," in November 2016, FirstEnergy announced a strategic review to exit its commodity-exposed generation as it transitions to a fully regulated utility. As part of assessing the viability of strategic alternatives, FirstEnergy determined that the carrying value of long-lived assets of the competitive business were not recoverable, specifically given FirstEnergy’s target to implement its exit from competitive operations by mid-2018, significantly before the end of the original useful lives, and the anticipated cash flows over this shortened period. As a result, CES recorded a non-cash pre-tax impairment charge of $9,218 million ( $8,082 million at FES) in the fourth quarter of 2016 to reduce the carrying value of certain assets to their estimated fair value, including long-lived assets, such as generating plants and nuclear fuel, as well as other assets, such as materials and supplies. Key assumptions used in determining the impairment charges of long-lived assets included forward power price projections, the expected duration of ownership of the plants, environmental compliance costs and strategies, operating costs, and estimated sale proceeds. Those same cash flow assumptions, along with a discount rate were used to estimate the fair value of each plant. These assumptions are subject to a high degree of judgment and complexity. The fair value estimate of these long-lived assets was based on a combination of the income approach, which considers discounted cash flows, and corroboration with the market approach, which considers market comparisons for similar assets within the electric generation industry. Goodwill As a result of low capacity prices associated with the 2019/2020 PJM Base Residual Auction in May 2016, as well as its annual update to its fundamental long-term capacity and energy price forecast, FirstEnergy determined that an interim impairment analysis of the CES reporting unit’s goodwill was necessary during the second quarter of 2016. Consistent with FirstEnergy’s annual goodwill impairment test, a discounted cash flow analysis was used to determine the fair value of the CES reporting unit for purposes of step one of the interim goodwill impairment test. Key assumptions incorporated into the CES discounted cash flow analysis requiring significant management judgment included the following: • Future Energy and Capacity Prices: Observable market information for near-term forward power prices, PJM auction results for near term capacity pricing, and a longer-term fundamental pricing model for energy and capacity that considered the impact of key factors such as load growth, plant retirements, carbon and other environmental regulations, and natural gas pipeline construction, as well as coal and natural gas pricing. • Retail Sales and Margin: CES' current retail targeted portfolio to estimate future retail sales volume as well as historical financial results to estimate retail margins. • Operating and Capital Costs: Estimated future operating and capital costs, including the estimated impact on costs of pending carbon and other environmental regulations, as well as costs associated with capacity performance reforms in the PJM market. • Discount Rate: A discount rate of 9.50% , based on selected comparable companies' capital structure, return on debt and return on equity. • Terminal Value: A terminal value of 7.0 x earnings before interest, taxes, depreciation and amortization based on consideration of peer group data and analyst consensus expectations. Based on the impairment analysis, FirstEnergy determined that the carrying value of goodwill exceeded its fair value and recognized a non-cash pre-tax impairment charge of $800 million ( $23 million - FES) in the second quarter of 2016, which is included in Impairment of assets and related charges in the Consolidated Statement of Income (Loss). YEAR ENDED DECEMBER 31, 2015 During 2015, FirstEnergy and FES recognized impairment charges of $42 million and $33 million , respectively, associated with certain transportation equipment and facilities. In order to conform to current year presentation, the charges were reclassified from Other operating expenses in the Consolidated Statement of Income (Loss) to Impairment of assets and related charges. The impairment charges are included within the Regulated Distribution segment ( $8 million ) and the CES segment ( $34 million ). |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2017 , 2016 and 2015 for FirstEnergy are shown in the following table: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 10 24 Amounts reclassified from AOCI 5 (25 ) (126 ) (146 ) Other comprehensive income (loss) 5 (11 ) (116 ) (122 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (44 ) (47 ) Other comprehensive income (loss), net of tax 4 (7 ) (72 ) (75 ) AOCI Balance, December 31, 2015 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 106 13 119 Amounts reclassified from AOCI 8 (51 ) (72 ) (115 ) Other comprehensive income (loss) 8 55 (59 ) 4 Income tax (benefits) on other comprehensive income (loss) 3 21 (23 ) 1 Other comprehensive income (loss), net of tax 5 34 (36 ) 3 AOCI Balance, December 31, 2016 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 85 (11 ) 74 Amounts reclassified from AOCI 10 (63 ) (74 ) (127 ) Other comprehensive income (loss) 10 22 (85 ) (53 ) Income tax (benefits) on other comprehensive income (loss) 4 7 (32 ) (21 ) Other comprehensive income (loss), net of tax 6 15 (53 ) (32 ) AOCI Balance, December 31, 2017 $ (22 ) $ 67 $ 97 $ 142 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2017 , 2016 and 2015 : FirstEnergy Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 2 $ — $ (3 ) Other operating expenses Long-term debt 8 8 8 Interest expense 10 8 5 Total before taxes (4 ) (3 ) (1 ) Income taxes (benefits) $ 6 $ 5 $ 4 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (63 ) $ (51 ) $ (25 ) Investment income (loss) 23 19 9 Income taxes (benefits) $ (40 ) $ (32 ) $ (16 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (74 ) $ (72 ) $ (126 ) (1) 28 27 49 Income taxes (benefits) $ (46 ) $ (45 ) $ (77 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. The changes in AOCI for the years ended December 31, 2017 , 2016 and 2015 for FES are shown in the following table: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 15 10 25 Amounts reclassified from AOCI (3 ) (24 ) (16 ) (43 ) Other comprehensive loss (3 ) (9 ) (6 ) (18 ) Income tax benefits on other comprehensive loss (1 ) (4 ) (2 ) (7 ) Other comprehensive loss, net of tax (2 ) (5 ) (4 ) (11 ) AOCI Balance, December 31, 2015 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 100 — 100 Amounts reclassified from AOCI — (48 ) (14 ) (62 ) Other comprehensive income (loss) — 52 (14 ) 38 Income tax (benefits) on other comprehensive income (loss) — 20 (5 ) 15 Other comprehensive income (loss), net of tax — 32 (9 ) 23 AOCI Balance, December 31, 2016 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 91 — 91 Amounts reclassified from AOCI 2 (61 ) (14 ) (73 ) Other comprehensive income (loss) 2 30 (14 ) 18 Income tax (benefits) on other comprehensive income (loss) 1 10 (5 ) 6 Other comprehensive income (loss), net of tax 1 20 (9 ) 12 AOCI Balance, December 31, 2017 $ (8 ) $ 68 $ 21 $ 81 The following amounts were reclassified from AOCI for FES in the years ended December 31, 2017 , 2016 and 2015 : FES Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 2 $ — $ (3 ) Other operating expenses (1 ) — 1 Income taxes (benefits) $ 1 $ — $ (2 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (61 ) $ (48 ) $ (24 ) Investment income (loss) 23 18 9 Income taxes (benefits) $ (38 ) $ (30 ) $ (15 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14 ) $ (14 ) $ (16 ) (1) 5 5 6 Income taxes (benefits) $ (9 ) $ (9 ) $ (10 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. |
Pension and Other Postemploymen
Pension and Other Postemployment Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS | PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2017, 2016, and 2015 were $141 million , $147 million , and $242 million , respectively. In 2017, the pension and OPEB mark-to-market adjustment primarily reflects a 50 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016. In January 2018, FirstEnergy satisfied its minimum required funding obligations of $500 million and addressed funding obligations for future years to its qualified pension plan with additional contributions of $750 million. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2017 , FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $999 million , or 15.1% , compared to gains of $472 million , or 8.2% , in 2016 and losses of $(172) million , or (2.7)% , in 2015 , and assumed a 7.50% rate of return for 2017 and 2016 and a 7.75% rate of return for 2015 on plan assets which generated $478 million , $429 million and $476 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will increase or decrease future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. During 2017, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2017, incorporating three additional years of SSA data on U.S. population mortality. MP-2017 incorporates SSA mortality data from 2013 to 2015 and a slight modification of two input values designed to improve the model’s year-over-year stability. The updated improvement scale indicates a slight decline in life expectancy. Due to the additional years of data on population mortality, the RP2014 mortality table with the projection scale MP-2017 was utilized to determine the 2017 benefit cost and obligation as of December 31, 2017 for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2017 resulted in a decrease in the projected pension benefit obligation of $62 million and was included in the 2017 pension and OPEB mark-to-market adjustment. Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2017 2016 2017 2016 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,426 $ 9,079 $ 711 $ 724 Service cost 208 191 5 5 Interest cost 390 398 27 30 Plan participants’ contributions — — 4 5 Plan amendments 11 — — (13 ) Medicare retiree drug subsidy — — 1 1 Actuarial loss 610 224 32 14 Benefits paid (478 ) (466 ) (49 ) (55 ) Benefit obligation as of December 31 $ 10,167 $ 9,426 $ 731 $ 711 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 6,213 $ 5,338 $ 420 $ 431 Actual return on plan assets 950 442 49 30 Company contributions 18 899 16 9 Plan participants’ contributions — — 4 5 Benefits paid (477 ) (466 ) (50 ) (55 ) Fair value of plan assets as of December 31 $ 6,704 $ 6,213 $ 439 $ 420 Funded Status: Qualified plan $ (3,043 ) $ (2,821 ) Non-qualified plans (420 ) (392 ) Funded Status $ (3,463 ) $ (3,213 ) $ (292 ) $ (291 ) Accumulated benefit obligation $ 9,583 $ 8,913 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ — $ 9 $ — $ — Current liabilities (19 ) (19 ) — — Noncurrent liabilities (3,444 ) (3,203 ) (292 ) (291 ) Net liability as of December 31 $ (3,463 ) $ (3,213 ) $ (292 ) $ (291 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 32 $ 28 $ (206 ) $ (288 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 3.75 % 4.25 % 3.50 % 4.00 % Rate of compensation increase 4.20 % 4.20 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0-5.5% 6.0-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2027 Allocation of Plan Assets (as of December 31) Equity securities 42 % 44 % 50 % 53 % Bonds 32 % 30 % 33 % 41 % Absolute return strategies 10 % 8 % — % — % Real estate funds 9 % 10 % — % — % Private equity funds 1 % — % — % — % Cash and short-term securities 6 % 8 % 17 % 6 % Total 100 % 100 % 100 % 100 % Pension OPEB Components of Net Periodic Benefit Costs 2017 2016 2015 2017 2016 2015 (In millions) Service cost $ 208 $ 191 $ 193 $ 5 $ 5 $ 5 Interest cost 390 398 383 27 30 29 Expected return on plan assets (448 ) (399 ) (443 ) (30 ) (30 ) (33 ) Amortization of prior service cost (credit) 7 8 8 (81 ) (80 ) (134 ) Pension & OPEB mark-to-market adjustment 108 179 344 13 15 25 Net periodic benefit cost (credit) $ 265 $ 377 $ 485 $ (66 ) $ (60 ) $ (108 ) Assumptions Used to Determine Net Periodic Benefit Cost * for Years Ended December 31 Pension OPEB 2017 2016 2015 2017 2016 2015 Weighted-average discount rate 4.25 % 4.50 % 4.25 % 4.00 % 4.25 % 4.00 % Expected long-term return on plan assets 7.50 % 7.50 % 7.75 % 7.50 % 7.50 % 7.75 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A N/A * Excludes impact of pension and OPEB mark-to-market adjustment. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2017 and 2016 . December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 379 $ — $ 379 6 % Equity investments Domestic 695 27 — 722 11 % International 514 1,569 — 2,083 31 % Fixed income Government bonds — 251 — 251 4 % Corporate bonds — 1,237 — 1,237 18 % High yield debt — 689 — 689 10 % Mortgage-backed securities (non-government) — 31 — 31 — % Alternatives Hedge funds (Absolute return) — 635 — 635 10 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 631 631 9 % Total (1) $ 1,209 $ 4,817 $ 631 $ 6,657 99 % Private equity funds (2) 57 1 % Total Investments $ 6,714 100 % (1) Excludes $(10) million as of December 31, 2017 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net asset value used as a practical expedient to approximate fair value. December 31, 2016 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 464 $ — $ 464 8 % Equity investments Domestic (1) 1,048 13 — 1,061 17 % International 422 1,269 — 1,691 27 % Fixed income Government bonds — 106 — 106 2 % Corporate bonds — 1,245 — 1,245 20 % High yield debt — 372 — 372 6 % Mortgage-backed securities (non-government) — 112 — 112 2 % Alternatives Hedge funds (Absolute return) — 500 — 500 8 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 615 615 10 % Total (2) $ 1,470 $ 4,080 $ 615 $ 6,165 100 % Private equity funds (3) 33 — % Total Investments $ 6,198 100 % (1) As a result of the $500 million equity contribution on December 13, 2016, there was $293 million of FE Stock included in the pension plan assets as of December 31, 2016. (2) Excludes $16 million as of December 31, 2016 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (3) Net asset value used as a practical expedient to approximate fair value. The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2017 and 2016 : Real Estate Funds Balance as of January 1, 2016 $ 587 Actual return on plan assets: Unrealized gains 29 Realized gains (losses) 14 Transfers in (15 ) Balance as of December 31, 2016 $ 615 Actual return on plan assets: Unrealized gains 3 Realized gains 10 Transfers in (out) 3 Balance as of December 31, 2017 $ 631 As of December 31, 2017 and 2016 , the OPEB trust investments measured at fair value were as follows: December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 75 $ — $ 75 17 % Equity investment Domestic 220 — — 220 50 % Fixed income Government bonds — 109 — 109 24 % Corporate bonds — 34 — 34 8 % Mortgage-backed securities (non-government) 3 — 3 1 % Total (1) $ 220 $ 221 $ — $ 441 100 % (1) Excludes $(2) million as of December 31, 2017 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2016 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 27 $ — $ 27 6 % Equity investment Domestic 223 — — 223 53 % Fixed income U.S. treasuries — 40 — 40 9 % Government bonds — 108 — 108 26 % Corporate bonds — 24 — 24 6 % Mortgage-backed securities (non-government) — 2 — 2 — % Total (1) $ 223 $ 201 $ — $ 424 100 % (1) Excludes $(4) million as of December 31, 2016 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2017 and 2016 are shown in the following table: Target Asset Allocations Equities 38 % Fixed income 30 % Absolute return strategies 8 % Real estate 10 % Alternative investments 8 % Cash 6 % 100 % Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage-Point Increase 1-Percentage-Point Decrease (In millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on accumulated benefit obligation $ 21 $ (18 ) Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2018 $ 518 $ 55 $ (1 ) 2019 531 54 (1 ) 2020 552 53 (1 ) 2021 567 53 (1 ) 2022 581 52 (1 ) Years 2023-2027 3,056 241 (3 ) FES’ share of the pension and OPEB net (liability) asset as of December 31, 2017 and 2016 , was as follows: Pension OPEB 2017 2016 2017 2016 (In millions) Net (Liability) Asset (1) $ (97 ) $ (158 ) $ 40 $ 36 (1) Excludes $954 million and $866 million as of December 31, 2017 and 2016, respectively, of affiliated non-current liabilities related to pension and OPEB mark-to-market costs allocated to FES of which $626 million and $570 million , respectively, are from FENOC. FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years ended December 31, 2017 , was as follows: Pension OPEB 2017 2016 2015 2017 2016 2015 (In millions) Net Periodic Cost (Credit) $ 60 $ (5 ) $ 10 $ (17 ) $ (26 ) $ (22 ) |
Stock-Based Compensation Plans
Stock-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation Plans | STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10 million shares, respectively, of common stock or their equivalent. As of December 31, 2017 , approximately 6 million shares were available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under the ICP 2007. Shares not issued due to forfeitures or cancellations may be added back to the ICP 2015. Shares used under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods range from one to ten years , with the majority of awards having a vesting period of three years . FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," FE has elected to account for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2017 , 2016 and 2015 were $15 million , $13 million and $10 million , respectively. The income tax effects of awards are recognized in the income statement when the awards vest or are settled. Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and FES plans are included in the following tables: FirstEnergy Years Ended December 31 Stock-based Compensation Plan 2017 2016 2015 (In millions) Restricted Stock Units $ 49 $ 62 $ 46 Restricted Stock 1 2 2 Performance Shares — (3 ) — 401(k) Savings Plan 42 39 38 EDCP & DCPD 6 5 3 Total $ 98 $ 105 $ 89 Stock-based compensation costs capitalized $ 37 $ 38 $ 32 FES Years Ended December 31 Stock-based Compensation Plan 2017 2016 2015 (In millions) Restricted Stock Units $ 4 $ 11 $ 6 401(k) Savings Plan 3 5 5 Total $ 7 $ 16 $ 11 Stock-based compensation costs capitalized $ 1 $ 2 $ 1 Outstanding stock options were fully amortized as of December 31, 2016 . Stock option expense was not material for FirstEnergy or FES for the years December 31, 2016 and 2015 . Income tax benefits associated with stock based compensation plan expense were $10 million , $14 million and $12 million (FES - $1 million , $2 million and $2 million ) for the years ended 2017 , 2016 and 2015 , respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds will be paid in stock and one-third will be paid in cash. All performance-based restricted stock units granted prior to 2015 were payable in stock. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for cash performance-based restricted stock units as of December 31, 2017 was $41 million . During 2017, restricted stock unit award agreements for certain employees were amended such that the two-thirds originally designated to be paid in stock will be paid in cash. These awards are included within the cash performance-based restricted stock unit liability. No cash was paid to settle the restricted stock unit obligations in 2017 . The vesting period for each of the awards was three years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions. Restricted stock unit activity for the year ended December 31, 2017 , was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2017 3,063,729 $ 32.98 Granted in 2017 1,577,844 31.71 Forfeited in 2017 (169,012 ) 32.66 Vested in 2017 (1) (1,156,810 ) 30.81 Nonvested as of December 31, 2017 3,315,751 $ 33.24 (1) Excludes dividend equivalents of 159,274 shares earned during vesting period. The weighted-average fair value of awards granted in 2017 , 2016 and 2015 was $ 31.71 , $34.77 and $35.27 , respectively. For the years ended December 31, 2017 , 2016 , and 2015 , the fair value of restricted stock units vested was $42 million , $36 million , and $22 million , respectively. As of December 31, 2017 , there was $33 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units; that cost is expected to be recognized over a period of approximately three years. Restricted Stock Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FirstEnergy common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock. Restricted common stock (restricted stock) activity for the year ended December 31, 2017 , was not material. Stock Options Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock options granted in 2017 . Stock option activity during 2017 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2017 (1,376,821 options exercisable) 1,376,821 $ 44.60 Options forfeited (9,946 ) 70.60 Balance, December 31, 2017 (1,366,875 options exercisable) 1,366,875 $ 44.41 There was no cash received from the exercise of stock options in 2017 and 2016 . Cash received from the exercise of stock options in 2015 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2017 , was 1.67 years . Performance Shares Prior to the 2015 grant of performance-based restricted stock units discussed above, the Company granted performance shares. Performance shares are share equivalents and do not have voting rights. The performance shares outstanding track the performance of FE's common stock over a three -year vesting period. Dividend equivalents accrue on performance shares and are reinvested into additional performance shares with the same performance conditions. The final account value may be adjusted based on the ranking of FE stock performance to a composite of peer companies. In 2016 , $2 million cash was paid to settle performance shares that vested over the 2013-2015 performance cycle. In 2017, no cash was paid to settle performance shares that vested over the 2014-2016 performance cycle. FirstEnergy no longer has outstanding performance share awards. 401(k) Savings Plan In 2017 and 2016 , 1,304,863 and 1,159,215 shares of FE common stock, respectively, were issued and contributed to participants' accounts. EDCP Under the EDCP, covered employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash can vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, Short-Term Incentive Awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years , effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. DCPD Under the DCPD, members of the Board of Directors can elect to allocate all or a portion of their equity retainers to deferred stock and their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $8 million and $7 million as of December 31, 2017 and December 31, 2016 , respectively, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets. |
Taxes
Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Taxes | TAXES FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. On December 22, 2017, the President signed into law the Tax Act. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities including FirstEnergy’s regulated distribution and transmission subsidiaries. The more significant changes that impact FirstEnergy included in the Tax Act are the following: • Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018; • Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023; • Limitations on interest deductions with an exception for rate regulated utilities; • Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward; • Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers. The most significant change that impacts FirstEnergy in the current year is the reduction of the corporate federal income tax rate. Other provisions are not expected to have a significant impact on the financial statements, but may impact the effective tax rate in future years. Under US GAAP, specifically ASC Topic 740, Income Taxes, the tax effects of changes in tax laws must be recognized in the period in which the law is enacted, or December 22, 2017, for the Tax Act. ASC 740 also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment, FirstEnergy’s deferred taxes were re-measured based upon the new tax rate, which resulted in a material decrease to FirstEnergy’s net deferred income tax liabilities. For FirstEnergy’s unregulated operations, the change in deferred taxes are recorded as an adjustment to FirstEnergy’s deferred income tax provision. FirstEnergy’s regulated entities recorded a corresponding net regulatory liability to the extent the change in deferred taxes would result in amounts previously collected from utility customers to be subject to refunds to such customers, generally through reductions in future rates. All other amounts were recorded as an adjustment to FirstEnergy’s regulated entities’ deferred income tax provision. FirstEnergy has completed its assessment of the accounting for certain effects of the provisions in the Tax Act, and as allowed under SEC Staff Accounting Bulletin 118 (SAB 118), has recorded provisional income tax amounts as of December 31, 2017 related to depreciation for which the impacts of the Tax Act could not be finalized, but for which a reasonable estimate could be determined. Under the new law, property acquired and placed into service after September 27, 2017, will be eligible for full expensing for all taxpayers other than regulated utilities. As a result, FirstEnergy will need to evaluate the contractual terms of its capital expenditures to determine eligibility for full expensing. As of December 31, 2017, FirstEnergy has not yet completed this analysis, but has recorded a reasonable estimate of the effects of these changes based on capital costs incurred prior to year-end. In addition, SAB 118 allows for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017. FirstEnergy expects to record any final adjustments to the provisional amounts by the fourth quarter of 2018, which could result in a material impact to FirstEnergy’s income tax provision or financial position. FirstEnergy’s assessment of accounting for the Tax Act are based upon management’s current understanding of the Tax Act. However, it is expected that further guidance will be issued during 2018, which may result in adjustments that could have a material impact to FirstEnergy’s future results of operations, cash flows, or financial position. As a result of the Tax Act, FirstEnergy recognized a non-cash charge to income tax expense of $1.2 billion (FES - $1.1 billion ) and resulted in excess deferred taxes of $ 2.3 billion for the regulated business, of which the revenue impact was recorded as a regulatory liability. These adjustments had no impact on our 2017 cash flows. INCOME TAXES (BENEFITS) 2017 2016 2015 (In millions) FirstEnergy Currently payable (receivable)- Federal $ 14 $ (1 ) $ 1 State 42 9 30 56 8 31 Deferred, net- Federal 876 (3,114 ) 277 State (29 ) 59 15 847 (3,055 ) 292 Investment tax credit amortization (8 ) (8 ) (8 ) Total provision for income taxes (benefits) $ 895 $ (3,055 ) $ 315 FES Currently payable (receivable)- Federal $ (159 ) $ (67 ) $ (56 ) State (1 ) (1 ) 2 (160 ) (68 ) (54 ) Deferred, net- Federal 509 (2,861 ) 103 State (52 ) (57 ) 18 457 (2,918 ) 121 Investment tax credit amortization (2 ) (2 ) (2 ) Total provision for income taxes (benefits) $ 295 $ (2,988 ) $ 65 FirstEnergy and FES tax rates are affected by permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the three years ended December 31: 2017 2016 2015 (In millions) FirstEnergy Income (loss) before income taxes (benefits) $ (829 ) $ (9,232 ) $ 893 Federal income tax expense (benefit) at statutory rate (35%) $ (290 ) $ (3,231 ) $ 313 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (4 ) (192 ) 17 AFUDC equity and other flow-through (15 ) (13 ) (16 ) Amortization of investment tax credits (8 ) (8 ) (8 ) Change in accounting method — — (8 ) ESOP dividend (6 ) (6 ) (6 ) Impairment of non-deductible goodwill — 157 — Remeasurement of deferred taxes 1,193 — — Uncertain tax positions (3 ) (16 ) 1 Valuation allowances 29 246 18 Other, net (1 ) 8 4 Total income taxes (benefits) $ 895 $ (3,055 ) $ 315 Effective income tax rate (108.0 )% 33.1 % 35.3 % FES Income (loss) before income taxes (benefits) $ (2,096 ) $ (8,443 ) $ 147 Federal income tax expense (benefit) at statutory rate (35%) $ (734 ) $ (2,955 ) $ 51 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (52 ) (188 ) 2 Amortization of investment tax credits (2 ) (2 ) (2 ) ESOP dividend — (1 ) (1 ) Impairment of non-deductible goodwill — 9 — Remeasurement of deferred taxes 1,067 — — Uncertain tax positions — (8 ) 5 Valuation allowances 18 151 14 Other, net (2 ) 6 (4 ) Total income taxes (benefits) $ 295 $ (2,988 ) $ 65 Effective income tax rate (14.1 )% 35.4 % 44.2 % Absent the impact from the Tax Act, discussed above, FirstEnergy’s effective tax rate on pre-tax losses for 2017 and 2016 was 35.9% and 33.1% , respectively. The change in the effective tax rate resulted primarily from the absence of 2016 charges, including $246 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $800 million of goodwill, of which $433 million was non-deductible for tax purposes. Absent the impact from the Tax Act, discussed above, FES’ 2017 effective tax rate on pre-tax losses for 2017 and 2016 was 36.8% , and 35.4% , respectively. The change in the effective tax resulted primarily from the absence of $151 million of valuation allowances recorded against state and local deferred tax assets, that management believes, more likely than not, will not be realized, as well as the impairment of $23 million of goodwill, which was non-deductible for tax purposes. Accumulated deferred income taxes as of December 31, 2017 and 2016 , are as follows: 2017 2016 (In millions) FirstEnergy Property basis differences $ 3,662 $ 7,088 Deferred sale and leaseback gain (231 ) (351 ) Pension and OPEB (952 ) (1,347 ) Nuclear decommissioning activities 450 635 Asset retirement obligations (453 ) (669 ) Regulatory asset/liability 416 545 Deferred compensation (177 ) (269 ) Nuclear Fuel (375 ) (90 ) Loss carryforwards and AMT credits (1,467 ) (2,251 ) Valuation reserve 580 438 All other (94 ) 36 Net deferred income tax liability $ 1,359 $ 3,765 FES Property basis differences $ (677 ) $ (1,009 ) Deferred sale and leaseback gain (219 ) (328 ) Pension and OPEB (244 ) (366 ) Lease market valuation liability 75 111 Nuclear decommissioning activities 411 540 Asset retirement obligations (296 ) (453 ) Nuclear Fuel (375 ) (90 ) Loss carryforwards and AMT credits (587 ) (830 ) Valuation reserve 268 197 All other (110 ) (51 ) Net deferred income tax asset $ (1,754 ) $ (2,279 ) FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2009-2016. In February 2017, the IRS completed its examination of FirstEnergy's 2015 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income. In August 2017, the IRS substantially completed its examination of FirstEnergy’s 2016 federal income tax return and, on January 18, 2018, issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy’s taxable income. FirstEnergy and FES have recorded as deferred income tax assets the effect of Federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2017 , FirstEnergy's loss carryforwards and AMT credits consisted of $4.3 billion ($ 908 million , net of tax) of Federal NOL carryforwards that will begin to expire in 2031 and Federal AMT credits of $ 39 million that have an indefinite carryforward period. As of December 31, 2017 , FES' loss carryforwards consisted of $2.0 billion ( $429 million , net of tax) of Federal NOL carryforwards that will begin to expire in 2031. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10.5 billion ( $496 million , net of tax) for FirstEnergy, of which approximately $1.8 billion ( $81 million , net of tax) is expected to be utilized based on current estimates and assumptions. FES’ pre-tax NOL carryforwards for state and local income tax purposes is approximately $3.7 billion ( $154 million , net of tax), of which $2 million is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. Expiration Period FirstEnergy FES (In millions) State Local State Local 2018-2022 $ 806 $ 3,472 $ 2 $ 1,954 2023-2027 1,963 — 32 — 2028-2032 2,382 — 703 — 2033-2037 1,896 — 982 — $ 7,047 $ 3,472 $ 1,719 $ 1,954 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. As of December 31, 2017 and 2016 , FirstEnergy's total unrecognized income tax benefits were approximately $80 million and $84 million , respectively. If ultimately recognized in future years, approximately $24 million of unrecognized income tax benefits would impact the effective tax rate. On October 18, 2017, the Supreme Court of Pennsylvania affirmed the Commonwealth Court’s holding that the state’s net loss carryover provision violated the Pennsylvania Uniformity Clause and was unconstitutional. However, the supreme court also opined that the portion of the net loss carryover provision that created the violation may be severed from the statute, enabling the statute to operate as the legislature intended, and on October 30, 2017, the Pennsylvania Governor signed House Bill 542 into law which, among other things, amended Pennsylvania’s limitation on net loss deductions to remove the flat-dollar limitation. On January 4, 2018, the supreme court denied to further hear any arguments related to the matter and, as a result, FirstEnergy withdrew its protective refund claims from the state of Pennsylvania on January 30, 2018. Upon doing so, FirstEnergy will reverse a previously recorded unrecognized tax benefit of approximately $45 million in the first quarter of 2018, none of which will impact FirstEnergy’s effective tax rate. As of December 31, 2017 , it is reasonably possible that approximately $2 million of additional unrecognized tax benefits may be resolved during 2018 as a result of the statute of limitations expiring, none of which would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended 2017 , 2016 and 2015 : FirstEnergy FES (In millions) Balance, January 1, 2015 $ 34 $ 3 Current year increases 3 — Prior years increases 7 5 Prior years decreases (10 ) — Balance, December 31, 2015 $ 34 $ 8 Current year increases 2 — Prior years increases 69 — Prior years decreases (21 ) (8 ) Balance, December 31, 2016 $ 84 $ — Current year increases 2 — Decrease for lapse in statute (6 ) — Balance, December 31, 2017 $ 80 $ — FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the federal income tax return. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2017 , 2016 , and 2015 was not material. For the years ended December 31, 2017 and 2016 , the cumulative net interest payable recorded by FirstEnergy was not material. General Taxes General tax expense for 2017 , 2016 and 2015 , is summarized as follows: 2017 2016 2015 (In millions) FirstEnergy KWH excise $ 188 $ 196 $ 193 State gross receipts 204 212 224 Real and personal property 486 472 410 Social security and unemployment 131 127 119 Other 34 35 32 Total general taxes $ 1,043 $ 1,042 $ 978 FES State gross receipts $ 20 $ 28 $ 44 Real and personal property 27 42 36 Social security and unemployment 11 15 16 Other — 3 2 Total general taxes $ 58 $ 88 $ 98 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2017 | |
Leases [Abstract] | |
Leases | LEASES FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases. In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years, which expired in 2016 for Perry Unit 1 and in 2017 for Beaver Valley Unit 2. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and entered into similar operating leases for lease terms of approximately 30 years, which expired in 2017. In 2007, FG completed a sale and leaseback transaction for its 93.83% undivided interest in Bruce Mansfield Unit 1 and entered into operating leases for basic lease terms of approximately 33 years, expiring in 2040. FES has unconditionally and irrevocably guaranteed all of FG’s obligations under each of the leases. As of December 31, 2017 , FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. On May 23, 2016, NG completed the purchase of the 3.75% lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 for $50 million . In addition, the Perry Unit 1 leases expired in accordance with their terms on May 30, 2016, resulting in NG being the sole owner of Perry Unit 1 and entitled to 100% of the unit's output. On June 1, 2017, NG completed the purchase of the 2.60% lessor equity interests of the remaining non-affiliated leasehold interests in Beaver Valley Unit 2 for $38 million . In addition, the Beaver Valley Unit 2 leases expired in accordance with their terms on June 1, 2017, resulting in NG being the sole owner of Beaver Valley Unit 2. Operating lease expense for 2017 , 2016 and 2015 , is summarized as follows: (In millions) 2017 2016 2015 FirstEnergy $ 158 $ 168 $ 174 FES $ 93 $ 94 $ 94 The future minimum capital lease payments as of December 31, 2017 are as follows: Capital Leases FirstEnergy FES (In millions) 2018 $ 28 $ 2 2019 23 — 2020 18 — 2021 15 — 2022 13 — Years thereafter 20 — Total minimum lease payments 117 2 Interest portion (26 ) — Present value of net minimum lease payments 91 2 Less current portion 24 2 Noncurrent portion $ 67 $ — The future minimum operating lease payments as of December 31, 2017 , are as follows: Operating Leases FirstEnergy FES (In millions) 2018 $ 146 $ 101 2019 128 97 2020 102 68 2021 124 93 2022 111 91 Years thereafter 1,263 1,131 Total minimum lease payments $ 1,874 $ 1,581 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
INTANGIBLE ASSETS | INTANGIBLE ASSETS As of December 31, 2017 , intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2017 2018 2019 2020 2021 2022 Thereafter NUG contracts (1) $ 124 $ 36 $ 88 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 63 OVEC 8 3 5 1 — 1 — — — 4 Coal contracts (2) 102 94 8 4 3 3 2 — — — FES customer contracts 148 144 4 5 3 1 — — — — $ 382 $ 277 $ 105 $ 15 $ 11 $ 10 $ 7 $ 5 $ 5 $ 67 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entities [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability company SPEs which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2017 and December 31, 2016 , $315 million and $339 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, which were paid in full at maturity on June 5, 2017. Additionally, in August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2017 and December 31, 2016 , $56 million and $85 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The limited liability company SPEs own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2017 and December 31, 2016 , $383 million and $406 million of the environmental control bonds were outstanding, respectively. FES does not have any consolidated VIEs. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding. As discussed in Note 16, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's term loan facility, which has an outstanding principal balance of $275 million . Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of December 31, 2017, the carrying value of the equity method investment was $ 17 million . • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 12 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $112 million and $108 million , respectively, during the years ended December 31, 2017 and 2016 . • Sale and Leaseback Transactions - FES has obligations that are not included on its Consolidated Balance Sheet related to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement, which are satisfied through operating lease payments. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangements. FES is exposed to losses under the Bruce Mansfield Unit 1 sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses FirstEnergy's net exposure to loss based upon the casualty value provisions as of December 31, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy (1) $ 1,083 $ 862 $ 221 (1) All amounts are associated with FES. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 11, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2017 , from those used as of December 31, 2016 . The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the years ended December 31, 2017 and 2016 . The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,196 $ — $ 1,196 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 33 — 33 10 200 — 210 Derivative assets - FTRs — — 4 4 — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 1,104 — — 1,104 925 — — 925 Foreign government debt securities — 88 — 88 — 78 — 78 U.S. government debt securities — 154 — 154 — 161 — 161 U.S. state debt securities — 276 — 276 — 246 — 246 Other (3) 589 135 — 724 199 123 — 322 Total assets $ 1,693 $ 1,882 $ 4 $ 3,579 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (27 ) $ — $ (27 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (79 ) (79 ) — — (108 ) (108 ) Total liabilities $ — $ (27 ) $ (80 ) $ (107 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,693 $ 1,855 $ (76 ) $ 3,472 $ 1,128 $ 1,937 $ (106 ) $ 2,959 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(8) million and $(3) million as of December 31, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and December 31, 2016 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2016 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) 2 (17 ) (15 ) (6 ) (4 ) (10 ) Purchases — — — 16 (7 ) 9 Settlements (2 ) 46 44 (11 ) 18 7 December 31, 2016 Balance $ 1 $ (108 ) $ (107 ) $ 7 $ (6 ) $ 1 Unrealized gain (loss) — (10 ) (10 ) 1 (2 ) (1 ) Purchases — — — 4 (1 ) 3 Settlements (1 ) 39 38 (8 ) 8 — December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 4 $ (1 ) $ 3 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices ($4.60) to $5.40 $0.70 Dollars/MWH NUG Contracts $ (79 ) Model Generation 400 to 2,099,000 $30.70 to $32.00 426,000 $30.70 MWH FES Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 720 $ — $ 720 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 33 — 33 10 200 — 210 Derivative assets - FTRs — — 1 1 — — 4 4 Equity securities (1) 810 — — 810 634 — — 634 Foreign government debt securities — 65 — 65 — 58 — 58 U.S. government debt securities — 133 — 133 — 48 — 48 U.S. state debt securities — 29 — 29 — 3 — 3 Other (2) 1 96 — 97 2 81 — 83 Total assets $ 811 $ 1,076 $ 1 $ 1,888 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (23 ) $ — $ (23 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (5 ) (5 ) Total liabilities $ — $ (23 ) $ (1 ) $ (24 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 811 $ 1,053 $ — $ 1,864 $ 640 $ 998 $ (1 ) $ 1,637 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $3 million and $2 million as of December 31, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and December 31, 2016 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2016 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (1 ) Unrealized loss — (1 ) (1 ) Purchases 1 (1 ) — Settlements (4 ) 6 2 December 31, 2017 Balance $ 1 $ (1 ) $ — Level 3 Quantitative Information The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ — Model RTO auction clearing prices ($4.60) to $3.30 $0.10 Dollars/MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES, OE and TE are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 and the expiration of the leases, OE and TE transferred NDT assets of $189 million associated with their leasehold interests to NG. See Note 14, "Asset Retirement Obligations," for additional information. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. AFS Securities FirstEnergy holds debt and equity securities within its NDT and nuclear fuel disposal trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes. The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2017 and December 31, 2016 : December 31, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,707 $ 31 $ 1,738 $ 1,735 $ 38 $ 1,773 FES 950 20 970 847 27 874 Equity securities FirstEnergy $ 949 $ 155 $ 1,104 $ 822 $ 103 $ 925 FES 695 115 810 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $87 million ; FES - $76 million . (2) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 million . Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three years ended December 31, 2017 , 2016 and 2015 were as follows: December 31, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,170 $ 330 $ (253 ) $ (13 ) $ 98 FES 940 256 (195 ) (13 ) 59 December 31, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,678 $ 170 $ (121 ) $ (21 ) $ 100 FES 717 117 (69 ) (19 ) 56 December 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,534 $ 209 $ (191 ) $ (102 ) $ 101 FES 733 158 (134 ) (90 ) 57 Held-To-Maturity Securities Unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of December 31, 2017 and December 31, 2016 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $255 million as of December 31, 2017 and $266 million as of December 31, 2016 , are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts: December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 22,261 $ 23,038 $ 19,885 $ 19,829 FES 2,836 1,487 3,000 1,555 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2017 and December 31, 2016 . |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $10 million and $12 million as of December 31, 2017 and December 31, 2016 , respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Net unamortized losses to be amortized to income during the next twelve months are not material. FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $25 million (FES $3 million ) and $33 million (FES $3 million ) as of December 31, 2017 and December 31, 2016 , respectively. Unamortized losses expected to be amortized to interest expense during the next twelve months are not material. Refer to Note 3, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the years ended December 31, 2017 and 2016 . As of December 31, 2017 and December 31, 2016 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of December 31, 2017 and December 31, 2016 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $3 million and $10 million as of December 31, 2017 and December 31, 2016 , respectively. During the next twelve months, approximately $2 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $7 million and $10 million during the years ended December 31, 2017 and 2016 , respectively. As of December 31, 2017 and December 31, 2016 , no commodity or interest rate derivatives were designated as fair value hedges. Commodity Derivatives FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting. Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas primarily for use in FirstEnergy’s combustion turbine units. Derivative instruments are not used in quantities greater than forecasted needs. As of December 31, 2017 , FirstEnergy's net asset position under commodity derivative contracts was not material. Under these commodity derivative contracts, FES posted $1 million of collateral. Based on commodity derivative contracts held as of December 31, 2017 , an increase in commodity prices of 10% would decrease net income by approximately $6 million (FES $4 million ) during the next twelve months. NUGs As of December 31, 2017 , FirstEnergy's net liability position under NUG contracts was $79 million representing contracts held at JCP&L and PN. Changes in the market value of NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. FTRs As of December 31, 2017 , FirstEnergy's and FES' net position associated with FTRs was not material. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to PJM, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s Utilities are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Other Commodity Contracts $ 33 $ 133 Commodity Contracts $ (27 ) $ (72 ) FTRs 4 7 FTRs (1 ) (6 ) 37 140 (28 ) (78 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (79 ) (108 ) Commodity Contracts — 77 Noncurrent Liabilities - Other FTRs — — Commodity Contracts — (52 ) NUGs (1) — 1 FTRs — — — 78 (79 ) (160 ) Derivative Assets $ 37 $ 218 Derivative Liabilities $ (107 ) $ (238 ) (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. FES records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FES' Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 33 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs 1 4 FTRs (1 ) (5 ) 34 137 (24 ) (77 ) Deferred Charges and Other Assets - Derivatives Noncurrent Liabilities - Other Commodity Contracts — 77 Commodity Contracts — (52 ) — 77 — (52 ) Derivative Assets $ 34 $ 214 Derivative Liabilities $ (24 ) $ (129 ) FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 4 (1 ) — 3 $ 37 $ (20 ) $ — $ 17 Derivative Liabilities Commodity contracts $ (27 ) $ 19 $ 3 $ (5 ) FTRs (1 ) 1 — — NUG contracts (79 ) — — (79 ) $ (107 ) $ 20 $ 3 $ (84 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 ) The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 1 (1 ) — — $ 34 $ (20 ) $ — $ 14 Derivative Liabilities Commodity contracts $ (23 ) $ 19 $ — $ (4 ) FTRs (1 ) 1 — — $ (24 ) $ 20 $ — $ (4 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 9 — 9 MWH NUGs 2 — 2 MWH The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 5 — 5 MWH The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during 2017 , 2016 and 2015 are summarized in the following tables: Year Ended December 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (82 ) $ 1 $ (81 ) Realized Gain (Loss) Reclassified to: Revenues $ 54 $ (4 ) $ 50 Purchased Power Expense (17 ) — (17 ) Other Operating Expense — (14 ) (14 ) Fuel Expense 5 — 5 Year Ended December 31 Commodity FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (14 ) $ 5 $ (9 ) Realized Gain (Loss) Reclassified to: Revenues $ 210 $ 8 $ 218 Purchased Power Expense (131 ) — (131 ) Other Operating Expense — (35 ) (35 ) Fuel Expense (8 ) — (8 ) Year Ended December 31 Commodity FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 93 $ (20 ) $ 73 Realized Gain (Loss) Reclassified to: Revenues $ 111 $ 50 $ 161 Purchased Power Expense (130 ) — (130 ) Other Operating Expense — (49 ) (49 ) Fuel Expense (34 ) — (34 ) The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during 2017 , 2016 and 2015 are summarized in the following tables: Year Ended December 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (79 ) $ 1 $ (78 ) Realized Gain (Loss) Reclassified to: Revenues $ 54 $ (4 ) $ 50 Purchased Power Expense (17 ) — (17 ) Other Operating Expense — (14 ) (14 ) Year Ended December 31 Commodity FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (14 ) $ 5 $ (9 ) Realized Gain (Loss) Reclassified to: Revenues $ 210 $ 8 $ 218 Purchased Power Expense (131 ) — (131 ) Other Operating Expense — (35 ) (35 ) Year Ended December 31 Commodity FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 93 $ (19 ) $ 74 Realized Gain (Loss) Reclassified to: Revenues $ 111 $ 49 $ 160 Purchased Power Expense (130 ) — (130 ) Other Operating Expense — (49 ) (49 ) The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2017 and 2016 . Changes in the value of these contracts are deferred for future recovery from (or credit to) customers: Year Ended December 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (9 ) (1 ) (10 ) Purchases — 3 3 Settlements 37 (1 ) 36 Outstanding net asset (liability) as of December 31, 2017 $ (79 ) $ 3 $ (76 ) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (15 ) (3 ) (18 ) Purchases — 4 4 Settlements 44 — 44 Outstanding net asset (liability) as of December 31, 2016 $ (107 ) $ 2 $ (105 ) |
Capitalization
Capitalization | 12 Months Ended |
Dec. 31, 2017 | |
Capitalization, Long-term Debt and Equity [Abstract] | |
Capitalization | CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2017 , FirstEnergy had an accumulated deficit of $(6.3) billion . Dividends declared in 2017 and 2016 were $1.44 per share, which included dividends of $0.36 per share paid in the first, second, third and fourth quarters. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors. On January 16, 2018 , the Board of Directors declared a quarterly dividend of $0.36 per share to be paid from other paid-in-capital in the first quarter of 2018 . In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35% . In addition, TrAIL and AGC have authorization from FERC to pay cash dividends to their respective parents from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 45% . The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FirstEnergy as of December 31, 2017 . Stock Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the Company. See Note 21, "Subsequent Events," for additional information related to the equity issuances. FE issued approximately 3.0 million shares of common stock in 2017, 2.7 million shares of common stock in 2016 and 2.5 million shares of common stock in 2015 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On December 13, 2016, FE contributed 16,097,875 newly issued shares of its common stock to its qualified pension plan in a private placement transaction. These shares were valued at approximately $500 million in the aggregate, and were issued to satisfy a portion of FirstEnergy’s future pension funding obligations. The independent fiduciary representing the pension plan with respect to the equity contribution fully liquidated the FE common stock by January 31, 2017. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2017 , as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FirstEnergy 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par As of December 31, 2017 and 2016 , there were no preferred or preference shares outstanding. See Note 21, "Subsequent Events," for additional information related to preferred stock outstanding. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2017 and 2016 : As of December 31, 2017 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2017 2016 FirstEnergy: FMBs and secured notes - fixed rate 2018 - 2056 1.726% - 9.740% $ 5,446 $ 5,623 Secured notes - variable rate 2019 4.500% 9 10 Total FMBs and secured notes 5,455 5,633 Unsecured notes - fixed rate 2018 - 2047 2.550% - 7.700% 15,370 13,058 Unsecured notes - variable rate 2020 - 2021 3.227% 1,450 1,200 Total unsecured notes 16,820 14,258 Capital lease obligations 91 104 Unamortized debt discounts (42 ) (25 ) Unamortized debt issuance costs (113 ) (87 ) Unamortized fair value adjustments (14 ) (6 ) Currently payable long-term debt (1,082 ) (1,685 ) Total long-term debt and other long-term obligations $ 21,115 $ 18,192 FES: Secured notes - fixed rate 2018 - 2047 4.250% - 5.625% $ 612 $ 617 Secured notes - variable rate 2019 4.500% 9 10 Total secured notes 621 627 Unsecured notes - fixed rate 2019 - 2041 2.550% - 6.800% 2,215 2,373 Capital lease obligations 2 8 Unamortized debt discounts (1 ) (1 ) Unamortized debt issuance costs (14 ) (15 ) Currently payable long-term debt (524 ) (179 ) Total long-term debt and other long-term obligations $ 2,299 $ 2,813 On March 1, 2017, FG retired $28 million of PCRBs at maturity. On March 15, 2017, MP retired $150 million of FMBs at maturity. On April 3, 2017, CEI retired $130 million of 5.70% senior notes at maturity. On May 16, 2017, MP issued $250 million of 3.55% FMBs due 2027. Proceeds received from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. On June 1, 2017, FG repurchased approximately $130 million of PCRBs, which were subject to a mandatory put on such date. FG is currently holding these PCRBs indefinitely. On June 1, 2017, JCP&L retired $250 million of 5.65% senior notes at maturity. On June 21, 2017, FE issued the aggregate principal amount of $3.0 billion of its senior notes in three series: $500 million of 2.85% notes due 2022; $1.5 billion of 3.90% notes due 2027; and $1.0 billion of 4.85% notes due 2047. Proceeds from the issuance of the notes were used: (i) to redeem $650 million of FE's 2.75% notes due in 2018 on July 25, 2017, and (ii) for general corporate purposes, including the repayment of short-term borrowings under the FE Facility. On August 31, 2017, ATSI issued $150 million of 3.66% senior unsecured notes maturing in 2032. Proceeds from the issuance of the notes were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for working capital needs and other general business purposes. On September 8, 2017, PN issued $300 million of 3.25% senior notes maturing in 2028. Proceeds from the issuance of the notes were used to repay short-term borrowings that were used to repay at maturity $300 million of PN's 6.05% senior notes due September 1, 2017. On September 15, 2017, WP issued $100 million of 4.09% FMBs due 2047. Proceeds from the issuance of the FMBs were used: (i) to repay short-term borrowings, (ii) to fund capital expenditures and (iii) for other general business purposes. On October 5, 2017, CEI issued $350 million of 3.50% senior notes maturing in 2028. Proceeds from the issuance of the notes were used: (i) to refinance existing indebtedness, including $300 million of 7.88% FMBs due November 1, 2017, and borrowings outstanding under FirstEnergy's regulated utility money pool and the Facility, (ii) to fund capital expenditures and (iii) for working capital and other general business purposes. On December 15, 2017, WP issued $275 million of 4.14% FMBs maturing in 2047. Proceeds from the issuance of the FMBs were used to repay at maturity $275 million of WP's 5.95% FMBs due December 15, 2017. See Note 7, "Leases," for additional information related to capital leases. Securitized Bonds Environmental Control Bonds The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. As of December 31, 2017 and 2016 , $383 million and $406 million of environmental control bonds were outstanding, respectively. Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include transition bonds issued by JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. The proceeds were used to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station and to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. As of December 31, 2017 and 2016 , $56 million and $85 million of the transition bonds were outstanding, respectively. Phase-In Recovery Bonds In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. As of December 31, 2017 and 2016 , $315 million and $339 million of the phase-in recovery bonds were outstanding, respectively. See Note 9, "Variable Interest Entities," for additional information on securitized bonds. Other Long-term Debt The Ohio Companies, Penn, FG and NG each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2017 , the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2017 . PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year FirstEnergy FES (In millions) 2018 $ 1,051 $ 515 2019 1,267 323 2020 1,281 667 2021 2,032 674 2022 1,428 284 Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. The following table classifies these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs. Year FirstEnergy FES (In millions) 2018 $ 375 $ 375 2019 232 232 2020 490 490 2021 342 342 2022 284 284 Debt Covenant Default Provisions FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2017 , FirstEnergy and FES remain in compliance with all debt covenant provisions. Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding FES and AES, default under another financing arrangement in excess of a certain principal amount, typically $100 million . Although such defaults by any of the Utilities, ATSI or TrAIL would generally cross-default FE financing arrangements containing these provisions, defaults by any of AE Supply, FES, FG or NG would generally not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE, FG, NG or the Utilities. |
Short-Term Borrowings and Bank
Short-Term Borrowings and Bank Lines of Credit | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT | SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FE and the Utilities and FET and its subsidiaries participate in two separate five-year syndicated revolving credit facilities with aggregate commitments of $5.0 billion (Facilities), which are available through December 6, 2021. FE and the Utilities and FET and its subsidiaries may use borrowings under their Facilities for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. Generally, borrowings under each of the Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy had $300 million and $2,675 million of short-term borrowings as of December 31, 2017 and 2016 , respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2018 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2021 $ 4,000 $ 3,740 FET (2) Revolving December 2021 1,000 1,000 Subtotal $ 5,000 $ 4,740 Cash — 358 Total $ 5,000 $ 5,098 (1) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. (2) Includes FET, ATSI, MAIT and TrAIL. FES had $105 million and $101 million of short-term borrowings as of December 31, 2017 and December 31, 2016, respectively. Of such amounts, $102 million and $101 million, respectively, represents a currently outstanding promissory note due April 2, 2018, payable to AE Supply with any additional short-term borrowings representing borrowings under an unregulated companies' money pool, which also includes FE, FET, FEV and certain other unregulated subsidiaries of FE, but excludes FENOC, FES and its subsidiaries. In addition to FES' access to a separate unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, FES' available liquidity as of January 31, 2018, was as follows: Type Commitment Available Liquidity (In millions) Two-year secured credit facility with FE $ 500 $ 500 Cash — 1 $ 500 $ 501 The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations , as of January 31, 2018 : Borrower FirstEnergy Revolving Credit Facility Sub-Limits FET Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 4,000 $ — $ — (1) FET — 1,000 — (1) OE 500 — 500 (2) CEI 500 — 500 (2) TE 300 — 300 (2) JCP&L 600 — 500 (2) ME 300 — 500 (2) PN 300 — 300 (2) WP 200 — 200 (2) MP 500 — 500 (2) PE 150 — 150 (2) ATSI — 500 500 (2) Penn 50 — 100 (2) TrAIL — 400 400 (2) MAIT — 400 400 (2) (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool. $250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds, other than the FET facility, which is based on its subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million . As of December 31, 2017, the borrowers were in compliance with the applicable debt-to-total-capitalization covenants, as well as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective Facilities. Separately, in December 2016, FE and FES entered into a two-year secured credit facility in which FE provides a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. So long as FES remains in an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, the $500 million secured line of credit provides FES the needed liquidity in order for FES to, among other things, satisfy its nuclear support obligation to NG in the event of extraordinary circumstances with respect to its nuclear facilities. The new facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million). Additionally, FES maintains access to an unregulated companies' money pool, which includes FE, FES' subsidiaries and FENOC, and continues to conduct its ordinary course of business under that money pool in lieu of borrowing under the new facility. Term Loans As of December 31, 2017, FE had a $1.2 billion variable rate syndicated term loan and two separate $125 million term loans. On January 22, 2018, FE repaid these term loans in full using the proceeds from the $2.5 billion equity investment. FirstEnergy Money Pools FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries of FE participating in a money pool and FE (as a lender only), FENOC, FES and its subsidiaries participating in a similar money pool. FESC administers these money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2017 was 1.48% per annum for the regulated companies’ money pool and 2.30% per annum for the unregulated companies’ money pools. As discussed above, FES currently maintains access to its unregulated companies' money pool in lieu of borrowing under its $500 million secured line of credit. FE expects to provide ongoing liquidity to FES within such unregulated companies' money pool through March 2018. As of December 31, 2017, FES, its subsidiaries, and FENOC had no borrowings in the aggregate under the unregulated companies' money pool. Weighted Average Interest Rates The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2017 and 2016 , were as follows: 2017 2016 FirstEnergy 3.24 % 2.47 % |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities and totaled $1,758 million and $713 million as of December 31, 2017 and 2016 , respectively. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. FirstEnergy and FES maintain NDTs that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2017 and 2016 were as follows: 2017 2016 (In millions) FirstEnergy $ 2,678 $ 2,514 FES $ 1,856 $ 1,552 The following table summarizes the changes to the ARO balances during 2017 and 2016 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2016 $ 1,410 $ 831 Liabilities settled (27 ) (18 ) Accretion 95 56 Liabilities Incurred 4 32 Balance, December 31, 2016 $ 1,482 $ 901 Changes in timing of estimated cash flows (1) 944 944 Liabilities settled (12 ) (11 ) Accretion 101 62 Liabilities Incurred — 49 Balance, December 31, 2017 $ 2,515 $ 1,945 (1) See Note 2, "Asset Sales and Impairments" for further discussion. During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 sale leaseback and the expiration of the leases, OE and TE transferred the ARO (included within the FES liabilities incurred above) and NDT assets associated with their leasehold interests to NG, with the difference of $73 million credited to the common stock of FES. During 2016, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in Perry Unit 1, OE transferred the ARO (included within the FES liabilities incurred above) and related NDT assets associated with the leasehold interest to NG with the difference of $28 million credited to the common stock of FES. As of June 30, 2016, NG owns 100% of Perry Unit 1. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs. |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
REGULATORY MATTERS | REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates. In addition, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility. Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings which have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory impacts resulting from the Tax Act. MARYLAND PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's current plan for 2016, and increasing 0.2% per year thereafter to reach 2% . The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. The costs of PE's 2015-2017 plan approved by the MDPSC in December 2014 were approximately $60 million . PE filed its 2018-2020 EmPOWER Maryland plan on August 31, 2017. The 2018-2020 plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three -year period. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. PE recovers program costs subject to a five -year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. Comments were filed and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. On January 19, 2018, PE filed a joint petition, along with other utility companies, work group stakeholders, and the MDPSC electric vehicle work group leader, to implement a statewide electric vehicle portfolio. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and directed that comments be filed by March 16, 2018. On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE must track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers and proposed to file a base rate case in the third quarter of 2018 where the benefits from the effects of the Tax Act will be realized by customers through a lower rate increase than would otherwise be necessary. NEW JERSEY JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third-party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. In addition, on January 25, 2017 , the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five -year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014 Generic Order. The proposed rule was published in the NJ Register on January 16, 2018, and was republished on February 6, 2018, to correct an error. Interested parties have sixty days to comment on the proposed rulemaking. At the December 19, 2017 NJBPU public meeting, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. JCP&L expects to make a filing in 2018. On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. JCP&L must track and apply regulatory accounting treatment for the impacts effective January 1, 2018, and file a petition with the NJBPU by March 2, 2018, regarding the expected impacts of the Tax Act on JCP&L’s expenses and revenues and how the effects will be passed through to its customers. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two -year extension. Rider DMR will be grossed up for federal income taxes, resulting in an approved amount of approximately $204 million annually. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three -year term but the exclusion will be reconsidered upon application for a potential two -year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. Other material terms of ESP IV include: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016, and remains pending); (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates (which filing was made on April 3, 2017, and remains pending). Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. On September 15, 2017, the Ohio Companies filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 2017, the Sierra Club and the Ohio Manufacturer's Association Energy Group filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three -year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the filed Stipulation and Recommendation with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers as reported on FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (3.5%), and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million , plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against prohibiting retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers. On January 13, 2016, the PUCO granted reconsideration for further consideration of the matters specified in the applications for rehearing. On March 29, 2017, the PUCO issued a Second Entry on Rehearing that granted, in part, the applications for rehearing filed by FES and other parties, finding that the PUCO’s guidelines regarding fixed-price contracts should not apply to large mercantile customers. This finding changes the original order, which applied the guidelines to all customers, including mercantile customers. The PUCO also reaffirmed several provisions of the original order, including that the fixed-price guidelines only apply on a going-forward basis and not to existing contracts and that regulatory-out clauses in contracts are permissible. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery no later than May 2, 2018, so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits. On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies must establish a regulatory liability, effective January 1, 2018, for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. PENNSYLVANIA The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24 -month energy contracts, as well as one RFP for 2 -year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW . A hearing has been scheduled for April 10-11, 2018, and the PPUC is expected to issue a final order on these DSPs by mid-September 2018. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million , are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. The LTIIPs estimated costs for the remaining period of 2018 to 2020, as modified, are: WP $50.1 million ; PN $44.8 million ; Penn $33.2 million ; and ME $51.3 million . On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016, which is pending PPUC approval. The ADIT issue is subject to further litigation and a hearing was held on May 12, 2017. On August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. If the decision is approved by the PPUC, the impact is not expected to be material to FirstEnergy. The Pennsylvania Companies filed exceptions to the decision on September 20, 2017, and reply exceptions on October 2, 2017. On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. By March 9, 2018, the Pennsylvania Companies must submit information to the PPUC to calculate the net effect of the Tax Act on income tax expense and rate base, and comments addressing whether rates should be adjusted to reflect the tax rate changes, and if so, how and when such modifications should take effect. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. On September 23, 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, which includes three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, which was approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP. The costs for the Phase II program are expected to be $10.4 million and are eligible for recovery through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy. On December 9, 2016, the WVPSC approved the annual ENEC case for MP and PE as reflected in a unanimous settlement by the parties to the proceeding, resulting in an increase in the ENEC rate of $25 million annually beginning January 1, 2017. In addition, ENEC rates will be maintained at the same level for a two year period. On December 30, 2015, MP and PE filed an IRP with the WVPSC identifying a capacity shortfall starting in 2016 and exceeding 700 MWs by 2020 and 850 MWs by 2027. On June 3, 2016, the WVPSC accepted the IRP. On December 16, 2016, MP issued an RFP to address its generation shortfall, along with issuing a second RFP to sell its interest in Bath County. Bids were received by an independent evaluator in February 2017 for both RFPs. AE Supply was the winning bidder of the RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station ( 1,300 MWs) for approximately $195 million , subject to customary and other closing conditions, including regulatory approvals . In addition, on March 7, 2017, MP and PE filed an application with the WVPSC and MP and AE Supply filed an application with FERC requesting authorization for such purchase. Various intervenors filed protests challenging the RFP and requesting FERC deny the application, set it for hearing to allow discovery into the RFP process, or delay an order pending the conclusion of the WVPSC proceeding. On January 12, 2018, FERC issued an order denying authorization for the transaction, holding that MP and AE Supply did not demonstrate that the sale was consistent with the public interest and the transaction did not fall within the safe harbors for meeting FERC’s affiliate cross-subsidization analysis. In the order FERC also revised and clarified certain details of its standards for the review of transactions resulting from competitive solicitations, and concluded that MP’s RFP did not meet the revised and clarified standards. FERC allowed that MP may submit a future application for a transaction resulting from a new RFP. The WVPSC issued its order on January 26, 2018, denying the petition as filed but granting the transfer of Pleasants Power Station under certain conditions, which included MP assuming significant commodity risk. MP, PE and AE Supply have determined not to seek rehearing at FERC in light of the adverse decisions at FERC and the WVPSC. Based on the FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement. With respect to the Bath County RFP, MP does not plan to move forward with that sale of its ownership interest. In the future, MP may re-evaluate its options with respect to its interest in Bath County. On September 1, 2017, MP and PE filed with the WVPSC for a reconciliation of their VMS to confirm that rate recovery matches VMP costs and for a regular review of that program. MP and PE proposed a $15 million annual decrease in VMS rates effective January 1, 2018, and an additional $15 million decrease in rates for 2019. This is an overall decrease in total revenue and average rates of 1% . On December 15, 2017, the WVPSC issued an order adopting a unanimous settlement without modification. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, |
Commitments, Guarantees and Con
Commitments, Guarantees and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES | COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $13.4 billion (assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $450 million ; and (ii) $13.0 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $127 million (but not more than $19 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s and NG's maximum potential assessment under these provisions would be $509 million per incident but not more than $76 million in any one year for each incident. In addition to the public liability insurance provided pursuant to the Price-Anderson Act, NG purchases insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. NG is a Member Insured of NEIL, which provides coverage for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. NG, as the Member Insured and each entity with an insurable interest, purchases policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion for replacement power costs incurred during an outage after an initial 12-week waiting period. NG, as the Member Insured and each entity with an insurable interest, is insured under property damage insurance provided by NEIL. Under these arrangements, up to $2.75 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. Member Insureds of NEIL pay annual premiums and are subject to retrospective premium assessments if losses exceed the accumulated funds available to the insurer. NG purchases insurance through NEIL that will pay its obligation in the event a retrospective premium call is made by NEIL, subject to the terms of the policy. FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of NG's plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs. The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.06 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition so as to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds. GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2017 , outstanding guarantees and other assurances aggregated approximately $3.8 billion , consisting of parental guarantees ( $1.2 billion ), subsidiaries' guarantees ( $1.8 billion ), other guarantees ($ 275 million ) and other assurances ( $459 million ). Of the aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG. Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on CES' power portfolio exposure as of December 31, 2017 , FES has posted collateral of $123 million and AE Supply has posted collateral of $4 million . The Regulated Distribution Segment has posted collateral of $4 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2017 : Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 4 $ 1 $ — $ — $ 5 Upon Further Downgrade — — 41 — 41 Surety Bonds (Collateralized Amount) (1) 16 1 107 237 361 Total Exposure from Contractual Obligations $ 20 $ 2 $ 148 $ 237 $ 407 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of December 31, 2017 , FES has $2 million of collateral posted with its affiliates. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding's outstanding principal balance is $275 million . In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may impact its business, results of operations, cash flows and financial condition. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with SO 2 and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls, generating more electricity from lower or non-emitting plants and/or using emission allowances. CSAPR requires reductions of NOx and SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but the EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017. The EPA missed the October 1, 2017, deadline and has not yet promulgated the attainment designations. States will then have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. On December 5, 2017, fourteen states and the District of Columbia filed complaints in the U.S. District Court of Northern California seeking an order that the EPA promulgate the attainment designations for the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition seeks a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. On September 27, 2016, the EPA extended the time frame for acting on the State of Delaware's CAA Section 126 petition by six months to April 7, 2017, but has not taken any further action. On January 2, 2018, the State of Delaware provided the EPA a notice required at least 60 days prior to filing a suit seeking to compel the EPA to either approve or deny the August 2016 CAA Section 126 petition . In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3, Mansfield Unit 1 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition seeks NOx emission rate limits for the 36 EGUs by May 1, 2017. On January 3, 2017, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to July 15, 2017, but has not taken any further action. On September 27, 2017, and October 4, 2017, the State of Maryland and various environmental organizations filed complaints in the U.S. District Court for the District of Maryland seeking an order that the EPA either approve or deny the CAA Section 126 petition of November 16, 2016. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposed emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired EGUs effective in April 2015 with averaging of emissions from multiple units located at a single plant. The majority of FirstEnergy's MATS compliance program and related costs have been completed. On August 3, 2015, FG, a wholly owned subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure event that excuses FG’s performance under its coal transportation contract with these parties. Specifically, the dispute arose from a contract for the transportation by BNSF and CSX of a minimum of 3.5 million tons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, all plants covered by this contract were deactivated by April 16, 2015. Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages under the contract through 2025. On May 31, 2016, the parties agreed to a stipulation that if FG’s force majeure defense is determined to be wholly or partially invalid, liquidated damages are the sole remedy available to BNSF and CSX. The arbitration panel consolidated the claims and held a hearing in November and December 2016. On April 12, 2017, the arbitration panel ruled on liability in favor of BNSF and CSX. In the liability award, the panel found, among other things, that FG’s demand for declaratory judgment that force majeure excused FG’s performance was denied, that FG breached and repudiated the coal transportation contract and that the panel retains jurisdiction of claims for liquidated damages for the years 2015-2025. On May 1, 2017, FE and FG and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to this consolidated proceeding on the terms and conditions set forth below. Pursuant to the settlement agreement, FG will pay CSX and BNSF an aggregate amount equal to $109 million , which is payable in three annual installments , the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provides that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. Further, FE and FG, and CSX and BNSF, agreed to release, waive and discharge each other from any further obligations under the claims covered by the settlement agreement upon payment in full of the settlement amount. Until such time, CSX and BNSF will retain the claims covered by the settlement agreement and in the event of a bankruptcy proceeding with respect to FG, to the extent the remaining settlement payments are not paid in full by FG or FE, CSX and BNSF shall be entitled to seek damages for such claims in an amount to be determined by the arbitration panel or otherwise agreed by the parties. On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS which are the counterparties to the coal transportation contract covering the delivery of 2.5 million tons annually through 2025, for FG’s coal-fired Bay Shore Units 2-4, deactivated on September 1, 2012, as a result of the EPA’s MATS and for FG’s W.H. Sammis generating station. The demand for arbitration was submitted to the AAA office in Washington, D.C., against FG alleging, among other things, that FG breached the agreement in 2015 and 2016 and repudiated the agreement for 2017-2025. The counterparties are seeking liquidated damages through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. The arbitration hearing is scheduled for June 2018. The parties have exchanged settlement proposals to resolve all claims related to this proceeding, however, discussions have been terminated and settlement is unlikely. FirstEnergy and FES recorded a pre-tax charge of $116 million in 2017 based on an estimated range of losses regarding the ongoing litigation with respect to this agreement. If the case proceeds to arbitration, the amount of damages owed to BNSF and NS could be materially higher and may cause FES to seek protection under U.S. bankruptcy laws. FG intends to vigorously assert its position in this arbitration proceeding, and if it were ultimately determined that the force majeure provisions or other defenses do not excuse the delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania, alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. AE Supply filed an answer denying any liability related to the termination. On May 1, 2017, the complaint was amended to add FE, FES and FG, although not parties to the underlying contract, as defendants and to seek additional damages based on new claims of fraud, unjust enrichment, promissory estoppel and alter ego. On June 27, 2017, after oral argument, defendants' preliminary objections to the amended complaint were denied. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement will be guaranteed by FE, including the $93 million payment. In September 2007, AE received an NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs. On June 29, 2012, January 31, 2013, March 27, 2013 and October 18, 2016, the EPA issued CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. On December 12, 2014, the EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009. FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss. Climate Change FirstEnergy has established a goal to reduce CO 2 emissions by 90% below 2005 levels by 2045. There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. On June 23, 2014, the U.S. Supreme Court decided that CO 2 or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies. The EPA released its final CPP regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO 2 emissions from existing fossil fuel-fired EGUs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. On January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court . On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020. The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide GHG emissions by 26 to 28 percent below 2005 levels by 2025 and in September 2016, joined in adopting the agreement reached on December 12, 2015, at the United Nations Framework Convention on Climate Change meetings in Paris. The Paris Agreement was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. The CO 2 emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO 2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five -year cycle from 2018 to 2023. The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed (effective upon publication in the Federal Register) all deadlines in the effluent limits rule pending a new rulemaking. Also, on September 18, 2017, the EPA postponed certain compliance deadlines for two years. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, changes in timing and closure plan requirements in the future, including changes resulting from the strategic review at CES, could materially and adversely impact FirstEnergy's and FES' AROs. Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12 -year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, W. Va., and the remainder recycled into drywall by National Gypsum. These beneficial reuse options should be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible pa |
Transactions With Affiliated Co
Transactions With Affiliated Companies | 12 Months Ended |
Dec. 31, 2017 | |
Transactions With Affiliated Companies [Abstract] | |
TRANSACTIONS WITH AFFILIATED COMPANIES | TRANSACTIONS WITH AFFILIATED COMPANIES FES’ operating revenues, operating expenses, investment income and interest expenses include transactions with affiliated companies. These affiliated company transactions include affiliated company power sales agreements between FirstEnergy's competitive and regulated companies, support service billings, including corporate and nuclear facility operational and maintenance support, interest on affiliated company notes including the money pools and other transactions. FirstEnergy's competitive companies at times provide power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provide power to certain affiliates' facilities. The primary affiliated company transactions for FES during the three years ended December 31, 2017 are as follows: FES 2017 2016 2015 (In millions) Revenues: Electric sales to affiliates $ 366 $ 459 $ 666 Other 11 11 14 Expenses: Purchased power from affiliates 201 622 353 Fuel 4 4 1 Support services 775 748 705 Investment Income: Interest income from FE 13 2 2 Interest Expense: Interest expense to affiliates — 5 4 Interest expense to FE 19 2 3 FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FES and the Utilities from FESC and FENOC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC and FENOC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Intercompany transactions are generally settled under commercial terms within thirty days. FES purchases the entire output of the generation facilities owned by FG and NG. Prior to June 1, 2017, FES purchased the output relating to leasehold interests of OE and TE in certain of those facilities that were subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. Prior to April 1, 2016, FES financially purchased the uncommitted output of AE Supply's generation facilities under a PSA. On December 21, 2015, FES agreed under a PSA to physically purchase all the output of AE Supply's generation facilities effective April 1, 2016. FES and AE Supply terminated the PSA effective on April 1, 2017. Additionally, FES and AE Supply are parties to an affiliated commodity transfer agreement in which AE Supply sells coal to FES in accordance with the terms and conditions set forth under the respective coal purchase agreements that AE Supply has with a third party. During 2017 , AE Supply sold 0.4 million tons of coal for $15 million to FES at market prices. During 2016 and 2015 , AE Supply sold 1.5 million and 1.2 million tons of coal to FES, respectively, at its cost of $80 million and $63 million , respectively. During 2017 and 2016, FES sold 1.1 million and 0.4 million tons of coal to AE Supply, respectively, for $41 million and $16 million , respectively, at market prices. Also during 2016, FES sold 0.7 million tons of coal to MP for $31 million at market prices. FES had no intercompany sales of coal to AE Supply or MP in 2015. FES and the Utilities are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 6, "Taxes"). |
Supplemental Guarantor Informat
Supplemental Guarantor Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Guarantor Information [Abstract] | |
SUPPLEMENTAL GUARANTOR INFORMATION | SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG, a 100% owned subsidiary of FES, completed a sale and leaseback transaction for a 93.83% undivided interest in Bruce Mansfield Unit 1. FG's parent company, FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FG or its parent company, but the notes are secured by, among other things, each lessor trust's undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES' lease guaranty. This transaction is classified as an operating lease for FES and FirstEnergy and as a financing lease for FG. The Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) for the years ended December 31, 2017 , 2016 , and 2015 , Condensed Consolidating Balance Sheets as of December 31, 2017 and December 31, 2016 , and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2017 , 2016 , and 2015 , for the parent and guarantor and non-guarantor subsidiaries are presented below. These statements are provided as FG's parent company fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. Investments in wholly owned subsidiaries are accounted for by the parent company using the equity method. Results of operations for FG and NG are, therefore, reflected in their parent company's investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction. FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 3,037 $ 1,062 $ 1,362 $ (2,363 ) $ 3,098 OPERATING EXPENSES: Fuel — 390 209 — 599 Purchased power from affiliates 2,488 — 76 (2,363 ) 201 Purchased power from non-affiliates 628 — — — 628 Other operating expenses 322 490 653 49 1,514 Pension and OPEB mark-to-market adjustment (12 ) (30 ) 66 — 24 Provision for depreciation 12 32 67 (2 ) 109 General taxes 20 21 17 — 58 Impairment of assets and related charges — — 2,031 — 2,031 Total operating expenses 3,458 903 3,119 (2,316 ) 5,164 OPERATING INCOME (LOSS) (421 ) 159 (1,757 ) (47 ) (2,066 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (1,864 ) 39 113 1,806 94 Miscellaneous income 1 1 5 — 7 Interest expense — affiliates (75 ) (11 ) (1 ) 68 (19 ) Interest expense — other (46 ) (104 ) (44 ) 56 (138 ) Capitalized interest — 2 24 — 26 Total other income (expense) (1,984 ) (73 ) 97 1,930 (30 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (2,405 ) 86 (1,660 ) 1,883 (2,096 ) INCOME TAXES (BENEFITS) (14 ) 360 (78 ) 27 295 NET INCOME (LOSS) $ (2,391 ) $ (274 ) $ (1,582 ) $ 1,856 $ (2,391 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (2,391 ) $ (274 ) $ (1,582 ) $ 1,856 $ (2,391 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (14 ) (13 ) — 13 (14 ) Amortized gain on derivative hedges 2 — — — 2 Change in unrealized gain on available-for-sale securities 30 — 30 (30 ) 30 Other comprehensive income (loss) 18 (13 ) 30 (17 ) 18 Income taxes (benefits) on other comprehensive income (loss) 6 (5 ) 10 (5 ) 6 Other comprehensive income (loss), net of tax 12 (8 ) 20 (12 ) 12 COMPREHENSIVE INCOME (LOSS) $ (2,379 ) $ (282 ) $ (1,562 ) $ 1,844 $ (2,379 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 4,242 $ 1,739 $ 2,004 $ (3,587 ) $ 4,398 OPERATING EXPENSES: Fuel — 582 198 — 780 Purchased power from affiliates 4,024 — 187 (3,587 ) 624 Purchased power from non-affiliates 1,020 — — — 1,020 Other operating expenses 310 286 632 49 1,277 Pension and OPEB mark-to-market adjustment (1 ) (4 ) 53 — 48 Provision for depreciation 13 120 206 (3 ) 336 General taxes 31 30 27 — 88 Impairment of assets and related charges 39 3,937 4,729 (83 ) 8,622 Total operating expenses 5,436 4,951 6,032 (3,624 ) 12,795 OPERATING LOSS (1,194 ) (3,212 ) (4,028 ) 37 (8,397 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (4,585 ) 30 84 4,538 67 Miscellaneous income 4 3 — — 7 Interest expense — affiliates (50 ) (10 ) (4 ) 57 (7 ) Interest expense — other (55 ) (105 ) (44 ) 57 (147 ) Capitalized interest — 8 26 — 34 Total other income (expense) (4,686 ) (74 ) 62 4,652 (46 ) LOSS BEFORE INCOME TAX BENEFITS (5,880 ) (3,286 ) (3,966 ) 4,689 (8,443 ) INCOME TAX BENEFITS (425 ) (1,169 ) (1,429 ) 35 (2,988 ) NET LOSS $ (5,455 ) $ (2,117 ) $ (2,537 ) $ 4,654 $ (5,455 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET LOSS $ (5,455 ) $ (2,117 ) $ (2,537 ) $ 4,654 $ (5,455 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (14 ) (14 ) — 14 (14 ) Amortized gain on derivative hedges — — — — — Change in unrealized gain on available-for-sale securities 52 — 52 (52 ) 52 Other comprehensive income (loss) 38 (14 ) 52 (38 ) 38 Income taxes (benefits) on other comprehensive income (loss) 15 (5 ) 20 (15 ) 15 Other comprehensive income (loss), net of tax 23 (9 ) 32 (23 ) 23 COMPREHENSIVE LOSS $ (5,432 ) $ (2,126 ) $ (2,505 ) $ 4,631 $ (5,432 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 4,824 $ 1,801 $ 2,138 $ (3,758 ) $ 5,005 OPERATING EXPENSES: Fuel — 679 192 — 871 Purchased power from affiliates 3,826 — 285 (3,758 ) 353 Purchased power from non-affiliates 1,684 — — — 1,684 Other operating expenses 378 273 608 49 1,308 Pension and OPEB mark-to-market adjustment (8 ) 10 55 — 57 Provision for depreciation 12 124 191 (3 ) 324 General taxes 45 26 27 — 98 Impairment of assets and related charges 21 2 10 — 33 Total operating expenses 5,958 1,114 1,368 (3,712 ) 4,728 OPERATING INCOME (LOSS) (1,134 ) 687 770 (46 ) 277 OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees 844 17 (5 ) (870 ) (14 ) Miscellaneous income 1 2 — — 3 Interest expense — affiliates (29 ) (8 ) (4 ) 34 (7 ) Interest expense — other (52 ) (104 ) (49 ) 58 (147 ) Capitalized interest — 6 29 — 35 Total other income (expense) 764 (87 ) (29 ) (778 ) (130 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (370 ) 600 741 (824 ) 147 INCOME TAXES (BENEFITS) (452 ) 224 278 15 65 NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (3 ) — — — (3 ) Change in unrealized gain on available-for-sale securities (9 ) — (8 ) 8 (9 ) Other comprehensive loss (18 ) (5 ) (8 ) 13 (18 ) Income tax benefits on other comprehensive loss (7 ) (2 ) (3 ) 5 (7 ) Other comprehensive loss, net of tax (11 ) (3 ) (5 ) 8 (11 ) COMPREHENSIVE INCOME $ 71 $ 373 $ 458 $ (831 ) $ 71 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 1 $ — $ — $ 1 Receivables- Customers 181 — — — 181 Affiliated companies 210 80 260 (326 ) 224 Other 13 8 — — 21 Notes receivable from affiliated companies 366 1,744 1,512 (3,622 ) — Materials and supplies 41 142 — — 183 Derivatives 34 — — — 34 Collateral 105 25 — — 130 Prepaid taxes and other 10 12 — — 22 960 2,012 1,772 (3,948 ) 796 PROPERTY, PLANT AND EQUIPMENT: In service 122 2,646 8 (281 ) 2,495 Less — Accumulated provision for depreciation 65 1,947 — (189 ) 1,823 57 699 8 (92 ) 672 Construction work in progress 3 19 — — 22 60 718 8 (92 ) 694 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,856 — 1,856 Investment in affiliated companies 1,153 — — (1,153 ) — Other — 9 — — 9 1,153 9 1,856 (1,153 ) 1,865 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 267 790 890 (193 ) 1,754 Property taxes — 9 16 — 25 Other 45 310 — 25 380 312 1,109 906 (168 ) 2,159 $ 2,485 $ 3,848 $ 4,542 $ (5,361 ) $ 5,514 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 438 $ 114 $ (28 ) $ 524 Short-term borrowings - affiliated companies 3,325 402 — (3,622 ) 105 Accounts payable- Affiliated companies 320 60 194 (319 ) 255 Other 22 83 — — 105 Accrued taxes 52 12 21 (13 ) 72 Derivatives 22 2 — — 24 Other 44 73 11 41 169 3,785 1,070 340 (3,941 ) 1,254 CAPITALIZATION: Total equity (deficit) (2,070 ) 547 528 (1,075 ) (2,070 ) Long-term debt and other long-term obligations 691 1,666 1,007 (1,065 ) 2,299 (1,379 ) 2,213 1,535 (2,140 ) 229 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 723 723 Retirement benefits 28 125 — — 153 Asset retirement obligations — 187 1,758 — 1,945 Other 51 253 909 (3 ) 1,210 79 565 2,667 720 4,031 $ 2,485 $ 3,848 $ 4,542 $ (5,361 ) $ 5,514 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 213 — — — 213 Affiliated companies 332 315 417 (612 ) 452 Other 17 2 8 — 27 Notes receivable from affiliated companies 501 1,585 1,294 (3,351 ) 29 Materials and supplies 45 142 80 — 267 Derivatives 137 — — — 137 Collateral 157 — — — 157 Prepaid taxes and other 38 24 1 — 63 1,440 2,070 1,800 (3,963 ) 1,347 PROPERTY, PLANT AND EQUIPMENT: In service 120 2,524 4,703 (290 ) 7,057 Less — Accumulated provision for depreciation 52 1,920 4,144 (187 ) 5,929 68 604 559 (103 ) 1,128 Construction work in progress 2 67 358 — 427 70 671 917 (103 ) 1,555 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,552 — 1,552 Investment in affiliated companies 2,923 — — (2,923 ) — Other — 9 1 — 10 2,923 9 1,553 (2,923 ) 1,562 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 395 1,271 883 (270 ) 2,279 Property taxes — 12 28 — 40 Derivatives 77 — — — 77 Other 33 327 — 21 381 505 1,610 911 (249 ) 2,777 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 200 $ 5 $ (26 ) $ 179 Short-term borrowings - affiliated companies 2,969 483 — (3,351 ) 101 Accounts payable- Affiliated companies 743 107 406 (706 ) 550 Other 17 93 — — 110 Accrued taxes 50 48 61 (16 ) 143 Derivatives 71 6 — — 77 Other 56 54 10 36 156 3,906 991 482 (4,063 ) 1,316 CAPITALIZATION: Total equity 218 828 2,006 (2,834 ) 218 Long-term debt and other long-term obligations 691 2,093 1,120 (1,091 ) 2,813 909 2,921 3,126 (3,925 ) 3,031 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 757 757 Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Other 98 88 860 (7 ) 1,039 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (485 ) $ 516 $ 722 $ (26 ) $ 727 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 356 (81 ) — (271 ) 4 Redemptions and Repayments- Long-term debt — (184 ) (5 ) 26 (163 ) Other (1 ) (6 ) — — (7 ) Net cash provided from (used for) financing activities 355 (271 ) (5 ) (245 ) (166 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (2 ) (88 ) (185 ) — (275 ) Nuclear fuel — — (254 ) — (254 ) Sales of investment securities held in trusts — — 940 — 940 Purchases of investment securities held in trusts — — (999 ) — (999 ) Cash Investments (3 ) — — — (3 ) Loans to affiliated companies, net 135 (158 ) (219 ) 271 29 Net cash provided from (used for) investing activities 130 (246 ) (717 ) 271 (562 ) Net change in cash and cash equivalents — (1 ) — — (1 ) Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 1 $ — $ — $ 1 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (842 ) $ 550 $ 1,103 $ (25 ) $ 786 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 186 285 — 471 Short-term borrowings, net 948 94 — (941 ) 101 Redemptions and Repayments- Long-term debt — (224 ) (308 ) 25 (507 ) Other — (7 ) (2 ) — (9 ) Net cash provided from (used for) financing activities 948 49 (25 ) (916 ) 56 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (30 ) (224 ) (292 ) — (546 ) Nuclear fuel — — (232 ) — (232 ) Proceeds from asset sales 9 — — — 9 Sales of investment securities held in trusts — — 717 — 717 Purchases of investment securities held in trusts — — (783 ) — (783 ) Cash investments 10 — — — 10 Loans to affiliated companies, net (95 ) (376 ) (488 ) 941 (18 ) Other — 1 — — 1 Net cash used for investing activities (106 ) (599 ) (1,078 ) 941 (842 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (637 ) $ 552 $ 1,261 $ (24 ) $ 1,152 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 45 296 — 341 Short-term borrowings, net 796 67 — (863 ) — Redemptions and Repayments- Long-term debt (17 ) (70 ) (348 ) 24 (411 ) Short-term borrowings, net — — (28 ) (98 ) (126 ) Common stock dividend payment (70 ) — — — (70 ) Other — (6 ) (1 ) — (7 ) Net cash provided from (used for) financing activities 709 36 (81 ) (937 ) (273 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (5 ) (223 ) (399 ) — (627 ) Nuclear fuel — — (190 ) — (190 ) Proceeds from asset sales 10 3 — — 13 Sales of investment securities held in trusts — — 733 — 733 Purchases of investment securities held in trusts — — (791 ) — (791 ) Cash investments (10 ) — — — (10 ) Loans to affiliated companies, net (67 ) (372 ) (533 ) 961 (11 ) Other — 4 — — 4 Net cash used for investing activities (72 ) (588 ) (1,180 ) 961 (879 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission and CES. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, MAIT (effective January 31, 2017) and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP). The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as stated transmission rates at certain of FirstEnergy's utilities. As discussed in Note 15, "Regulatory Matters - FERC Matters," above, MAIT and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. In March 2017, FERC approved JCP&L's and MAIT's forward-looking formula rates, subject to refund, with effective dates of June 1, 2017, and July 1, 2017, respectively. Additionally, MAIT and JCP&L filed settlement agreements with FERC on October 13, 2017 and December 21, 2017, respectively, both pending final orders by FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under forward-looking rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which are subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. The CES segment, through FES and AE Supply, primarily supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan, New Jersey and Illinois, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of January 31, 2018, this business segment controlled 12,303 MWs of electric generating capacity, including , as discussed in Note 2, "Asset Sales and Impairments," 756 MWs of generating capacity which remain subject to an asset purchase agreement with a subsidiary of LS Power that is expected to close in the first half of 2018. The CES segment’s operating results are primarily derived from electric generation sales less the related costs of electricity generation, including fuel, purchased power and net transmission (including congestion) and ancillary costs and capacity costs charged by PJM to deliver energy to the segment’s customers, as well as other operating and maintenance costs, including costs incurred by FENOC. Interest expense on stand-alone holding company debt, corporate income taxes and other businesses that do not constitute an operating segment are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other. As of December 31, 2017, Corporate/Other had $6.8 billion of stand-alone holding company long-term debt, of which $1.45 billion was subject to variable-interest rates, and $300 million was borrowed by FE under its revolving credit facility. On January 22, 2018, FE repaid its $1.45 billion of outstanding variable-interest rate debt using the proceeds from the $2.5 billion equity investment. Segment Financial Information For the Years Ended December 31 Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2017 External revenues $ 9,734 $ 1,325 $ 3,143 $ — $ (185 ) $ 14,017 Internal revenues — — 386 — (386 ) — Total revenues 9,734 1,325 3,529 — (571 ) 14,017 Depreciation 724 224 118 72 — 1,138 Amortization of regulatory assets, net 292 16 — — — 308 Impairment of assets and related charges — 41 2,365 — — 2,406 Investment income 54 — 81 11 (48 ) 98 Interest expense 535 156 179 308 — 1,178 Income taxes (benefits) 580 205 155 (45 ) — 895 Net income (loss) 916 336 (2,641 ) (335 ) — (1,724 ) Total assets 27,730 9,525 4,339 663 — 42,257 Total goodwill 5,004 614 — — — 5,618 Property additions 1,191 1,030 317 49 — 2,587 2016 External revenues $ 9,629 $ 1,144 $ 4,070 $ — $ (281 ) $ 14,562 Internal revenues — — 479 — (479 ) — Total revenues 9,629 1,144 4,549 — (760 ) 14,562 Depreciation 676 187 387 63 — 1,313 Amortization of regulatory assets, net 290 7 — — — 297 Impairment of assets and related charges — — 10,665 — — 10,665 Investment income 49 — 66 10 (41 ) 84 Interest expense 586 158 194 219 — 1,157 Income taxes (benefits) 375 187 (3,498 ) (119 ) — (3,055 ) Net income (loss) 651 331 (6,919 ) (240 ) — (6,177 ) Total assets 27,702 8,755 5,952 739 — 43,148 Total goodwill 5,004 614 — — — 5,618 Property additions 1,063 1,101 619 52 — 2,835 2015 External revenues $ 9,582 $ 1,046 $ 4,698 $ — $ (300 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,582 1,046 5,384 — (986 ) 15,026 Depreciation 664 164 394 60 — 1,282 Amortization of regulatory assets, net 165 7 — — — 172 Impairment of assets and related charges 8 — 34 — — 42 Investment income (loss) 42 — (16 ) (9 ) (39 ) (22 ) Impairment of equity method investment — — — 362 — 362 Interest expense 600 147 192 193 — 1,132 Income taxes (benefits) 325 191 50 (251 ) — 315 Net income (loss) 588 328 89 (427 ) — 578 Total assets 27,390 7,800 16,027 877 — 52,094 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,040 1,020 588 56 — 2,704 |
Summary of Quarterly Financial
Summary of Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Data [Abstract] | |
SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) | SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) The following summarizes certain consolidated operating results by quarter for 2017 and 2016 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2017 2016 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,442 $ 3,714 $ 3,309 $ 3,552 $ 3,375 $ 3,917 $ 3,401 $ 3,869 Other operating expense 1,195 940 956 1,141 1,021 950 963 917 Pension and OPEB mark-to-market adjustment 141 — — — 147 — — — Provision for depreciation 293 289 281 275 339 311 334 329 Impairment of assets and related charges 2,244 31 131 — 9,218 — 1,447 — Operating Income (Loss) (1,830 ) 884 544 574 (8,924 ) 861 (975 ) 776 Income (loss) before income taxes (benefits) (2,086 ) 635 291 331 (9,185 ) 631 (1,219 ) 541 Income taxes (benefits) 413 239 117 126 (3,389 ) 251 (130 ) 213 Net Income (Loss) (2,499 ) 396 174 205 (5,796 ) 380 (1,089 ) 328 Earnings (loss) per share of common stock- (1) Basic - Earnings (losses) Available to FirstEnergy Corp. (5.62 ) 0.89 0.39 0.46 (13.44 ) 0.89 (2.56 ) 0.78 Diluted - Earnings (losses) Available to FirstEnergy Corp. (5.62 ) 0.89 0.39 0.46 (13.44 ) 0.89 (2.56 ) 0.77 (1) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 5, "Stock-Based Compensation Plans," for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) 2017 2016 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 700 $ 743 $ 741 $ 914 $ 997 $ 1,100 $ 1,102 $ 1,199 Other operating expense 419 291 286 518 352 316 369 240 Pension and OPEB mark-to-market adjustment 24 — — — 48 — — — Provision for depreciation 29 28 27 25 86 83 84 83 Impairment of assets and related charges 2,031 — — — 8,082 — 540 — Operating Income (Loss) (2,112 ) 102 61 (117 ) (8,153 ) 101 (571 ) 226 Income (loss) from continuing operations before income taxes (benefits) (2,125 ) 108 42 (121 ) (8,171 ) 96 (581 ) 213 Income taxes (benefits) 281 32 23 (41 ) (2,983 ) 56 (143 ) 82 Net Income (Loss) (2,406 ) 76 19 (80 ) (5,188 ) 40 (438 ) 131 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS January 2018 Equity Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in the Company. The Company entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion . The Company also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of the Company’s common stock, par value $0.10 per share, representing an investment of $850 million . The Preferred Stock will participate in dividends on the Common Stock on an as-converted basis based on the number of shares of Common Stock a holder of Preferred Stock would receive if its shares of Preferred Stock were converted on the dividend record date at the Conversion Price in effect at that time. Such dividends will be paid at the same time that the dividends on Common Stock are paid. Each share of Preferred Stock will be convertible into a number of shares of Common Stock equal to the $1,000 liquidation preference, divided by the Conversion Price then in effect. As of January 22, 2018, the Conversion Price in effect was $27.42 per share. The Conversion Price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the Common Stock, as well as dividends on the Common Stock paid in Common Stock and for certain equity issuances below the Conversion Price then in effect. The Preferred Stock will generally be convertible at the option of holders beginning on July 22, 2018. The holders of Preferred Stock may also elect to convert their shares if the Company undergoes a fundamental change. Furthermore, the Preferred Stock will automatically convert to Common Stock upon certain events of bankruptcy or liquidation of the Company. The Company may elect to convert the Preferred Stock if, at any time, fewer than 323,200 shares of Preferred Stock are outstanding. In general, any shares of Preferred Stock outstanding on July 22, 2019, will be automatically converted. However, no shares of Preferred Stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding Common Stock. Furthermore, in no event shall the Company issue more than 58,964,222 shares of Common Stock (the Share Cap) in the aggregate upon conversion of the Convertible Preferred Stock. From and after the time at which the aggregate number of shares of Common Stock issued upon conversion of the Preferred Stock equals the Share Cap, each holder electing to convert Convertible Preferred Stock will be entitled to receive a cash payment equal to the market value of the Common Stock such holder does not receive upon conversion. The holders of Preferred Stock will have limited class voting rights related to the creation of additional securities that are senior or equal with the Preferred Stock, as well as certain reclassifications and amendments that would affect the rights of the holders of Preferred Stock. The holders of Preferred Stock will also have the right to approve issuances of securities convertible or exchangeable for Common Stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans. Pursuant to the Preferred SPA, FirstEnergy formed a RWG composed of three employees of FirstEnergy and two outside members to advise FirstEnergy management regarding an FES restructuring in the event the FES Board decides to seek bankruptcy protection. Bruce Mansfield Plant On the morning of January 10, 2018, Bruce Mansfield plant personnel were in the process of shutting down Unit 1 for a maintenance outage when an equipment failure resulted in an unplanned outage for Unit 2 that led to the loss of plant power. Later that morning, a fire damaged the scrubber, stack and other plant property and systems associated with Units 1 and 2. Evaluation of the extent of the damage, which may be significant, to the scrubber, stack and other plant property and systems associated with Units 1 and 2 is underway and is expected to take several weeks. Unit 3, which had been off-line for maintenance, was unaffected by the January 10 th fire. The affected plant property and systems are insured and management is working with the insurance carriers to complete the assessment. At this time management is unable to estimate the financial effect of the fire on Units 1 and 2. |
Consolidated Valuation and Qual
Consolidated Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | FIRSTENERGY CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2017 , 2016 AND 2015 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) Year Ended December 31, 2017: Accumulated provision for uncollectible accounts — customers $ 53,307 $ 75,859 $ 49,728 $ 127,607 $ 51,287 — other $ 884 $ 6,495 $ — $ 6,357 $ 1,022 Valuation allowance on state and local DTAs $ 437,779 $ 142,623 $ — $ — $ 580,402 Year Ended December 31, 2016: Accumulated provision for uncollectible accounts — customers $ 68,775 $ 81,719 $ 15,222 $ 112,409 $ 53,307 — other $ 5,231 $ 13,597 $ 11,329 $ 29,273 $ 884 Valuation allowance on state and local DTAs $ 192,397 $ 245,382 $ — $ — $ 437,779 Year Ended December 31, 2015: Accumulated provision for uncollectible accounts — customers $ 59,266 $ 114,249 $ 54,199 $ 158,939 $ 68,775 — other $ 5,197 $ 899 $ 4,189 $ 5,054 $ 5,231 Valuation allowance on state and local DTAs $ 174,004 $ 18,393 $ — $ — $ 192,397 (1) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (2) Represents the write-off of accounts considered to be uncollectible. |
FES | |
Valuation and Qualifying Accounts Disclosure [Line Items] | |
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS | FIRSTENERGY SOLUTIONS CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2017 , 2016 AND 2015 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) Year Ended December 31, 2017: Accumulated provision for uncollectible accounts — customers $ 4,898 $ 2,373 $ — $ 4,921 $ 2,350 — other $ — $ 34 $ — $ 2 $ 32 Valuation allowance on state and local DTAs $ 197,490 $ 70,777 $ — $ — $ 268,267 Year Ended December 31, 2016: Accumulated provision for uncollectible accounts — customers $ 8,466 $ 4,766 $ — $ 8,334 $ 4,898 — other $ 2,500 $ — $ — $ 2,500 $ — Valuation allowance on state and local DTAs $ 45,808 $ 151,682 $ — $ — $ 197,490 Year Ended December 31, 2015: Accumulated provision for uncollectible accounts — customers $ 17,862 $ 7,411 $ — $ 16,807 $ 8,466 — other $ 2,500 $ — $ — $ — $ 2,500 Valuation allowance on state and local DTAs $ 32,126 $ 13,682 $ — $ — $ 45,808 (1) Represents recoveries and reinstatements of accounts previously written off. (2) Represents the write-off of accounts considered to be uncollectible. |
Organization and Basis of Prese
Organization and Basis of Presentation (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Accounting | FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued. |
Consolidation | FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation as appropriate. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 9, "Variable Interest Entities"). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). These Notes to Consolidated Financial Statements are combined for FirstEnergy and FES. |
Accounting for the Effects of Regulation | ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, ATSI, MAIT and TrAIL since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income (Loss) concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. |
Revenues and Receivables | REVENUES AND RECEIVABLES Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, FirstEnergy accrues the estimated unbilled amount as revenue and reverses the related prior period estimate. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities, and retail and wholesale sales to customers for FES. |
Earnings Per Share of Common Stock | EARNINGS (LOSS) PER SHARE OF COMMON STOCK Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. As discussed below in "New Accounting Pronouncements," FirstEnergy adopted ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," beginning January 1, 2017. For the year ended December 31, 2017 , there were no material impacts to the basic or diluted earnings per share due to the new standard. |
Property, Plant and Equipment | PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. The cost of nuclear fuel is capitalized within the CES segment's Property, plant and equipment and charged to fuel expense using the specific identification method. |
Asset Retirement Obligations | Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FE's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FE uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO, considering the expected timing of settlement of the ARO based on the expected economic useful life of the plants (including the likelihood that the facilities will be deactivated before the end of their estimated useful lives). The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. |
Asset Impairments | Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. |
Goodwill | GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents goodwill by reporting unit for the year ended December 31, 2017 : |
Investments | INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities. At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. The NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets or liabilities. In 2017 , 2016 and 2015 , FirstEnergy recognized $13 million , $21 million and $102 million , respectively, of OTTI. During the same periods, FES recognized OTTI of $13 million , $19 million and $90 million , respectively. The fair values of FirstEnergy’s investments are disclosed in Note 10, "Fair Value Measurements." The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. FirstEnergy holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. In 2015, Global Holding incurred losses primarily as a result of declines in coal prices due to weakening global and U.S. coal demand. Based on the significant decline in coal pricing and the outlook for the coal market, including the significant decline in the market capitalization of coal companies in 2015, FirstEnergy assessed the value of its investment in Global Holding and determined there was a decline in the fair value of the investment below its carrying value that was other than temporary, resulting in a pre-tax impairment charge of $362 million recognized in 2015. Key assumptions incorporated into the discounted cash flow analysis utilized in the impairment analysis included the discount rate, future long-term coal prices, production levels, sales forecasts, projected capital and operating costs. The impairment charge is classified as a component of Other Income (Expense) in the Consolidated Statement of Income (Loss). See Note 9, "Variable Interest Entities," for further discussion of FirstEnergy's investment in Global Holding. |
Inventory | INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased, and recorded to fuel expense when consumed. See Note 2, "Asset Sales and Impairments," for inventory-related charges recognized in 2017. |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2016-09, " Improvements to Employee Share-Based Payment Accounting " (Issued March 2016): ASU 2016-09 simplifies several aspects of the accounting for employee share-based payments. The new guidance requires all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also does not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. FirstEnergy adopted ASU 2016-09 on January 1, 2017. Upon adoption, FirstEnergy elected to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings of approximately $6 million as of January 1, 2017. Additionally, FirstEnergy retrospectively applied the cash flow presentation requirement to present cash paid to tax authorities when shares are withheld to satisfy statutory tax withholding obligations as financing activities by reclassifying $12 million and $13 million from operating activities to financing activities in the 2016 and 2015 Consolidated Statements of Cash Flows, respectively. ASU 2016-15, " Classification of Certain Cash Receipts and Cash Payments " (Issued August 2016): The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the Consolidated Statements of Cash Flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. ASU 2016-15 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. FirstEnergy early adopted this ASU as of January 1, 2017. There was no impact to prior periods. Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2017. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance: establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy has evaluated its revenues and the new guidance will have limited impacts to current revenue recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy will not record a cumulative adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes will be implemented. FirstEnergy expects to disaggregate revenue by type of service in future revenue disclosures. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (issued January 2016): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. Upon adoption, January 1, 2018, FirstEnergy will recognize all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT’s equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting the standard, FirstEnergy and FES will record a cumulative effect adjustment to retained earnings of $115 million (pre-tax) on January 1, 2018 representing unrealized gains on equity securities that were previously recorded to AOCI. ASU 2016-02, "Leases (Topic 842)" (Issued February 2016) and ASU 2018-01 ,"Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842" (Issued January 2018): ASU 2016-02 will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets. In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. ASU 2018-01 (same effective date and transition requirements as ASU 2016-02) provides an optional transition practical expedient that, if elected, would not require an entity to reconsider its accounting for existing land easements that are not currently accounted for under the old leases standard. FirstEnergy does not plan to adopt these standards early. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy expects an increase in assets and liabilities, however, it is currently assessing the impact on its Consolidated Financial Statements. This assessment includes monitoring utility industry implementation guidance. FirstEnergy is in the process of conducting outreach activities across its business units and analyzing its lease population. In addition, it has begun implementation of a third-party software tool that will assist with the initial adoption and ongoing compliance. ASU 2016-13, “ Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ” (issued June 2016): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018. ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory " (issued October 2016): ASU 2016-16 eliminates the exception for all intra-entity sales of assets other than inventory, which allows companies to defer the tax effects of intra-entity asset transfers. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the intra-entity transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted and the modified retrospective approach will be required for transition to the new guidance, with a cumulative-effect adjustment recorded in retained earnings as of the beginning of the period of adoption. FirstEnergy will not be impacted upon its adoption of this ASU on January 1, 2018. ASU 2016-18, " Restricted Cash " (issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. In its first quarter 2018 Form 10-Q, FirstEnergy will show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. In addition, FirstEnergy will disclose the nature of its restricted cash and restricted cash equivalent balances within the footnotes. ASU 2017-01, " Business Combinations: Clarifying the Definition of a Business " (Issued January 2017): ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. The ASU will be applied prospectively to any transactions occurring within the period of adoption. FirstEnergy will not early adopt this standard. ASU 2017-07, " Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost " (Issued March 2017): ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the “other components”) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. As a result of the retrospective presentation, FirstEnergy will reclassify approximately $62 million of non-service costs, excluding the annual mark-to-market, to Other Income/Expense related to the fiscal year 2017 within the 2018 financial statements. In addition, ASU 2017-07 requires service costs to be capitalized as appropriate and non-service costs to be charged to earnings. FirstEnergy will present non-service costs in the caption “Miscellaneous Income” with the exception of the annual mark-to-market adjustment which will be disclosed separately. ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. ASU 2018-02 is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2018. Early adoption of the ASU is permitted including adoption in any interim period. ASU 2018-02 should be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the income tax rate change resulting from the Tax Act is recognized. FirstEnergy did not adopt this ASU as of December 31, 2017. |
Pension and Other Postretirement Plans | PENSION AND OTHER POSTEMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2017, 2016, and 2015 were $141 million , $147 million , and $242 million , respectively. In 2017, the pension and OPEB mark-to-market adjustment primarily reflects a 50 bps decrease in the discount rate used to measure benefit obligations, partially offset by higher than expected asset returns. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. |
Share-based Compensation, Option and Incentive Plans | Shares used under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods range from one to ten years , with the majority of awards having a vesting period of three years . FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," FE has elected to account for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled |
Variable Interest Entities | VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. |
Fair Value Measurement | Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs follows: FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 11, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. |
Derivatives | FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. |
Income Taxes | FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. |
Organization and Basis of Pre40
Organization and Basis of Presentation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Regulatory assets on the Balance Sheets | The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2017 and December 31, 2016 , and the changes during the year ended December 31, 2017 : Net Regulatory Assets (Liabilities) by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 46 $ 90 $ (44 ) Customer receivables (payables) for future income taxes (2,765 ) 468 (3,233 ) Nuclear decommissioning and spent fuel disposal costs (323 ) (304 ) (19 ) Asset removal costs (774 ) (770 ) (4 ) Deferred transmission costs 187 122 65 Deferred generation costs 198 331 (133 ) Deferred distribution costs 258 296 (38 ) Contract valuations 118 153 (35 ) Storm-related costs 329 397 (68 ) Other 46 74 (28 ) Net Regulatory Assets (Liabilities) included on the Consolidated Balance Sheets $ (2,680 ) $ 857 $ (3,537 ) |
Receivables from customers | Billed and unbilled customer receivables as of December 31, 2017 and 2016 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2017 Billed $ 860 $ 106 Unbilled 603 75 Total $ 1,463 $ 181 December 31, 2016 Billed $ 833 $ 123 Unbilled 607 90 Total $ 1,440 $ 213 |
Reconciliation of basic and diluted earnings per share | Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock 2017 2016 2015 (In millions, except per share amounts) Net income (loss) $ (1,724 ) $ (6,177 ) $ 578 Weighted average number of basic shares outstanding 444 426 422 Assumed exercise of dilutive stock options and awards (1) — — 2 Weighted average number of diluted shares outstanding 444 426 424 Basic earnings (loss) per share of common stock $ (3.88 ) $ (14.49 ) $ 1.37 Diluted earnings (loss) per share of common stock $ (3.88 ) $ (14.49 ) $ 1.37 (1) For the years ended December 31, 2017, 2016 and 2015, approximately three million , three million and one million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutiv |
Property, plant and equipment balances | Property, plant and equipment balances for FES as of December 31, 2017 and 2016 were as follows: December 31, 2017 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 2,344 $ (1,743 ) $ 601 $ 19 $ 620 Other 151 (80 ) 71 3 74 Total $ 2,495 $ (1,823 ) $ 672 $ 22 $ 694 December 31, 2016 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 2,212 $ (1,720 ) $ 492 $ 63 $ 555 Nuclear Generation 2,065 (1,723 ) 342 118 460 Nuclear Fuel 2,637 (2,418 ) 219 241 460 Other 143 (68 ) 75 5 80 Total $ 7,057 $ (5,929 ) $ 1,128 $ 427 $ 1,555 Property, plant and equipment balances by segment as of December 31, 2017 and 2016 were as follows: December 31, 2017 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution $ 25,950 $ (7,503 ) $ 18,447 $ 469 $ 18,916 Regulated Transmission 10,102 (2,055 ) 8,047 480 8,527 Competitive Energy Services (2) 2,902 (1,958 ) 944 28 972 Corporate/Other 824 (409 ) 415 49 464 Total $ 39,778 $ (11,925 ) $ 27,853 $ 1,026 $ 28,879 December 31, 2016 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution $ 24,979 $ (7,169 ) $ 17,810 $ 472 $ 18,282 Regulated Transmission 9,342 (1,948 ) 7,394 383 7,777 Competitive Energy Services (2) 8,680 (6,267 ) 2,413 453 2,866 Corporate/Other 766 (347 ) 419 43 462 Total $ 43,767 $ (15,731 ) $ 28,036 $ 1,351 $ 29,387 (1) Includes capital leases of $238 million and $244 million at December 31, 2017 and 2016, respectively. (2) Primarily consists of generating assets and nuclear fuel as discussed above. |
Annual composite rates | The respective annual composite rates for FirstEnergy's and FES' electric plant in 2017 , 2016 and 2015 are shown in the following table: Annual Composite Depreciation Rate 2017 2016 2015 FirstEnergy 2.4 % 2.5 % 2.5 % FES 4.4 % 3.3 % 3.2 % |
Summary of changes in goodwill | FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, and CES. The following table presents goodwill by reporting unit for the year ended December 31, 2017 : Goodwill Regulated Distribution Regulated Transmission Consolidated (In millions) Balance as of December 31, 2017 $ 5,004 $ 614 $ 5,618 FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential impairment arise. |
Asset Sales and Impairments (Ta
Asset Sales and Impairments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Impairment Assets | The charges consisted of the following: (In millions) Pre-tax charge Nuclear generating asset Beaver Valley $ 107 Davis Besse 420 Perry 124 Nuclear fuel 369 Materials and supplies 81 Asset retirement obligation 944 Total non-cash charges $ 2,045 |
Accumulated Other Comprehensi42
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | The changes in AOCI for the years ended December 31, 2017 , 2016 and 2015 for FES are shown in the following table: FES Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (7 ) $ 21 $ 43 $ 57 Other comprehensive income before reclassifications — 15 10 25 Amounts reclassified from AOCI (3 ) (24 ) (16 ) (43 ) Other comprehensive loss (3 ) (9 ) (6 ) (18 ) Income tax benefits on other comprehensive loss (1 ) (4 ) (2 ) (7 ) Other comprehensive loss, net of tax (2 ) (5 ) (4 ) (11 ) AOCI Balance, December 31, 2015 $ (9 ) $ 16 $ 39 $ 46 Other comprehensive income before reclassifications — 100 — 100 Amounts reclassified from AOCI — (48 ) (14 ) (62 ) Other comprehensive income (loss) — 52 (14 ) 38 Income tax (benefits) on other comprehensive income (loss) — 20 (5 ) 15 Other comprehensive income (loss), net of tax — 32 (9 ) 23 AOCI Balance, December 31, 2016 $ (9 ) $ 48 $ 30 $ 69 Other comprehensive income before reclassifications — 91 — 91 Amounts reclassified from AOCI 2 (61 ) (14 ) (73 ) Other comprehensive income (loss) 2 30 (14 ) 18 Income tax (benefits) on other comprehensive income (loss) 1 10 (5 ) 6 Other comprehensive income (loss), net of tax 1 20 (9 ) 12 AOCI Balance, December 31, 2017 $ (8 ) $ 68 $ 21 $ 81 The changes in AOCI for the years ended December 31, 2017 , 2016 and 2015 for FirstEnergy are shown in the following table: FirstEnergy Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2015 $ (37 ) $ 25 $ 258 $ 246 Other comprehensive income before reclassifications — 14 10 24 Amounts reclassified from AOCI 5 (25 ) (126 ) (146 ) Other comprehensive income (loss) 5 (11 ) (116 ) (122 ) Income tax (benefits) on other comprehensive income (loss) 1 (4 ) (44 ) (47 ) Other comprehensive income (loss), net of tax 4 (7 ) (72 ) (75 ) AOCI Balance, December 31, 2015 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 106 13 119 Amounts reclassified from AOCI 8 (51 ) (72 ) (115 ) Other comprehensive income (loss) 8 55 (59 ) 4 Income tax (benefits) on other comprehensive income (loss) 3 21 (23 ) 1 Other comprehensive income (loss), net of tax 5 34 (36 ) 3 AOCI Balance, December 31, 2016 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 85 (11 ) 74 Amounts reclassified from AOCI 10 (63 ) (74 ) (127 ) Other comprehensive income (loss) 10 22 (85 ) (53 ) Income tax (benefits) on other comprehensive income (loss) 4 7 (32 ) (21 ) Other comprehensive income (loss), net of tax 6 15 (53 ) (32 ) AOCI Balance, December 31, 2017 $ (22 ) $ 67 $ 97 $ 142 |
Reclassification out of Accumulated Other Comprehensive Income | The following amounts were reclassified from AOCI for FES in the years ended December 31, 2017 , 2016 and 2015 : FES Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 2 $ — $ (3 ) Other operating expenses (1 ) — 1 Income taxes (benefits) $ 1 $ — $ (2 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (61 ) $ (48 ) $ (24 ) Investment income (loss) 23 18 9 Income taxes (benefits) $ (38 ) $ (30 ) $ (15 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14 ) $ (14 ) $ (16 ) (1) 5 5 6 Income taxes (benefits) $ (9 ) $ (9 ) $ (10 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2017 , 2016 and 2015 : FirstEnergy Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2017 2016 2015 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 2 $ — $ (3 ) Other operating expenses Long-term debt 8 8 8 Interest expense 10 8 5 Total before taxes (4 ) (3 ) (1 ) Income taxes (benefits) $ 6 $ 5 $ 4 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (63 ) $ (51 ) $ (25 ) Investment income (loss) 23 19 9 Income taxes (benefits) $ (40 ) $ (32 ) $ (16 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (74 ) $ (72 ) $ (126 ) (1) 28 27 49 Income taxes (benefits) $ (46 ) $ (45 ) $ (77 ) Net of tax (1) These AOCI components are included in the computation of net periodic pension cost. See Note 4, "Pension and Other Postemployment Benefits," for additional details. (2) Parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. |
Pension and Other Postemploym43
Pension and Other Postemployment Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Obligations and Funded Status | Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2017 2016 2017 2016 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,426 $ 9,079 $ 711 $ 724 Service cost 208 191 5 5 Interest cost 390 398 27 30 Plan participants’ contributions — — 4 5 Plan amendments 11 — — (13 ) Medicare retiree drug subsidy — — 1 1 Actuarial loss 610 224 32 14 Benefits paid (478 ) (466 ) (49 ) (55 ) Benefit obligation as of December 31 $ 10,167 $ 9,426 $ 731 $ 711 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 6,213 $ 5,338 $ 420 $ 431 Actual return on plan assets 950 442 49 30 Company contributions 18 899 16 9 Plan participants’ contributions — — 4 5 Benefits paid (477 ) (466 ) (50 ) (55 ) Fair value of plan assets as of December 31 $ 6,704 $ 6,213 $ 439 $ 420 Funded Status: Qualified plan $ (3,043 ) $ (2,821 ) Non-qualified plans (420 ) (392 ) Funded Status $ (3,463 ) $ (3,213 ) $ (292 ) $ (291 ) Accumulated benefit obligation $ 9,583 $ 8,913 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ — $ 9 $ — $ — Current liabilities (19 ) (19 ) — — Noncurrent liabilities (3,444 ) (3,203 ) (292 ) (291 ) Net liability as of December 31 $ (3,463 ) $ (3,213 ) $ (292 ) $ (291 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 32 $ 28 $ (206 ) $ (288 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 3.75 % 4.25 % 3.50 % 4.00 % Rate of compensation increase 4.20 % 4.20 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0-5.5% 6.0-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2027 Allocation of Plan Assets (as of December 31) Equity securities 42 % 44 % 50 % 53 % Bonds 32 % 30 % 33 % 41 % Absolute return strategies 10 % 8 % — % — % Real estate funds 9 % 10 % — % — % Private equity funds 1 % — % — % — % Cash and short-term securities 6 % 8 % 17 % 6 % Total 100 % 100 % 100 % 100 % |
Components of Net Periodic Benefit Costs | Pension OPEB Components of Net Periodic Benefit Costs 2017 2016 2015 2017 2016 2015 (In millions) Service cost $ 208 $ 191 $ 193 $ 5 $ 5 $ 5 Interest cost 390 398 383 27 30 29 Expected return on plan assets (448 ) (399 ) (443 ) (30 ) (30 ) (33 ) Amortization of prior service cost (credit) 7 8 8 (81 ) (80 ) (134 ) Pension & OPEB mark-to-market adjustment 108 179 344 13 15 25 Net periodic benefit cost (credit) $ 265 $ 377 $ 485 $ (66 ) $ (60 ) $ (108 ) |
Assumptions Used to Determine Net Periodic Benefit Cost | Assumptions Used to Determine Net Periodic Benefit Cost * for Years Ended December 31 Pension OPEB 2017 2016 2015 2017 2016 2015 Weighted-average discount rate 4.25 % 4.50 % 4.25 % 4.00 % 4.25 % 4.00 % Expected long-term return on plan assets 7.50 % 7.50 % 7.75 % 7.50 % 7.50 % 7.75 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A N/A * Excludes impact of pension and OPEB mark-to-market adjustment. |
Target asset allocations for pension and OPEB portfolio | FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2017 and 2016 are shown in the following table: Target Asset Allocations Equities 38 % Fixed income 30 % Absolute return strategies 8 % Real estate 10 % Alternative investments 8 % Cash 6 % 100 % |
Effect of One-Percentage Point change in assumed health care cost trend rates | Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: 1-Percentage-Point Increase 1-Percentage-Point Decrease (In millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on accumulated benefit obligation $ 21 $ (18 ) |
Estimated Future Benefit Payments | Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2018 $ 518 $ 55 $ (1 ) 2019 531 54 (1 ) 2020 552 53 (1 ) 2021 567 53 (1 ) 2022 581 52 (1 ) Years 2023-2027 3,056 241 (3 ) |
Net Pension and OPEB Asset (Liability) | FES’ share of the pension and OPEB net (liability) asset as of December 31, 2017 and 2016 , was as follows: Pension OPEB 2017 2016 2017 2016 (In millions) Net (Liability) Asset (1) $ (97 ) $ (158 ) $ 40 $ 36 (1) Excludes $954 million and $866 million as of December 31, 2017 and 2016, respectively, of affiliated non-current liabilities related to pension and OPEB mark-to-market costs allocated to FES of which $626 million and $570 million , respectively, are from FENOC. |
Net Periodic Pension and OPEB Costs | FES’ share of the net periodic benefit cost (credit), including the pension and OPEB mark-to-market adjustment, for the three years ended December 31, 2017 , was as follows: Pension OPEB 2017 2016 2015 2017 2016 2015 (In millions) Net Periodic Cost (Credit) $ 60 $ (5 ) $ 10 $ (17 ) $ (26 ) $ (22 ) |
Pension | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension investments measured at fair value | The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2017 and 2016 . December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 379 $ — $ 379 6 % Equity investments Domestic 695 27 — 722 11 % International 514 1,569 — 2,083 31 % Fixed income Government bonds — 251 — 251 4 % Corporate bonds — 1,237 — 1,237 18 % High yield debt — 689 — 689 10 % Mortgage-backed securities (non-government) — 31 — 31 — % Alternatives Hedge funds (Absolute return) — 635 — 635 10 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 631 631 9 % Total (1) $ 1,209 $ 4,817 $ 631 $ 6,657 99 % Private equity funds (2) 57 1 % Total Investments $ 6,714 100 % (1) Excludes $(10) million as of December 31, 2017 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net asset value used as a practical expedient to approximate fair value. December 31, 2016 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 464 $ — $ 464 8 % Equity investments Domestic (1) 1,048 13 — 1,061 17 % International 422 1,269 — 1,691 27 % Fixed income Government bonds — 106 — 106 2 % Corporate bonds — 1,245 — 1,245 20 % High yield debt — 372 — 372 6 % Mortgage-backed securities (non-government) — 112 — 112 2 % Alternatives Hedge funds (Absolute return) — 500 — 500 8 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 615 615 10 % Total (2) $ 1,470 $ 4,080 $ 615 $ 6,165 100 % Private equity funds (3) 33 — % Total Investments $ 6,198 100 % (1) As a result of the $500 million equity contribution on December 13, 2016, there was $293 million of FE Stock included in the pension plan assets as of December 31, 2016. (2) Excludes $16 million as of December 31, 2016 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (3) Net asset value used as a practical expedient to approximate fair value. |
Reconciliation of changes in the fair value of pension investments | The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2017 and 2016 : Real Estate Funds Balance as of January 1, 2016 $ 587 Actual return on plan assets: Unrealized gains 29 Realized gains (losses) 14 Transfers in (15 ) Balance as of December 31, 2016 $ 615 Actual return on plan assets: Unrealized gains 3 Realized gains 10 Transfers in (out) 3 Balance as of December 31, 2017 $ 631 |
OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension investments measured at fair value | As of December 31, 2017 and 2016 , the OPEB trust investments measured at fair value were as follows: December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 75 $ — $ 75 17 % Equity investment Domestic 220 — — 220 50 % Fixed income Government bonds — 109 — 109 24 % Corporate bonds — 34 — 34 8 % Mortgage-backed securities (non-government) 3 — 3 1 % Total (1) $ 220 $ 221 $ — $ 441 100 % (1) Excludes $(2) million as of December 31, 2017 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2016 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 27 $ — $ 27 6 % Equity investment Domestic 223 — — 223 53 % Fixed income U.S. treasuries — 40 — 40 9 % Government bonds — 108 — 108 26 % Corporate bonds — 24 — 24 6 % Mortgage-backed securities (non-government) — 2 — 2 — % Total (1) $ 223 $ 201 $ — $ 424 100 % (1) Excludes $(4) million as of December 31, 2016 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Stock-Based Compensation Plans
Stock-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Stock-based Compensation Expense | Stock-based compensation costs and the amount of stock-based compensation expense capitalized related to FirstEnergy and FES plans are included in the following tables: FirstEnergy Years Ended December 31 Stock-based Compensation Plan 2017 2016 2015 (In millions) Restricted Stock Units $ 49 $ 62 $ 46 Restricted Stock 1 2 2 Performance Shares — (3 ) — 401(k) Savings Plan 42 39 38 EDCP & DCPD 6 5 3 Total $ 98 $ 105 $ 89 Stock-based compensation costs capitalized $ 37 $ 38 $ 32 FES Years Ended December 31 Stock-based Compensation Plan 2017 2016 2015 (In millions) Restricted Stock Units $ 4 $ 11 $ 6 401(k) Savings Plan 3 5 5 Total $ 7 $ 16 $ 11 Stock-based compensation costs capitalized $ 1 $ 2 $ 1 |
Schedule of Nonvested Restricted Stock Units Activity | Restricted stock unit activity for the year ended December 31, 2017 , was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2017 3,063,729 $ 32.98 Granted in 2017 1,577,844 31.71 Forfeited in 2017 (169,012 ) 32.66 Vested in 2017 (1) (1,156,810 ) 30.81 Nonvested as of December 31, 2017 3,315,751 $ 33.24 (1) Excludes dividend equivalents of 159,274 shares earned during vesting period |
Stock Options | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Stock Option Activity | There were no stock options granted in 2017 . Stock option activity during 2017 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2017 (1,376,821 options exercisable) 1,376,821 $ 44.60 Options forfeited (9,946 ) 70.60 Balance, December 31, 2017 (1,366,875 options exercisable) 1,366,875 $ 44.41 |
Taxes (Tables)
Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Provision for income taxes (benefits) | INCOME TAXES (BENEFITS) 2017 2016 2015 (In millions) FirstEnergy Currently payable (receivable)- Federal $ 14 $ (1 ) $ 1 State 42 9 30 56 8 31 Deferred, net- Federal 876 (3,114 ) 277 State (29 ) 59 15 847 (3,055 ) 292 Investment tax credit amortization (8 ) (8 ) (8 ) Total provision for income taxes (benefits) $ 895 $ (3,055 ) $ 315 FES Currently payable (receivable)- Federal $ (159 ) $ (67 ) $ (56 ) State (1 ) (1 ) 2 (160 ) (68 ) (54 ) Deferred, net- Federal 509 (2,861 ) 103 State (52 ) (57 ) 18 457 (2,918 ) 121 Investment tax credit amortization (2 ) (2 ) (2 ) Total provision for income taxes (benefits) $ 295 $ (2,988 ) $ 65 |
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the three years ended December 31: 2017 2016 2015 (In millions) FirstEnergy Income (loss) before income taxes (benefits) $ (829 ) $ (9,232 ) $ 893 Federal income tax expense (benefit) at statutory rate (35%) $ (290 ) $ (3,231 ) $ 313 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (4 ) (192 ) 17 AFUDC equity and other flow-through (15 ) (13 ) (16 ) Amortization of investment tax credits (8 ) (8 ) (8 ) Change in accounting method — — (8 ) ESOP dividend (6 ) (6 ) (6 ) Impairment of non-deductible goodwill — 157 — Remeasurement of deferred taxes 1,193 — — Uncertain tax positions (3 ) (16 ) 1 Valuation allowances 29 246 18 Other, net (1 ) 8 4 Total income taxes (benefits) $ 895 $ (3,055 ) $ 315 Effective income tax rate (108.0 )% 33.1 % 35.3 % FES Income (loss) before income taxes (benefits) $ (2,096 ) $ (8,443 ) $ 147 Federal income tax expense (benefit) at statutory rate (35%) $ (734 ) $ (2,955 ) $ 51 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (52 ) (188 ) 2 Amortization of investment tax credits (2 ) (2 ) (2 ) ESOP dividend — (1 ) (1 ) Impairment of non-deductible goodwill — 9 — Remeasurement of deferred taxes 1,067 — — Uncertain tax positions — (8 ) 5 Valuation allowances 18 151 14 Other, net (2 ) 6 (4 ) Total income taxes (benefits) $ 295 $ (2,988 ) $ 65 Effective income tax rate (14.1 )% 35.4 % 44.2 % |
Accumulated deferred income taxes | Accumulated deferred income taxes as of December 31, 2017 and 2016 , are as follows: 2017 2016 (In millions) FirstEnergy Property basis differences $ 3,662 $ 7,088 Deferred sale and leaseback gain (231 ) (351 ) Pension and OPEB (952 ) (1,347 ) Nuclear decommissioning activities 450 635 Asset retirement obligations (453 ) (669 ) Regulatory asset/liability 416 545 Deferred compensation (177 ) (269 ) Nuclear Fuel (375 ) (90 ) Loss carryforwards and AMT credits (1,467 ) (2,251 ) Valuation reserve 580 438 All other (94 ) 36 Net deferred income tax liability $ 1,359 $ 3,765 FES Property basis differences $ (677 ) $ (1,009 ) Deferred sale and leaseback gain (219 ) (328 ) Pension and OPEB (244 ) (366 ) Lease market valuation liability 75 111 Nuclear decommissioning activities 411 540 Asset retirement obligations (296 ) (453 ) Nuclear Fuel (375 ) (90 ) Loss carryforwards and AMT credits (587 ) (830 ) Valuation reserve 268 197 All other (110 ) (51 ) Net deferred income tax asset $ (1,754 ) $ (2,279 ) |
Pre-tax net operating loss expiration period | Expiration Period FirstEnergy FES (In millions) State Local State Local 2018-2022 $ 806 $ 3,472 $ 2 $ 1,954 2023-2027 1,963 — 32 — 2028-2032 2,382 — 703 — 2033-2037 1,896 — 982 — $ 7,047 $ 3,472 $ 1,719 $ 1,954 |
Changes in unrecognized tax benefits | The following table summarizes the changes in unrecognized tax positions for the years ended 2017 , 2016 and 2015 : FirstEnergy FES (In millions) Balance, January 1, 2015 $ 34 $ 3 Current year increases 3 — Prior years increases 7 5 Prior years decreases (10 ) — Balance, December 31, 2015 $ 34 $ 8 Current year increases 2 — Prior years increases 69 — Prior years decreases (21 ) (8 ) Balance, December 31, 2016 $ 84 $ — Current year increases 2 — Decrease for lapse in statute (6 ) — Balance, December 31, 2017 $ 80 $ — |
Details of general taxes | General tax expense for 2017 , 2016 and 2015 , is summarized as follows: 2017 2016 2015 (In millions) FirstEnergy KWH excise $ 188 $ 196 $ 193 State gross receipts 204 212 224 Real and personal property 486 472 410 Social security and unemployment 131 127 119 Other 34 35 32 Total general taxes $ 1,043 $ 1,042 $ 978 FES State gross receipts $ 20 $ 28 $ 44 Real and personal property 27 42 36 Social security and unemployment 11 15 16 Other — 3 2 Total general taxes $ 58 $ 88 $ 98 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Leases [Abstract] | |
Rentals for capital and operating leases | Operating lease expense for 2017 , 2016 and 2015 , is summarized as follows: (In millions) 2017 2016 2015 FirstEnergy $ 158 $ 168 $ 174 FES $ 93 $ 94 $ 94 |
Future minimum capital lease payments | The future minimum capital lease payments as of December 31, 2017 are as follows: Capital Leases FirstEnergy FES (In millions) 2018 $ 28 $ 2 2019 23 — 2020 18 — 2021 15 — 2022 13 — Years thereafter 20 — Total minimum lease payments 117 2 Interest portion (26 ) — Present value of net minimum lease payments 91 2 Less current portion 24 2 Noncurrent portion $ 67 $ — |
Future minimum operating lease payments | future minimum operating lease payments as of December 31, 2017 , are as follows: Operating Leases FirstEnergy FES (In millions) 2018 $ 146 $ 101 2019 128 97 2020 102 68 2021 124 93 2022 111 91 Years thereafter 1,263 1,131 Total minimum lease payments $ 1,874 $ 1,581 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Future Amortization | As of December 31, 2017 , intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2017 2018 2019 2020 2021 2022 Thereafter NUG contracts (1) $ 124 $ 36 $ 88 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 63 OVEC 8 3 5 1 — 1 — — — 4 Coal contracts (2) 102 94 8 4 3 3 2 — — — FES customer contracts 148 144 4 5 3 1 — — — — $ 382 $ 277 $ 105 $ 15 $ 11 $ 10 $ 7 $ 5 $ 5 $ 67 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings. |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entities [Abstract] | |
Net exposure to loss based upon the casualty value provisions | The following table discloses FirstEnergy's net exposure to loss based upon the casualty value provisions as of December 31, 2017 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy (1) $ 1,083 $ 862 $ 221 (1) All amounts are associated with FES. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value of Financial Instruments [Line Items] | |
Assets and liabilities measured on recurring basis | The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: FirstEnergy Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,196 $ — $ 1,196 $ — $ 1,247 $ — $ 1,247 Derivative assets - commodity contracts — 33 — 33 10 200 — 210 Derivative assets - FTRs — — 4 4 — — 7 7 Derivative assets - NUG contracts (1) — — — — — — 1 1 Equity securities (2) 1,104 — — 1,104 925 — — 925 Foreign government debt securities — 88 — 88 — 78 — 78 U.S. government debt securities — 154 — 154 — 161 — 161 U.S. state debt securities — 276 — 276 — 246 — 246 Other (3) 589 135 — 724 199 123 — 322 Total assets $ 1,693 $ 1,882 $ 4 $ 3,579 $ 1,134 $ 2,055 $ 8 $ 3,197 Liabilities Derivative liabilities - commodity contracts $ — $ (27 ) $ — $ (27 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (6 ) (6 ) Derivative liabilities - NUG contracts (1) — — (79 ) (79 ) — — (108 ) (108 ) Total liabilities $ — $ (27 ) $ (80 ) $ (107 ) $ (6 ) $ (118 ) $ (114 ) $ (238 ) Net assets (liabilities) (4) $ 1,693 $ 1,855 $ (76 ) $ 3,472 $ 1,128 $ 1,937 $ (106 ) $ 2,959 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (3) Primarily consists of short-term cash investments. (4) Excludes $(8) million and $(3) million as of December 31, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts | The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and December 31, 2016 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2016 Balance $ 1 $ (137 ) $ (136 ) $ 8 $ (13 ) $ (5 ) Unrealized gain (loss) 2 (17 ) (15 ) (6 ) (4 ) (10 ) Purchases — — — 16 (7 ) 9 Settlements (2 ) 46 44 (11 ) 18 7 December 31, 2016 Balance $ 1 $ (108 ) $ (107 ) $ 7 $ (6 ) $ 1 Unrealized gain (loss) — (10 ) (10 ) 1 (2 ) (1 ) Purchases — — — 4 (1 ) 3 Settlements (1 ) 39 38 (8 ) 8 — December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 4 $ (1 ) $ 3 (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. |
Quantitative information for level 3 valuation | The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices ($4.60) to $5.40 $0.70 Dollars/MWH NUG Contracts $ (79 ) Model Generation 400 to 2,099,000 $30.70 to $32.00 426,000 $30.70 MWH |
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2017 and December 31, 2016 : December 31, 2017 (1) December 31, 2016 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,707 $ 31 $ 1,738 $ 1,735 $ 38 $ 1,773 FES 950 20 970 847 27 874 Equity securities FirstEnergy $ 949 $ 155 $ 1,104 $ 822 $ 103 $ 925 FES 695 115 810 564 70 634 (1) Excludes short-term cash investments: FirstEnergy - $87 million ; FES - $76 million . (2) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 million . |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three years ended December 31, 2017 , 2016 and 2015 were as follows: December 31, 2017 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,170 $ 330 $ (253 ) $ (13 ) $ 98 FES 940 256 (195 ) (13 ) 59 December 31, 2016 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,678 $ 170 $ (121 ) $ (21 ) $ 100 FES 717 117 (69 ) (19 ) 56 December 31, 2015 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 1,534 $ 209 $ (191 ) $ (102 ) $ 101 FES 733 158 (134 ) (90 ) 57 |
Fair value and related carrying amounts of long-term debt and other long-term obligations | The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts: December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 22,261 $ 23,038 $ 19,885 $ 19,829 FES 2,836 1,487 3,000 1,555 |
FES | |
Fair Value of Financial Instruments [Line Items] | |
Assets and liabilities measured on recurring basis | FES Recurring Fair Value Measurements December 31, 2017 December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 720 $ — $ 720 $ — $ 726 $ — $ 726 Derivative assets - commodity contracts — 33 — 33 10 200 — 210 Derivative assets - FTRs — — 1 1 — — 4 4 Equity securities (1) 810 — — 810 634 — — 634 Foreign government debt securities — 65 — 65 — 58 — 58 U.S. government debt securities — 133 — 133 — 48 — 48 U.S. state debt securities — 29 — 29 — 3 — 3 Other (2) 1 96 — 97 2 81 — 83 Total assets $ 811 $ 1,076 $ 1 $ 1,888 $ 646 $ 1,116 $ 4 $ 1,766 Liabilities Derivative liabilities - commodity contracts $ — $ (23 ) $ — $ (23 ) $ (6 ) $ (118 ) $ — $ (124 ) Derivative liabilities - FTRs — — (1 ) (1 ) — — (5 ) (5 ) Total liabilities $ — $ (23 ) $ (1 ) $ (24 ) $ (6 ) $ (118 ) $ (5 ) $ (129 ) Net assets (liabilities) (3) $ 811 $ 1,053 $ — $ 1,864 $ 640 $ 998 $ (1 ) $ 1,637 (1) NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. (2) Primarily consists of short-term cash investments. (3) Excludes $3 million and $2 million as of December 31, 2017 and December 31, 2016 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts | The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2017 and December 31, 2016 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2016 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (1 ) Unrealized loss — (1 ) (1 ) Purchases 1 (1 ) — Settlements (4 ) 6 2 December 31, 2017 Balance $ 1 $ (1 ) $ — |
Quantitative information for level 3 valuation | The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2017 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ — Model RTO auction clearing prices ($4.60) to $3.30 $0.10 Dollars/MWH |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative [Line Items] | |
Fair value of derivatives instruments | The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Other Commodity Contracts $ 33 $ 133 Commodity Contracts $ (27 ) $ (72 ) FTRs 4 7 FTRs (1 ) (6 ) 37 140 (28 ) (78 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (79 ) (108 ) Commodity Contracts — 77 Noncurrent Liabilities - Other FTRs — — Commodity Contracts — (52 ) NUGs (1) — 1 FTRs — — — 78 (79 ) (160 ) Derivative Assets $ 37 $ 218 Derivative Liabilities $ (107 ) $ (238 ) (1) NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. |
Offsetting assets | The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 4 (1 ) — 3 $ 37 $ (20 ) $ — $ 17 Derivative Liabilities Commodity contracts $ (27 ) $ 19 $ 3 $ (5 ) FTRs (1 ) 1 — — NUG contracts (79 ) — — (79 ) $ (107 ) $ 20 $ 3 $ (84 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 ) |
Offsetting liabilities | The following tables summarize the fair value of derivative assets and derivative liabilities on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 4 (1 ) — 3 $ 37 $ (20 ) $ — $ 17 Derivative Liabilities Commodity contracts $ (27 ) $ 19 $ 3 $ (5 ) FTRs (1 ) 1 — — NUG contracts (79 ) — — (79 ) $ (107 ) $ 20 $ 3 $ (84 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 7 (6 ) — 1 NUG contracts 1 — — 1 $ 218 $ (123 ) $ — $ 95 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (6 ) 6 — — NUG contracts (108 ) — — (108 ) $ (238 ) $ 123 $ 1 $ (114 ) |
Volume of First Energy's outstanding derivative transactions | The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 9 — 9 MWH NUGs 2 — 2 MWH The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2017 : Purchases Sales Net Units (In millions) Power Contracts 2 11 (9 ) MWH FTRs 5 — 5 MWH |
Effect of derivative instruments on statements of income and comprehensive income | The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during 2017 , 2016 and 2015 are summarized in the following tables: Year Ended December 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (82 ) $ 1 $ (81 ) Realized Gain (Loss) Reclassified to: Revenues $ 54 $ (4 ) $ 50 Purchased Power Expense (17 ) — (17 ) Other Operating Expense — (14 ) (14 ) Fuel Expense 5 — 5 Year Ended December 31 Commodity FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (14 ) $ 5 $ (9 ) Realized Gain (Loss) Reclassified to: Revenues $ 210 $ 8 $ 218 Purchased Power Expense (131 ) — (131 ) Other Operating Expense — (35 ) (35 ) Fuel Expense (8 ) — (8 ) Year Ended December 31 Commodity FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 93 $ (20 ) $ 73 Realized Gain (Loss) Reclassified to: Revenues $ 111 $ 50 $ 161 Purchased Power Expense (130 ) — (130 ) Other Operating Expense — (49 ) (49 ) Fuel Expense (34 ) — (34 ) |
Reconciliation of changes in the fair value of certain contracts that are deferred | The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2017 and 2016 . Changes in the value of these contracts are deferred for future recovery from (or credit to) customers: Year Ended December 31 Derivatives Not in a Hedging Relationship with Regulatory Offset NUGs Regulated FTRs Total (In millions) Outstanding net asset (liability) as of January 1, 2017 $ (107 ) $ 2 $ (105 ) Unrealized loss (9 ) (1 ) (10 ) Purchases — 3 3 Settlements 37 (1 ) 36 Outstanding net asset (liability) as of December 31, 2017 $ (79 ) $ 3 $ (76 ) Outstanding net asset (liability) as of January 1, 2016 $ (136 ) $ 1 $ (135 ) Unrealized loss (15 ) (3 ) (18 ) Purchases — 4 4 Settlements 44 — 44 Outstanding net asset (liability) as of December 31, 2016 $ (107 ) $ 2 $ (105 ) |
FES | |
Derivative [Line Items] | |
Fair value of derivatives instruments | The following table summarizes the fair value and classification of derivative instruments on FES' Consolidated Balance Sheets: Derivative Assets Derivative Liabilities Fair Value Fair Value December 31, December 31, December 31, December 31, (In millions) (In millions) Current Assets - Derivatives Current Liabilities - Derivatives Commodity Contracts $ 33 $ 133 Commodity Contracts $ (23 ) $ (72 ) FTRs 1 4 FTRs (1 ) (5 ) 34 137 (24 ) (77 ) Deferred Charges and Other Assets - Derivatives Noncurrent Liabilities - Other Commodity Contracts — 77 Commodity Contracts — (52 ) — 77 — (52 ) Derivative Assets $ 34 $ 214 Derivative Liabilities $ (24 ) $ (129 ) |
Offsetting assets | The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 1 (1 ) — — $ 34 $ (20 ) $ — $ 14 Derivative Liabilities Commodity contracts $ (23 ) $ 19 $ — $ (4 ) FTRs (1 ) 1 — — $ (24 ) $ 20 $ — $ (4 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 ) |
Offsetting liabilities | The following tables summarize the fair value of derivative assets and derivative liabilities on FES’ Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position: Amounts Not Offset in Consolidated Balance Sheet December 31, 2017 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 33 $ (19 ) $ — $ 14 FTRs 1 (1 ) — — $ 34 $ (20 ) $ — $ 14 Derivative Liabilities Commodity contracts $ (23 ) $ 19 $ — $ (4 ) FTRs (1 ) 1 — — $ (24 ) $ 20 $ — $ (4 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2016 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 210 $ (117 ) $ — $ 93 FTRs 4 (4 ) — — $ 214 $ (121 ) $ — $ 93 Derivative Liabilities Commodity contracts $ (124 ) $ 117 $ 1 $ (6 ) FTRs (5 ) 4 1 — $ (129 ) $ 121 $ 2 $ (6 ) |
Effect of derivative instruments on statements of income and comprehensive income | The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during 2017 , 2016 and 2015 are summarized in the following tables: Year Ended December 31 Commodity Contracts FTRs Total (In millions) 2017 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (79 ) $ 1 $ (78 ) Realized Gain (Loss) Reclassified to: Revenues $ 54 $ (4 ) $ 50 Purchased Power Expense (17 ) — (17 ) Other Operating Expense — (14 ) (14 ) Year Ended December 31 Commodity FTRs Total (In millions) 2016 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (14 ) $ 5 $ (9 ) Realized Gain (Loss) Reclassified to: Revenues $ 210 $ 8 $ 218 Purchased Power Expense (131 ) — (131 ) Other Operating Expense — (35 ) (35 ) Year Ended December 31 Commodity FTRs Total (In millions) 2015 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ 93 $ (19 ) $ 74 Realized Gain (Loss) Reclassified to: Revenues $ 111 $ 49 $ 160 Purchased Power Expense (130 ) — (130 ) Other Operating Expense — (49 ) (49 ) |
Capitalization (Tables)
Capitalization (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Capitalization, Long-term Debt and Equity [Abstract] | |
Preferred stock and preference stock authorizations | FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2017 , as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FirstEnergy 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par |
Outstanding consolidated long-term debt and other long-term obligations | The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy and FES as of December 31, 2017 and 2016 : As of December 31, 2017 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2017 2016 FirstEnergy: FMBs and secured notes - fixed rate 2018 - 2056 1.726% - 9.740% $ 5,446 $ 5,623 Secured notes - variable rate 2019 4.500% 9 10 Total FMBs and secured notes 5,455 5,633 Unsecured notes - fixed rate 2018 - 2047 2.550% - 7.700% 15,370 13,058 Unsecured notes - variable rate 2020 - 2021 3.227% 1,450 1,200 Total unsecured notes 16,820 14,258 Capital lease obligations 91 104 Unamortized debt discounts (42 ) (25 ) Unamortized debt issuance costs (113 ) (87 ) Unamortized fair value adjustments (14 ) (6 ) Currently payable long-term debt (1,082 ) (1,685 ) Total long-term debt and other long-term obligations $ 21,115 $ 18,192 FES: Secured notes - fixed rate 2018 - 2047 4.250% - 5.625% $ 612 $ 617 Secured notes - variable rate 2019 4.500% 9 10 Total secured notes 621 627 Unsecured notes - fixed rate 2019 - 2041 2.550% - 6.800% 2,215 2,373 Capital lease obligations 2 8 Unamortized debt discounts (1 ) (1 ) Unamortized debt issuance costs (14 ) (15 ) Currently payable long-term debt (524 ) (179 ) Total long-term debt and other long-term obligations $ 2,299 $ 2,813 |
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years | The following table presents scheduled debt repayments for outstanding long-term debt, excluding capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2017 . PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year FirstEnergy FES (In millions) 2018 $ 1,051 $ 515 2019 1,267 323 2020 1,281 667 2021 2,032 674 2022 1,428 284 |
Outstanding PCRBs for the next three years | The following table classifies these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs. Year FirstEnergy FES (In millions) 2018 $ 375 $ 375 2019 232 232 2020 490 490 2021 342 342 2022 284 284 |
Short-Term Borrowings and Ban52
Short-Term Borrowings and Bank Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Line Items] | |
Liquidity | FirstEnergy’s available liquidity from external sources as of January 31, 2018 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2021 $ 4,000 $ 3,740 FET (2) Revolving December 2021 1,000 1,000 Subtotal $ 5,000 $ 4,740 Cash — 358 Total $ 5,000 $ 5,098 (1) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. (2) Includes FET, ATSI, MAIT and TrAIL. |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations , as of January 31, 2018 : Borrower FirstEnergy Revolving Credit Facility Sub-Limits FET Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 4,000 $ — $ — (1) FET — 1,000 — (1) OE 500 — 500 (2) CEI 500 — 500 (2) TE 300 — 300 (2) JCP&L 600 — 500 (2) ME 300 — 500 (2) PN 300 — 300 (2) WP 200 — 200 (2) MP 500 — 500 (2) PE 150 — 150 (2) ATSI — 500 500 (2) Penn 50 — 100 (2) TrAIL — 400 400 (2) MAIT — 400 400 (2) (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool. |
Weighted average interest rates on short-term borrowings outstanding | The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2017 and 2016 , were as follows: 2017 2016 FirstEnergy 3.24 % 2.47 % |
FES | |
Short-term Debt [Line Items] | |
Liquidity | Type Commitment Available Liquidity (In millions) Two-year secured credit facility with FE $ 500 $ 500 Cash — 1 $ 500 $ 501 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Fair values of the decommissioning trust assets | The fair values of the decommissioning trust assets as of December 31, 2017 and 2016 were as follows: 2017 2016 (In millions) FirstEnergy $ 2,678 $ 2,514 FES $ 1,856 $ 1,552 |
Changes to the asset retirement obligations | The following table summarizes the changes to the ARO balances during 2017 and 2016 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2016 $ 1,410 $ 831 Liabilities settled (27 ) (18 ) Accretion 95 56 Liabilities Incurred 4 32 Balance, December 31, 2016 $ 1,482 $ 901 Changes in timing of estimated cash flows (1) 944 944 Liabilities settled (12 ) (11 ) Accretion 101 62 Liabilities Incurred — 49 Balance, December 31, 2017 $ 2,515 $ 1,945 (1) See Note 2, "Asset Sales and Impairments" for further discussion. |
Commitments, Guarantees and C54
Commitments, Guarantees and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of Guarantor Obligations | The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2017 : Potential Collateral Obligations FES AE Supply Regulated FE Corp Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 4 $ 1 $ — $ — $ 5 Upon Further Downgrade — — 41 — 41 Surety Bonds (Collateralized Amount) (1) 16 1 107 237 361 Total Exposure from Contractual Obligations $ 20 $ 2 $ 148 $ 237 $ 407 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. |
Transactions With Affiliated 55
Transactions With Affiliated Companies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Transactions With Affiliated Companies [Abstract] | |
Affiliated Company Transactions | The primary affiliated company transactions for FES during the three years ended December 31, 2017 are as follows: FES 2017 2016 2015 (In millions) Revenues: Electric sales to affiliates $ 366 $ 459 $ 666 Other 11 11 14 Expenses: Purchased power from affiliates 201 622 353 Fuel 4 4 1 Support services 775 748 705 Investment Income: Interest income from FE 13 2 2 Interest Expense: Interest expense to affiliates — 5 4 Interest expense to FE 19 2 3 |
Supplemental Guarantor Inform56
Supplemental Guarantor Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Guarantor Information [Abstract] | |
Condensed Consolidating Statements of Income and Comprehensive Income | FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 3,037 $ 1,062 $ 1,362 $ (2,363 ) $ 3,098 OPERATING EXPENSES: Fuel — 390 209 — 599 Purchased power from affiliates 2,488 — 76 (2,363 ) 201 Purchased power from non-affiliates 628 — — — 628 Other operating expenses 322 490 653 49 1,514 Pension and OPEB mark-to-market adjustment (12 ) (30 ) 66 — 24 Provision for depreciation 12 32 67 (2 ) 109 General taxes 20 21 17 — 58 Impairment of assets and related charges — — 2,031 — 2,031 Total operating expenses 3,458 903 3,119 (2,316 ) 5,164 OPERATING INCOME (LOSS) (421 ) 159 (1,757 ) (47 ) (2,066 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (1,864 ) 39 113 1,806 94 Miscellaneous income 1 1 5 — 7 Interest expense — affiliates (75 ) (11 ) (1 ) 68 (19 ) Interest expense — other (46 ) (104 ) (44 ) 56 (138 ) Capitalized interest — 2 24 — 26 Total other income (expense) (1,984 ) (73 ) 97 1,930 (30 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (2,405 ) 86 (1,660 ) 1,883 (2,096 ) INCOME TAXES (BENEFITS) (14 ) 360 (78 ) 27 295 NET INCOME (LOSS) $ (2,391 ) $ (274 ) $ (1,582 ) $ 1,856 $ (2,391 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (2,391 ) $ (274 ) $ (1,582 ) $ 1,856 $ (2,391 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (14 ) (13 ) — 13 (14 ) Amortized gain on derivative hedges 2 — — — 2 Change in unrealized gain on available-for-sale securities 30 — 30 (30 ) 30 Other comprehensive income (loss) 18 (13 ) 30 (17 ) 18 Income taxes (benefits) on other comprehensive income (loss) 6 (5 ) 10 (5 ) 6 Other comprehensive income (loss), net of tax 12 (8 ) 20 (12 ) 12 COMPREHENSIVE INCOME (LOSS) $ (2,379 ) $ (282 ) $ (1,562 ) $ 1,844 $ (2,379 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 4,242 $ 1,739 $ 2,004 $ (3,587 ) $ 4,398 OPERATING EXPENSES: Fuel — 582 198 — 780 Purchased power from affiliates 4,024 — 187 (3,587 ) 624 Purchased power from non-affiliates 1,020 — — — 1,020 Other operating expenses 310 286 632 49 1,277 Pension and OPEB mark-to-market adjustment (1 ) (4 ) 53 — 48 Provision for depreciation 13 120 206 (3 ) 336 General taxes 31 30 27 — 88 Impairment of assets and related charges 39 3,937 4,729 (83 ) 8,622 Total operating expenses 5,436 4,951 6,032 (3,624 ) 12,795 OPERATING LOSS (1,194 ) (3,212 ) (4,028 ) 37 (8,397 ) OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees (4,585 ) 30 84 4,538 67 Miscellaneous income 4 3 — — 7 Interest expense — affiliates (50 ) (10 ) (4 ) 57 (7 ) Interest expense — other (55 ) (105 ) (44 ) 57 (147 ) Capitalized interest — 8 26 — 34 Total other income (expense) (4,686 ) (74 ) 62 4,652 (46 ) LOSS BEFORE INCOME TAX BENEFITS (5,880 ) (3,286 ) (3,966 ) 4,689 (8,443 ) INCOME TAX BENEFITS (425 ) (1,169 ) (1,429 ) 35 (2,988 ) NET LOSS $ (5,455 ) $ (2,117 ) $ (2,537 ) $ 4,654 $ (5,455 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET LOSS $ (5,455 ) $ (2,117 ) $ (2,537 ) $ 4,654 $ (5,455 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (14 ) (14 ) — 14 (14 ) Amortized gain on derivative hedges — — — — — Change in unrealized gain on available-for-sale securities 52 — 52 (52 ) 52 Other comprehensive income (loss) 38 (14 ) 52 (38 ) 38 Income taxes (benefits) on other comprehensive income (loss) 15 (5 ) 20 (15 ) 15 Other comprehensive income (loss), net of tax 23 (9 ) 32 (23 ) 23 COMPREHENSIVE LOSS $ (5,432 ) $ (2,126 ) $ (2,505 ) $ 4,631 $ (5,432 ) FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME REVENUES $ 4,824 $ 1,801 $ 2,138 $ (3,758 ) $ 5,005 OPERATING EXPENSES: Fuel — 679 192 — 871 Purchased power from affiliates 3,826 — 285 (3,758 ) 353 Purchased power from non-affiliates 1,684 — — — 1,684 Other operating expenses 378 273 608 49 1,308 Pension and OPEB mark-to-market adjustment (8 ) 10 55 — 57 Provision for depreciation 12 124 191 (3 ) 324 General taxes 45 26 27 — 98 Impairment of assets and related charges 21 2 10 — 33 Total operating expenses 5,958 1,114 1,368 (3,712 ) 4,728 OPERATING INCOME (LOSS) (1,134 ) 687 770 (46 ) 277 OTHER INCOME (EXPENSE): Investment income (loss), including net income (loss) from equity investees 844 17 (5 ) (870 ) (14 ) Miscellaneous income 1 2 — — 3 Interest expense — affiliates (29 ) (8 ) (4 ) 34 (7 ) Interest expense — other (52 ) (104 ) (49 ) 58 (147 ) Capitalized interest — 6 29 — 35 Total other income (expense) 764 (87 ) (29 ) (778 ) (130 ) INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) (370 ) 600 741 (824 ) 147 INCOME TAXES (BENEFITS) (452 ) 224 278 15 65 NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 STATEMENTS OF COMPREHENSIVE INCOME NET INCOME $ 82 $ 376 $ 463 $ (839 ) $ 82 OTHER COMPREHENSIVE LOSS: Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (3 ) — — — (3 ) Change in unrealized gain on available-for-sale securities (9 ) — (8 ) 8 (9 ) Other comprehensive loss (18 ) (5 ) (8 ) 13 (18 ) Income tax benefits on other comprehensive loss (7 ) (2 ) (3 ) 5 (7 ) Other comprehensive loss, net of tax (11 ) (3 ) (5 ) 8 (11 ) COMPREHENSIVE INCOME $ 71 $ 373 $ 458 $ (831 ) $ 71 |
Condensed Consolidating Balance Sheets | FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2017 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 1 $ — $ — $ 1 Receivables- Customers 181 — — — 181 Affiliated companies 210 80 260 (326 ) 224 Other 13 8 — — 21 Notes receivable from affiliated companies 366 1,744 1,512 (3,622 ) — Materials and supplies 41 142 — — 183 Derivatives 34 — — — 34 Collateral 105 25 — — 130 Prepaid taxes and other 10 12 — — 22 960 2,012 1,772 (3,948 ) 796 PROPERTY, PLANT AND EQUIPMENT: In service 122 2,646 8 (281 ) 2,495 Less — Accumulated provision for depreciation 65 1,947 — (189 ) 1,823 57 699 8 (92 ) 672 Construction work in progress 3 19 — — 22 60 718 8 (92 ) 694 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,856 — 1,856 Investment in affiliated companies 1,153 — — (1,153 ) — Other — 9 — — 9 1,153 9 1,856 (1,153 ) 1,865 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 267 790 890 (193 ) 1,754 Property taxes — 9 16 — 25 Other 45 310 — 25 380 312 1,109 906 (168 ) 2,159 $ 2,485 $ 3,848 $ 4,542 $ (5,361 ) $ 5,514 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 438 $ 114 $ (28 ) $ 524 Short-term borrowings - affiliated companies 3,325 402 — (3,622 ) 105 Accounts payable- Affiliated companies 320 60 194 (319 ) 255 Other 22 83 — — 105 Accrued taxes 52 12 21 (13 ) 72 Derivatives 22 2 — — 24 Other 44 73 11 41 169 3,785 1,070 340 (3,941 ) 1,254 CAPITALIZATION: Total equity (deficit) (2,070 ) 547 528 (1,075 ) (2,070 ) Long-term debt and other long-term obligations 691 1,666 1,007 (1,065 ) 2,299 (1,379 ) 2,213 1,535 (2,140 ) 229 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 723 723 Retirement benefits 28 125 — — 153 Asset retirement obligations — 187 1,758 — 1,945 Other 51 253 909 (3 ) 1,210 79 565 2,667 720 4,031 $ 2,485 $ 3,848 $ 4,542 $ (5,361 ) $ 5,514 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2016 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 213 — — — 213 Affiliated companies 332 315 417 (612 ) 452 Other 17 2 8 — 27 Notes receivable from affiliated companies 501 1,585 1,294 (3,351 ) 29 Materials and supplies 45 142 80 — 267 Derivatives 137 — — — 137 Collateral 157 — — — 157 Prepaid taxes and other 38 24 1 — 63 1,440 2,070 1,800 (3,963 ) 1,347 PROPERTY, PLANT AND EQUIPMENT: In service 120 2,524 4,703 (290 ) 7,057 Less — Accumulated provision for depreciation 52 1,920 4,144 (187 ) 5,929 68 604 559 (103 ) 1,128 Construction work in progress 2 67 358 — 427 70 671 917 (103 ) 1,555 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,552 — 1,552 Investment in affiliated companies 2,923 — — (2,923 ) — Other — 9 1 — 10 2,923 9 1,553 (2,923 ) 1,562 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 395 1,271 883 (270 ) 2,279 Property taxes — 12 28 — 40 Derivatives 77 — — — 77 Other 33 327 — 21 381 505 1,610 911 (249 ) 2,777 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 200 $ 5 $ (26 ) $ 179 Short-term borrowings - affiliated companies 2,969 483 — (3,351 ) 101 Accounts payable- Affiliated companies 743 107 406 (706 ) 550 Other 17 93 — — 110 Accrued taxes 50 48 61 (16 ) 143 Derivatives 71 6 — — 77 Other 56 54 10 36 156 3,906 991 482 (4,063 ) 1,316 CAPITALIZATION: Total equity 218 828 2,006 (2,834 ) 218 Long-term debt and other long-term obligations 691 2,093 1,120 (1,091 ) 2,813 909 2,921 3,126 (3,925 ) 3,031 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 757 757 Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Other 98 88 860 (7 ) 1,039 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 |
Condensed Consolidating Statements of Cash Flows | FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2017 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (485 ) $ 516 $ 722 $ (26 ) $ 727 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Short-term borrowings, net 356 (81 ) — (271 ) 4 Redemptions and Repayments- Long-term debt — (184 ) (5 ) 26 (163 ) Other (1 ) (6 ) — — (7 ) Net cash provided from (used for) financing activities 355 (271 ) (5 ) (245 ) (166 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (2 ) (88 ) (185 ) — (275 ) Nuclear fuel — — (254 ) — (254 ) Sales of investment securities held in trusts — — 940 — 940 Purchases of investment securities held in trusts — — (999 ) — (999 ) Cash Investments (3 ) — — — (3 ) Loans to affiliated companies, net 135 (158 ) (219 ) 271 29 Net cash provided from (used for) investing activities 130 (246 ) (717 ) 271 (562 ) Net change in cash and cash equivalents — (1 ) — — (1 ) Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 1 $ — $ — $ 1 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2016 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (842 ) $ 550 $ 1,103 $ (25 ) $ 786 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 186 285 — 471 Short-term borrowings, net 948 94 — (941 ) 101 Redemptions and Repayments- Long-term debt — (224 ) (308 ) 25 (507 ) Other — (7 ) (2 ) — (9 ) Net cash provided from (used for) financing activities 948 49 (25 ) (916 ) 56 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (30 ) (224 ) (292 ) — (546 ) Nuclear fuel — — (232 ) — (232 ) Proceeds from asset sales 9 — — — 9 Sales of investment securities held in trusts — — 717 — 717 Purchases of investment securities held in trusts — — (783 ) — (783 ) Cash investments 10 — — — 10 Loans to affiliated companies, net (95 ) (376 ) (488 ) 941 (18 ) Other — 1 — — 1 Net cash used for investing activities (106 ) (599 ) (1,078 ) 941 (842 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2015 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (637 ) $ 552 $ 1,261 $ (24 ) $ 1,152 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 45 296 — 341 Short-term borrowings, net 796 67 — (863 ) — Redemptions and Repayments- Long-term debt (17 ) (70 ) (348 ) 24 (411 ) Short-term borrowings, net — — (28 ) (98 ) (126 ) Common stock dividend payment (70 ) — — — (70 ) Other — (6 ) (1 ) — (7 ) Net cash provided from (used for) financing activities 709 36 (81 ) (937 ) (273 ) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (5 ) (223 ) (399 ) — (627 ) Nuclear fuel — — (190 ) — (190 ) Proceeds from asset sales 10 3 — — 13 Sales of investment securities held in trusts — — 733 — 733 Purchases of investment securities held in trusts — — (791 ) — (791 ) Cash investments (10 ) — — — (10 ) Loans to affiliated companies, net (67 ) (372 ) (533 ) 961 (11 ) Other — 4 — — 4 Net cash used for investing activities (72 ) (588 ) (1,180 ) 961 (879 ) Net change in cash and cash equivalents — — — — — Cash and cash equivalents at beginning of period — 2 — — 2 Cash and cash equivalents at end of period $ — $ 2 $ — $ — $ 2 |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Financial Information | Segment Financial Information For the Years Ended December 31 Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2017 External revenues $ 9,734 $ 1,325 $ 3,143 $ — $ (185 ) $ 14,017 Internal revenues — — 386 — (386 ) — Total revenues 9,734 1,325 3,529 — (571 ) 14,017 Depreciation 724 224 118 72 — 1,138 Amortization of regulatory assets, net 292 16 — — — 308 Impairment of assets and related charges — 41 2,365 — — 2,406 Investment income 54 — 81 11 (48 ) 98 Interest expense 535 156 179 308 — 1,178 Income taxes (benefits) 580 205 155 (45 ) — 895 Net income (loss) 916 336 (2,641 ) (335 ) — (1,724 ) Total assets 27,730 9,525 4,339 663 — 42,257 Total goodwill 5,004 614 — — — 5,618 Property additions 1,191 1,030 317 49 — 2,587 2016 External revenues $ 9,629 $ 1,144 $ 4,070 $ — $ (281 ) $ 14,562 Internal revenues — — 479 — (479 ) — Total revenues 9,629 1,144 4,549 — (760 ) 14,562 Depreciation 676 187 387 63 — 1,313 Amortization of regulatory assets, net 290 7 — — — 297 Impairment of assets and related charges — — 10,665 — — 10,665 Investment income 49 — 66 10 (41 ) 84 Interest expense 586 158 194 219 — 1,157 Income taxes (benefits) 375 187 (3,498 ) (119 ) — (3,055 ) Net income (loss) 651 331 (6,919 ) (240 ) — (6,177 ) Total assets 27,702 8,755 5,952 739 — 43,148 Total goodwill 5,004 614 — — — 5,618 Property additions 1,063 1,101 619 52 — 2,835 2015 External revenues $ 9,582 $ 1,046 $ 4,698 $ — $ (300 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,582 1,046 5,384 — (986 ) 15,026 Depreciation 664 164 394 60 — 1,282 Amortization of regulatory assets, net 165 7 — — — 172 Impairment of assets and related charges 8 — 34 — — 42 Investment income (loss) 42 — (16 ) (9 ) (39 ) (22 ) Impairment of equity method investment — — — 362 — 362 Interest expense 600 147 192 193 — 1,132 Income taxes (benefits) 325 191 50 (251 ) — 315 Net income (loss) 588 328 89 (427 ) — 578 Total assets 27,390 7,800 16,027 877 — 52,094 Total goodwill 5,092 526 800 — — 6,418 Property additions 1,040 1,020 588 56 — 2,704 |
Summary of Quarterly Financia58
Summary of Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Data [Abstract] | |
Schedule of Quarterly Financial Information | The following summarizes certain consolidated operating results by quarter for 2017 and 2016 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2017 2016 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,442 $ 3,714 $ 3,309 $ 3,552 $ 3,375 $ 3,917 $ 3,401 $ 3,869 Other operating expense 1,195 940 956 1,141 1,021 950 963 917 Pension and OPEB mark-to-market adjustment 141 — — — 147 — — — Provision for depreciation 293 289 281 275 339 311 334 329 Impairment of assets and related charges 2,244 31 131 — 9,218 — 1,447 — Operating Income (Loss) (1,830 ) 884 544 574 (8,924 ) 861 (975 ) 776 Income (loss) before income taxes (benefits) (2,086 ) 635 291 331 (9,185 ) 631 (1,219 ) 541 Income taxes (benefits) 413 239 117 126 (3,389 ) 251 (130 ) 213 Net Income (Loss) (2,499 ) 396 174 205 (5,796 ) 380 (1,089 ) 328 Earnings (loss) per share of common stock- (1) Basic - Earnings (losses) Available to FirstEnergy Corp. (5.62 ) 0.89 0.39 0.46 (13.44 ) 0.89 (2.56 ) 0.78 Diluted - Earnings (losses) Available to FirstEnergy Corp. (5.62 ) 0.89 0.39 0.46 (13.44 ) 0.89 (2.56 ) 0.77 (1) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 5, "Stock-Based Compensation Plans," for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) 2017 2016 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 700 $ 743 $ 741 $ 914 $ 997 $ 1,100 $ 1,102 $ 1,199 Other operating expense 419 291 286 518 352 316 369 240 Pension and OPEB mark-to-market adjustment 24 — — — 48 — — — Provision for depreciation 29 28 27 25 86 83 84 83 Impairment of assets and related charges 2,031 — — — 8,082 — 540 — Operating Income (Loss) (2,112 ) 102 61 (117 ) (8,153 ) 101 (571 ) 226 Income (loss) from continuing operations before income taxes (benefits) (2,125 ) 108 42 (121 ) (8,171 ) 96 (581 ) 213 Income taxes (benefits) 281 32 23 (41 ) (2,983 ) 56 (143 ) 82 Net Income (Loss) (2,406 ) 76 19 (80 ) (5,188 ) 40 (438 ) 131 |
Organization and Basis of Pre59
Organization and Basis of Presentation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | $ 40 | $ 1,014 |
Regulatory Liability | (2,720) | (157) |
Net Regulatory Assets (Liabilities) included on the Consolidated Balance Sheets | (2,680) | 857 |
Increase (Decrease) | (3,537) | |
Regulatory transition costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 46 | 90 |
Increase (Decrease) | (44) | |
Customer receivables (payables) for future income taxes | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | (2,765) | 468 |
Increase (Decrease) | (3,233) | |
Nuclear decommissioning and spent fuel disposal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (323) | (304) |
Increase (Decrease) | (19) | |
Asset removal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (774) | (770) |
Increase (Decrease) | (4) | |
Deferred transmission costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 187 | 122 |
Increase (Decrease) | 65 | |
Deferred generation costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 198 | 331 |
Increase (Decrease) | (133) | |
Deferred distribution costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 258 | 296 |
Increase (Decrease) | (38) | |
Contract valuations | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 118 | 153 |
Increase (Decrease) | (35) | |
Storm-related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 329 | 397 |
Increase (Decrease) | (68) | |
Other | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 46 | $ 74 |
Increase (Decrease) | $ (28) |
Organization and Basis of Pre60
Organization and Basis of Presentation (Details 1) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Receivables from customers | ||
Customers | $ 1,463 | $ 1,440 |
FES | ||
Receivables from customers | ||
Customers | 181 | 213 |
Billed | ||
Receivables from customers | ||
Customers | 860 | 833 |
Billed | FES | ||
Receivables from customers | ||
Customers | 106 | 123 |
Unbilled | ||
Receivables from customers | ||
Customers | 603 | 607 |
Unbilled | FES | ||
Receivables from customers | ||
Customers | $ 75 | $ 90 |
Organization and Basis of Pre61
Organization and Basis of Presentation (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Basic and Diluted Earnings per Share of Common Stock | |||||||||||
Net income (loss) | $ (2,499) | $ 396 | $ 174 | $ 205 | $ (5,796) | $ 380 | $ (1,089) | $ 328 | $ (1,724) | $ (6,177) | $ 578 |
Weighted average number of basic shares outstanding | 444 | 426 | 422 | ||||||||
Assumed exercise of dilutive stock options and awards (in shares) | 0 | 0 | 2 | ||||||||
Weighted average number of diluted shares outstanding | 444 | 426 | 424 | ||||||||
Earnings (loss) per share: | |||||||||||
Basic earnings (loss) per share of common stock, in dollars per share | $ (5.62) | $ 0.89 | $ 0.39 | $ 0.46 | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.78 | $ (3.88) | $ (14.49) | $ 1.37 |
Diluted earnings (loss) per share of common stock, in dollars per share | $ (5.62) | $ 0.89 | $ 0.39 | $ 0.46 | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.77 | $ (3.88) | $ (14.49) | $ 1.37 |
Shares excluded from the calculation of diluted shares outstanding, in shares | 3 | 3 | 1 |
Organization and Basis of Pre62
Organization and Basis of Presentation (Details 3) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment | ||
In Service | $ 39,778 | $ 43,767 |
Accumulated Depreciation | (11,925) | (15,731) |
Property, plant and equipment in service net of accumulated provision for depreciation | 27,853 | 28,036 |
Construction Work in Progress | 1,026 | 1,351 |
Total net property, plant and equipment | 28,879 | 29,387 |
Capital leased assets | 238 | 244 |
Regulated Distribution | ||
Property, Plant and Equipment | ||
In Service | 25,950 | 24,979 |
Accumulated Depreciation | (7,503) | (7,169) |
Property, plant and equipment in service net of accumulated provision for depreciation | 18,447 | 17,810 |
Construction Work in Progress | 469 | 472 |
Total net property, plant and equipment | 18,916 | 18,282 |
Regulated Transmission | ||
Property, Plant and Equipment | ||
In Service | 10,102 | 9,342 |
Accumulated Depreciation | (2,055) | (1,948) |
Property, plant and equipment in service net of accumulated provision for depreciation | 8,047 | 7,394 |
Construction Work in Progress | 480 | 383 |
Total net property, plant and equipment | 8,527 | 7,777 |
Competitive Energy Services | ||
Property, Plant and Equipment | ||
In Service | 2,902 | 8,680 |
Accumulated Depreciation | (1,958) | (6,267) |
Property, plant and equipment in service net of accumulated provision for depreciation | 944 | 2,413 |
Construction Work in Progress | 28 | 453 |
Total net property, plant and equipment | 972 | 2,866 |
Corporate/Other | ||
Property, Plant and Equipment | ||
In Service | 824 | 766 |
Accumulated Depreciation | (409) | (347) |
Property, plant and equipment in service net of accumulated provision for depreciation | 415 | 419 |
Construction Work in Progress | 49 | 43 |
Total net property, plant and equipment | 464 | 462 |
FES | ||
Property, Plant and Equipment | ||
In Service | 2,495 | 7,057 |
Accumulated Depreciation | (1,823) | (5,929) |
Property, plant and equipment in service net of accumulated provision for depreciation | 672 | 1,128 |
Construction Work in Progress | 22 | 427 |
Total net property, plant and equipment | 694 | 1,555 |
FES | Fossil Generation | ||
Property, Plant and Equipment | ||
In Service | 2,344 | 2,212 |
Accumulated Depreciation | (1,743) | (1,720) |
Property, plant and equipment in service net of accumulated provision for depreciation | 601 | 492 |
Construction Work in Progress | 19 | 63 |
Total net property, plant and equipment | 620 | 555 |
FES | Nuclear Generation | ||
Property, Plant and Equipment | ||
In Service | 2,065 | |
Accumulated Depreciation | (1,723) | |
Property, plant and equipment in service net of accumulated provision for depreciation | 342 | |
Construction Work in Progress | 118 | |
Total net property, plant and equipment | 460 | |
FES | Nuclear Fuel | ||
Property, Plant and Equipment | ||
In Service | 2,637 | |
Accumulated Depreciation | (2,418) | |
Property, plant and equipment in service net of accumulated provision for depreciation | 219 | |
Construction Work in Progress | 241 | |
Total net property, plant and equipment | 460 | |
FES | Other | ||
Property, Plant and Equipment | ||
In Service | 151 | 143 |
Accumulated Depreciation | (80) | (68) |
Property, plant and equipment in service net of accumulated provision for depreciation | 71 | 75 |
Construction Work in Progress | 3 | 5 |
Total net property, plant and equipment | $ 74 | $ 80 |
Organization and Basis of Pre63
Organization and Basis of Presentation (Details 4) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Annual Composite Depreciation Rate | |||
Annual Composite Depreciation Rate (percent) | 2.40% | 2.50% | 2.50% |
FES | |||
Annual Composite Depreciation Rate | |||
Annual Composite Depreciation Rate (percent) | 4.40% | 3.30% | 3.20% |
Organization and Basis of Pre64
Organization and Basis of Presentation (Details 5) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Goodwill [Line Items] | |||
Goodwill | $ 5,618 | $ 5,618 | $ 6,418 |
Regulated Distribution | |||
Goodwill [Line Items] | |||
Goodwill | 5,004 | $ 5,004 | $ 5,092 |
Regulated Transmission | |||
Goodwill [Line Items] | |||
Goodwill | $ 614 |
Organization and Basis of Pre65
Organization and Basis of Presentation (Details Textuals) customer in Millions | Apr. 02, 2018USD ($) | Dec. 13, 2017USD ($) | Oct. 20, 2017 | Aug. 30, 2017USD ($)Natural_gas_plant | Jul. 22, 2016MW | Aug. 31, 2017USD ($)Natural_gas_plantMW | Jan. 31, 2017USD ($)MW | Dec. 31, 2017USD ($)transmission_centerMW | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($)customertransmission_centercompanymiMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jan. 31, 2018USD ($) | Mar. 06, 2017USD ($)MW | Jan. 18, 2017 |
Regulatory Assets [Line Items] | ||||||||||||||||||
Aggregate amount of capacity (in MWs) | MW | 16,000 | |||||||||||||||||
Length of transmission lines | mi | 24,500 | |||||||||||||||||
Number of regional transmission centers | transmission_center | 2 | 2 | ||||||||||||||||
Impairment of assets | $ 42,000,000 | |||||||||||||||||
Regulatory assets that do not earn a current return | $ 7,000,000 | $ 153,000,000 | $ 7,000,000 | $ 153,000,000 | ||||||||||||||
Capitalized financing costs | 35,000,000 | 37,000,000 | 49,000,000 | |||||||||||||||
Interest costs capitalized | 44,000,000 | 66,000,000 | 68,000,000 | |||||||||||||||
Property, plant and equipment | $ 28,879,000,000 | 29,387,000,000 | 28,879,000,000 | 29,387,000,000 | ||||||||||||||
Other than temporary impairments | 13,000,000 | 21,000,000 | 102,000,000 | |||||||||||||||
Impairments of long-lived assets | 2,406,000,000 | 10,665,000,000 | 42,000,000 | |||||||||||||||
Net cash used for financing activities | (702,000,000) | (34,000,000) | (292,000,000) | |||||||||||||||
Net cash provided by (used in) operating activities | $ 3,808,000,000 | 3,383,000,000 | 3,460,000,000 | |||||||||||||||
Regulated Distribution | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Number of existing utility operating companies | company | 10 | |||||||||||||||||
Number of customers served by utility operating companies | customer | 6 | |||||||||||||||||
Plant generation capacity (in MW's) | MW | 3,790 | 3,790 | ||||||||||||||||
Impairment of assets | 8,000,000 | |||||||||||||||||
Property, plant and equipment, net | $ 2,100,000,000 | $ 2,100,000,000 | ||||||||||||||||
Property, plant and equipment | $ 18,916,000,000 | 18,282,000,000 | $ 18,916,000,000 | 18,282,000,000 | ||||||||||||||
Competitive Energy Services | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 12,303 | 12,303 | ||||||||||||||||
Impairment of assets | 9,218,000,000 | 34,000,000 | ||||||||||||||||
Impairment of assets | $ 193,000,000 | |||||||||||||||||
Property, plant and equipment | $ 972,000,000 | 2,866,000,000 | $ 972,000,000 | 2,866,000,000 | ||||||||||||||
Bath County, Virginia | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 3,003 | 3,003 | ||||||||||||||||
MP | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Ownership interest (percent) | 41.00% | |||||||||||||||||
Virginia Electric and Power Company | Bath County, Virginia | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Proportionate ownership share (percent) | 60.00% | 60.00% | ||||||||||||||||
FES | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Impairment of assets | $ 2,045,000,000 | 33,000,000 | ||||||||||||||||
Interest costs capitalized | $ 26,000,000 | 34,000,000 | 35,000,000 | |||||||||||||||
Property, plant and equipment | 694,000,000 | 1,555,000,000 | 694,000,000 | 1,555,000,000 | ||||||||||||||
Other than temporary impairments | 13,000,000 | 19,000,000 | 90,000,000 | |||||||||||||||
Impairments of long-lived assets | 2,031,000,000 | 8,622,000,000 | 33,000,000 | |||||||||||||||
Net cash used for financing activities | (166,000,000) | 56,000,000 | (273,000,000) | |||||||||||||||
Net cash provided by (used in) operating activities | $ 727,000,000 | 786,000,000 | 1,152,000,000 | |||||||||||||||
FES | Competitive Energy Services | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Impairment of assets | 2,000,000,000 | 8,082,000,000 | ||||||||||||||||
Impairment of assets | $ 2,000,000,000 | |||||||||||||||||
AGC | Bath County, Virginia | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,200 | 1,200 | ||||||||||||||||
Proportionate ownership share (percent) | 40.00% | 40.00% | ||||||||||||||||
Property, plant and equipment | $ 531,000,000 | $ 531,000,000 | ||||||||||||||||
AGC | Bath County, Virginia | Competitive Energy Services | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Property, plant and equipment | $ 365,000,000 | $ 365,000,000 | ||||||||||||||||
Signal Peak | Global Holding | FEV | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Ownership interest (percent) | 33.33% | 33.33% | ||||||||||||||||
Impairments of long-lived assets | 362,000,000 | |||||||||||||||||
Bay Shore Unit 1 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant capacity (in MW's) | MW | 136 | |||||||||||||||||
Sammis Power Plant Units 1-4 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant capacity (in MW's) | MW | 720 | |||||||||||||||||
Pleasants Power Station | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,300 | |||||||||||||||||
Assets purchase agreement consideration to be received | $ 195,000,000 | |||||||||||||||||
Impairment of assets | $ 120,000,000 | |||||||||||||||||
Forecast | FES | Competitive Energy Services | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Debt that needs to be refinanced | $ 515,000,000 | |||||||||||||||||
Principal payment | $ 100,000,000 | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,615 | 756 | 756 | |||||||||||||||
Cash purchase price | $ 825,000,000 | $ 825,000,000 | ||||||||||||||||
Plant capacity (in MW's) | MW | 1,615 | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | AE Supply | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Number of gas generating plants | Natural_gas_plant | 4 | 4 | ||||||||||||||||
Discharge of note indenture | $ 305,000,000 | |||||||||||||||||
Make-whole premiums | $ 95,000,000 | |||||||||||||||||
Ownership interest (percent) | 59.00% | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | AE Supply | Bath County, Virginia | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Proportionate ownership share (percent) | 23.75% | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | AGC | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Plant ownership percentage | 59.00% | 59.00% | 59.00% | |||||||||||||||
Make-whole premiums | $ 95,000,000 | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | Natural Gas Generating Plants | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Cash purchase price | $ 388,000,000 | |||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | Forecast | Bath County Hydroelectric Power Station and Buchanan Generating Facility | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Cash purchase price | $ 375,000,000 | |||||||||||||||||
Subsequent Event | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | |||||||||||||||||
Subsequent Event | FES | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | |||||||||||||||||
Line of Credit | Revolving Credit Facility | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | 500,000,000 | 5,000,000,000 | 500,000,000 | ||||||||||||||
Line of Credit | Revolving Credit Facility | FES | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | 500,000,000 | ||||||||||||||||
Line of Credit | Revolving Credit Facility | Subsequent Event | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | 5,000,000,000 | |||||||||||||||||
Line of Credit | Revolving Credit Facility | Subsequent Event | FES | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | |||||||||||||||||
Utilization of Accelerated Useful Life | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Out-of period adjustment | $ 21,000,000 | 19,000,000 | ||||||||||||||||
Accounting Standards Update 2016-09 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Net cash used for financing activities | 12,000,000 | 13,000,000 | ||||||||||||||||
Net cash provided by (used in) operating activities | (12,000,000) | (13,000,000) | ||||||||||||||||
Accounting Standards Update 2017-07 | Pro Forma | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Reclassification of non-service costs | 62,000,000 | |||||||||||||||||
Retained Earnings (Accumulated Deficit) | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Share-based compensation accounting change (Note 1) | (6,000,000) | (6,000,000) | ||||||||||||||||
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-09 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Share-based compensation accounting change (Note 1) | $ 6,000,000 | 6,000,000 | ||||||||||||||||
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-01 | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Share-based compensation accounting change (Note 1) | 115,000,000 | 115,000,000 | ||||||||||||||||
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-01 | FES | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Share-based compensation accounting change (Note 1) | $ 115,000,000 | $ 115,000,000 | ||||||||||||||||
Deferred Purchased Power and Fuel Costs | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Prior period reclassification adjustment | (30,000,000) | (105,000,000) | ||||||||||||||||
Amortization of Regulatory Assets, Net | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Prior period reclassification adjustment | $ 30,000,000 | $ 105,000,000 | ||||||||||||||||
PCRB | Purchase Agreement with Subsidiary of LS Power | AE Supply | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Discharge of note indenture | $ 142,000,000 | |||||||||||||||||
Senior Notes | Purchase Agreement with Subsidiary of LS Power | AGC | ||||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||||
Discharge of note indenture | $ 100,000,000 |
Asset Sales and Impairments (De
Asset Sales and Impairments (Details 1) | Dec. 13, 2017USD ($) | Oct. 20, 2017 | Aug. 30, 2017USD ($)limited_guarantyNatural_gas_plant | Jul. 22, 2016MW | Aug. 31, 2017USD ($)Natural_gas_plantMW | Jan. 31, 2017USD ($)MW | Dec. 31, 2017USD ($)MW | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Jun. 30, 2018USD ($) | Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Mar. 06, 2017USD ($)MW |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | $ 42,000,000 | ||||||||||||||||||
Potential collateral obligations | $ 407,000,000 | $ 407,000,000 | |||||||||||||||||
Impairments of long-lived assets | 2,406,000,000 | $ 10,665,000,000 | 42,000,000 | ||||||||||||||||
Impairment of assets and related charges (Note 2) | $ 2,244,000,000 | $ 31,000,000 | $ 131,000,000 | $ 0 | $ 9,218,000,000 | $ 0 | $ 1,447,000,000 | $ 0 | $ 2,406,000,000 | 10,665,000,000 | 42,000,000 | ||||||||
Impairment | 800,000,000 | 800,000,000 | |||||||||||||||||
Contract Termination | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Restructuring charges | 58,000,000 | ||||||||||||||||||
CES | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | 9,218,000,000 | 34,000,000 | |||||||||||||||||
Plant generation capacity (in MW's) | MW | 12,303 | 12,303 | |||||||||||||||||
Impairment of assets | $ 193,000,000 | ||||||||||||||||||
Impairment of assets and related charges (Note 2) | 647,000,000 | $ 2,365,000,000 | $ 10,665,000,000 | 34,000,000 | |||||||||||||||
CES | Income Approach Valuation Technique | Goodwill | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Discount rate (percent) | 9.50% | ||||||||||||||||||
Terminal value of EBITDA | 7 | ||||||||||||||||||
Regulated Distribution | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | 8,000,000 | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 3,790 | 3,790 | |||||||||||||||||
Potential collateral obligations | $ 148,000,000 | $ 148,000,000 | |||||||||||||||||
Impairment of assets and related charges (Note 2) | 0 | $ 0 | 8,000,000 | ||||||||||||||||
AE Supply | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Potential collateral obligations | 2,000,000 | 2,000,000 | |||||||||||||||||
FES | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | 2,045,000,000 | 33,000,000 | |||||||||||||||||
Potential collateral obligations | 20,000,000 | 20,000,000 | |||||||||||||||||
Impairments of long-lived assets | 2,031,000,000 | 8,622,000,000 | 33,000,000 | ||||||||||||||||
Impairment of assets and related charges (Note 2) | 2,031,000,000 | 0 | $ 0 | $ 0 | 8,082,000,000 | $ 0 | 540,000,000 | $ 0 | 2,031,000,000 | 8,622,000,000 | $ 33,000,000 | ||||||||
Impairment | 23,000,000 | $ 23,000,000 | |||||||||||||||||
FES | CES | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | 2,000,000,000 | $ 8,082,000,000 | |||||||||||||||||
Potential collateral obligations | 2,000,000 | 2,000,000 | |||||||||||||||||
Impairment of assets | 2,000,000,000 | ||||||||||||||||||
Impairment of assets and related charges (Note 2) | $ 517,000,000 | ||||||||||||||||||
MAIT | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairments of long-lived assets | $ 13,000,000 | ||||||||||||||||||
Pleasants Power Station | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairment of assets | 120,000,000 | ||||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,300 | ||||||||||||||||||
Assets purchase agreement consideration to be received | $ 195,000,000 | ||||||||||||||||||
Carrying value of power station | $ 75,000,000 | $ 75,000,000 | |||||||||||||||||
Bay Shore Unit 1 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Plant capacity (in MW's) | MW | 136 | ||||||||||||||||||
Sammis Power Plant Units 1-4 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Plant capacity (in MW's) | MW | 720 | ||||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,615 | 756 | 756 | ||||||||||||||||
Plant capacity (in MW's) | MW | 1,615 | ||||||||||||||||||
Cash purchase price | $ 825,000,000 | $ 825,000,000 | |||||||||||||||||
Number of limited guaranties | limited_guaranty | 2 | ||||||||||||||||||
Term of guaranties | 3 years | ||||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | AE Supply | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Number of gas generating plants | Natural_gas_plant | 4 | 4 | |||||||||||||||||
Discharge of note indenture | $ 305,000,000 | ||||||||||||||||||
Make-whole premiums | $ 95,000,000 | ||||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | AGC | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Plant ownership percentage | 59.00% | 59.00% | 59.00% | ||||||||||||||||
Make-whole premiums | 95,000,000 | ||||||||||||||||||
Purchase Agreement with Subsidiary of LS Power | Natural Gas Generating Plants | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Cash purchase price | $ 388,000,000 | ||||||||||||||||||
Held-for-sale | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Assets held-for-sale | $ 354,000,000 | 354,000,000 | |||||||||||||||||
Investments | 19,000,000 | 19,000,000 | |||||||||||||||||
Materials and supplies inventory | 2,000,000 | 2,000,000 | |||||||||||||||||
Forecast | Purchase Agreement with Subsidiary of LS Power | Bath County Hydroelectric Power Station and Buchanan Generating Facility | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Cash purchase price | $ 375,000,000 | ||||||||||||||||||
FE | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Potential collateral obligations | 237,000,000 | $ 237,000,000 | |||||||||||||||||
FE | Purchase Agreement with Subsidiary of LS Power | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Potential collateral obligations | $ 555,000,000 | ||||||||||||||||||
Purchase Agreement Guarantee, Breaches of Covenants and Indebtedness | FE | Purchase Agreement with Subsidiary of LS Power | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Term of guaranties | 3 years | ||||||||||||||||||
Potential collateral obligations | $ 463,000,000 | ||||||||||||||||||
Purchase Agreement Guarantee, Breaches of Non-fundamental Representations | FE | Purchase Agreement with Subsidiary of LS Power | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Potential collateral obligations | $ 92,000,000 | ||||||||||||||||||
Senior Notes | Purchase Agreement with Subsidiary of LS Power | AGC | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Discharge of note indenture | $ 100,000,000 | ||||||||||||||||||
PCRB | Purchase Agreement with Subsidiary of LS Power | AE Supply | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Discharge of note indenture | $ 142,000,000 | ||||||||||||||||||
FERC | JCP&L | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||||||||||||||||
Impairments of long-lived assets | $ 28,000,000 |
Asset Sales and Impairments (67
Asset Sales and Impairments (Details 2) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2017 | Dec. 31, 2015 | |
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | $ 42 | |
FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | $ 2,045 | $ 33 |
FES | Nuclear generation assets | Beaver Valley | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 107 | |
FES | Nuclear generation assets | Davis Besse | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 420 | |
FES | Nuclear generation assets | Perry | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 124 | |
FES | Nuclear Fuel | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 369 | |
FES | Materials and Supplies | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 81 | |
FES | Asset retirement obligation | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | $ 944 |
Accumulated Other Comprehensi68
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Other comprehensive income (loss) | $ (53) | $ 4 | $ (122) |
Income taxes (benefits) on other comprehensive income (loss) | (21) | 1 | (47) |
Other comprehensive income (loss), net of tax | (32) | 3 | (75) |
FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 218 | ||
Other comprehensive income (loss) | 18 | 38 | (18) |
Income taxes (benefits) on other comprehensive income (loss) | 6 | 15 | (7) |
Other comprehensive income (loss), net of tax | 12 | 23 | (11) |
Ending Balance | (2,070) | 218 | |
Accumulated Other Comprehensive Income | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 174 | 171 | 246 |
Other comprehensive income before reclassifications | 74 | 119 | 24 |
Amounts reclassified from AOCI | (127) | (115) | (146) |
Other comprehensive income (loss) | (53) | 4 | (122) |
Income taxes (benefits) on other comprehensive income (loss) | (21) | 1 | (47) |
Other comprehensive income (loss), net of tax | (32) | 3 | (75) |
Ending Balance | 142 | 174 | 171 |
Accumulated Other Comprehensive Income | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 69 | 46 | 57 |
Other comprehensive income before reclassifications | 91 | 100 | 25 |
Amounts reclassified from AOCI | (73) | (62) | (43) |
Other comprehensive income (loss) | 18 | 38 | (18) |
Income taxes (benefits) on other comprehensive income (loss) | 6 | 15 | (7) |
Other comprehensive income (loss), net of tax | 12 | 23 | (11) |
Ending Balance | 81 | 69 | 46 |
Gains & Losses on Cash Flow Hedges | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (28) | (33) | (37) |
Other comprehensive income before reclassifications | 0 | 0 | 0 |
Amounts reclassified from AOCI | 10 | 8 | 5 |
Other comprehensive income (loss) | 10 | 8 | 5 |
Income taxes (benefits) on other comprehensive income (loss) | 4 | 3 | 1 |
Other comprehensive income (loss), net of tax | 6 | 5 | 4 |
Ending Balance | (22) | (28) | (33) |
Gains & Losses on Cash Flow Hedges | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | (9) | (9) | (7) |
Other comprehensive income before reclassifications | 0 | 0 | 0 |
Amounts reclassified from AOCI | 2 | 0 | (3) |
Other comprehensive income (loss) | 2 | 0 | (3) |
Income taxes (benefits) on other comprehensive income (loss) | 1 | 0 | (1) |
Other comprehensive income (loss), net of tax | 1 | 0 | (2) |
Ending Balance | (8) | (9) | (9) |
Unrealized Gains on AFS Securities | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 52 | 18 | 25 |
Other comprehensive income before reclassifications | 85 | 106 | 14 |
Amounts reclassified from AOCI | (63) | (51) | (25) |
Other comprehensive income (loss) | 22 | 55 | (11) |
Income taxes (benefits) on other comprehensive income (loss) | 7 | 21 | (4) |
Other comprehensive income (loss), net of tax | 15 | 34 | (7) |
Ending Balance | 67 | 52 | 18 |
Unrealized Gains on AFS Securities | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 48 | 16 | 21 |
Other comprehensive income before reclassifications | 91 | 100 | 15 |
Amounts reclassified from AOCI | (61) | (48) | (24) |
Other comprehensive income (loss) | 30 | 52 | (9) |
Income taxes (benefits) on other comprehensive income (loss) | 10 | 20 | (4) |
Other comprehensive income (loss), net of tax | 20 | 32 | (5) |
Ending Balance | 68 | 48 | 16 |
Defined Benefit Pension & OPEB Plans | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 150 | 186 | 258 |
Other comprehensive income before reclassifications | (11) | 13 | 10 |
Amounts reclassified from AOCI | (74) | (72) | (126) |
Other comprehensive income (loss) | (85) | (59) | (116) |
Income taxes (benefits) on other comprehensive income (loss) | (32) | (23) | (44) |
Other comprehensive income (loss), net of tax | (53) | (36) | (72) |
Ending Balance | 97 | 150 | 186 |
Defined Benefit Pension & OPEB Plans | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
Beginning Balance | 30 | 39 | 43 |
Other comprehensive income before reclassifications | 0 | 0 | 10 |
Amounts reclassified from AOCI | (14) | (14) | (16) |
Other comprehensive income (loss) | (14) | (14) | (6) |
Income taxes (benefits) on other comprehensive income (loss) | (5) | (5) | (2) |
Other comprehensive income (loss), net of tax | (9) | (9) | (4) |
Ending Balance | $ 21 | $ 30 | $ 39 |
Pension and Other Postemploym69
Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent liabilities | $ (3,975) | $ (3,719) | |
Pension | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 9,426 | 9,079 | |
Service cost | 208 | 191 | $ 193 |
Interest cost | 390 | 398 | 383 |
Plan participants’ contributions | 0 | 0 | |
Plan amendments | 11 | 0 | |
Medicare retiree drug subsidy | 0 | 0 | |
Actuarial loss | 610 | 224 | |
Benefits paid | (478) | (466) | |
Benefit obligation as of December 31 | 10,167 | 9,426 | 9,079 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 6,213 | 5,338 | |
Actual return on plan assets | 950 | 442 | |
Company contributions | 18 | 899 | |
Plan participants’ contributions | 0 | 0 | |
Benefits paid | (477) | (466) | |
Fair value of plan assets as of December 31 | 6,704 | 6,213 | 5,338 |
Funded Status: | |||
Funded Status | (3,463) | (3,213) | |
Accumulated benefit obligation | 9,583 | 8,913 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent assets | 0 | 9 | |
Current liabilities | (19) | (19) | |
Noncurrent liabilities | (3,444) | (3,203) | |
Net liability as of December 31 | (3,463) | (3,213) | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ 32 | $ 28 | |
Assumptions Used to Determine Benefit Obligations | |||
Discount rate | 3.75% | 4.25% | |
Rate of compensation increase | 4.20% | 4.20% | |
Allocation of Plan Assets | |||
Asset Allocation | 100.00% | 100.00% | |
Pension | Equity securities | |||
Allocation of Plan Assets | |||
Asset Allocation | 42.00% | 44.00% | |
Pension | Bonds | |||
Allocation of Plan Assets | |||
Asset Allocation | 32.00% | 30.00% | |
Pension | Absolute return strategies | |||
Allocation of Plan Assets | |||
Asset Allocation | 10.00% | 8.00% | |
Pension | Real estate | |||
Allocation of Plan Assets | |||
Asset Allocation | 9.00% | 10.00% | |
Pension | Private equity funds | |||
Allocation of Plan Assets | |||
Asset Allocation | 1.00% | 0.00% | |
Pension | Cash and short-term securities | |||
Allocation of Plan Assets | |||
Asset Allocation | 6.00% | 8.00% | |
Pension | Qualified plan | |||
Funded Status: | |||
Funded Status | $ (3,043) | $ (2,821) | |
Pension | Non-qualified plans | |||
Funded Status: | |||
Funded Status | (420) | (392) | |
OPEB | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 711 | 724 | |
Service cost | 5 | 5 | 5 |
Interest cost | 27 | 30 | 29 |
Plan participants’ contributions | 4 | 5 | |
Plan amendments | 0 | (13) | |
Medicare retiree drug subsidy | 1 | 1 | |
Actuarial loss | 32 | 14 | |
Benefits paid | (49) | (55) | |
Benefit obligation as of December 31 | 731 | 711 | 724 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 420 | 431 | |
Actual return on plan assets | 49 | 30 | |
Company contributions | 16 | 9 | |
Plan participants’ contributions | 4 | 5 | |
Benefits paid | (50) | (55) | |
Fair value of plan assets as of December 31 | 439 | 420 | $ 431 |
Funded Status: | |||
Funded Status | (292) | (291) | |
Accumulated benefit obligation | 0 | 0 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | (292) | (291) | |
Net liability as of December 31 | (292) | (291) | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ (206) | $ (288) | |
Assumptions Used to Determine Benefit Obligations | |||
Discount rate | 3.50% | 4.00% | |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | 4.50% | 4.50% | |
Allocation of Plan Assets | |||
Asset Allocation | 100.00% | 100.00% | |
OPEB | Equity securities | |||
Allocation of Plan Assets | |||
Asset Allocation | 50.00% | 53.00% | |
OPEB | Bonds | |||
Allocation of Plan Assets | |||
Asset Allocation | 33.00% | 41.00% | |
OPEB | Absolute return strategies | |||
Allocation of Plan Assets | |||
Asset Allocation | 0.00% | 0.00% | |
OPEB | Real estate | |||
Allocation of Plan Assets | |||
Asset Allocation | 0.00% | 0.00% | |
OPEB | Private equity funds | |||
Allocation of Plan Assets | |||
Asset Allocation | 0.00% | 0.00% | |
OPEB | Cash and short-term securities | |||
Allocation of Plan Assets | |||
Asset Allocation | 17.00% | 6.00% | |
OPEB | Pre Medicare | |||
Assumptions Used to Determine Benefit Obligations | |||
Health care cost trend rate assumed (pre/post-Medicare) | 6.00% | 6.00% | |
OPEB | Post Medicare | |||
Assumptions Used to Determine Benefit Obligations | |||
Health care cost trend rate assumed (pre/post-Medicare) | 5.50% | 5.50% |
Accumulated Other Comprehensi70
Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | $ (1,195) | $ (940) | $ (956) | $ (1,141) | $ (1,021) | $ (950) | $ (963) | $ (917) | $ (4,232) | $ (3,851) | $ (3,740) |
Interest expense - other | (1,178) | (1,157) | (1,132) | ||||||||
Total before taxes | (829) | (9,232) | 893 | ||||||||
Income taxes (benefits) | (413) | (239) | (117) | (126) | 3,389 | (251) | 130 | (213) | (895) | 3,055 | (315) |
FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | (419) | (291) | (286) | (518) | (352) | (316) | (369) | (240) | (1,514) | (1,277) | (1,308) |
Total before taxes | (2,096) | (8,443) | 147 | ||||||||
Income taxes (benefits) | $ (281) | $ (32) | $ (23) | $ 41 | $ 2,983 | $ (56) | $ 143 | $ (82) | (295) | 2,988 | (65) |
Reclassifications from AOCI | Gains & losses on cash flow hedges | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Total before taxes | 10 | 8 | 5 | ||||||||
Income taxes (benefits) | (4) | (3) | (1) | ||||||||
NET INCOME (LOSS) | 6 | 5 | 4 | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Income taxes (benefits) | (1) | 0 | 1 | ||||||||
NET INCOME (LOSS) | 1 | 0 | (2) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | 2 | 0 | (3) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | 2 | 0 | (3) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Interest expense - other | 8 | 8 | 8 | ||||||||
Reclassifications from AOCI | Unrealized gains on AFS securities | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Investment income | (63) | (51) | (25) | ||||||||
Income taxes (benefits) | 23 | 19 | 9 | ||||||||
NET INCOME (LOSS) | (40) | (32) | (16) | ||||||||
Reclassifications from AOCI | Unrealized gains on AFS securities | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Investment income | (61) | (48) | (24) | ||||||||
Income taxes (benefits) | 23 | 18 | 9 | ||||||||
NET INCOME (LOSS) | (38) | (30) | (15) | ||||||||
Reclassifications from AOCI | Defined benefit pension and OPEB plans | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Prior-service costs | (74) | (72) | (126) | ||||||||
Income taxes (benefits) | 28 | 27 | 49 | ||||||||
NET INCOME (LOSS) | (46) | (45) | (77) | ||||||||
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Prior-service costs | (14) | (14) | (16) | ||||||||
Income taxes (benefits) | 5 | 5 | 6 | ||||||||
NET INCOME (LOSS) | $ (9) | $ (9) | $ (10) |
Pension and Other Postemploym71
Pension and Other Postemployment Benefits (Details 1) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service cost | $ 208 | $ 191 | $ 193 |
Interest cost | 390 | 398 | 383 |
Expected return on plan assets | (448) | (399) | (443) |
Amortization of prior service cost (credit) | 7 | 8 | 8 |
Pension & OPEB mark-to-market adjustment | 108 | 179 | 344 |
Net periodic benefit cost (credit) | 265 | 377 | 485 |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service cost | 5 | 5 | 5 |
Interest cost | 27 | 30 | 29 |
Expected return on plan assets | (30) | (30) | (33) |
Amortization of prior service cost (credit) | (81) | (80) | (134) |
Pension & OPEB mark-to-market adjustment | 13 | 15 | 25 |
Net periodic benefit cost (credit) | $ (66) | $ (60) | $ (108) |
Pension and Other Postemploym72
Pension and Other Postemployment Benefits (Details 2) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 4.25% | 4.50% | 4.25% |
Expected long-term return on plan assets | 7.50% | 7.50% | 7.75% |
Rate of compensation increase | 4.20% | 4.20% | 4.20% |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 4.00% | 4.25% | 4.00% |
Expected long-term return on plan assets | 7.50% | 7.50% | 7.75% |
Pension and Other Postemploym73
Pension and Other Postemployment Benefits (Details 3) - Pension - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 6,714 | $ 6,198 | |
Asset Allocation | 100.00% | 100.00% | |
Investments Excluding in Investments at NAV [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 6,657 | $ 6,165 | |
Asset Allocation | 99.00% | 100.00% | |
Cash and short-term securities | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 379 | $ 464 | |
Asset Allocation | 6.00% | 8.00% | |
Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 722 | $ 1,061 | |
Asset Allocation | 11.00% | 17.00% | |
International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 2,083 | $ 1,691 | |
Asset Allocation | 31.00% | 27.00% | |
Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 251 | $ 106 | |
Asset Allocation | 4.00% | 2.00% | |
Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,237 | $ 1,245 | |
Asset Allocation | 18.00% | 20.00% | |
High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 689 | $ 372 | |
Asset Allocation | 10.00% | 6.00% | |
Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 31 | $ 112 | |
Asset Allocation | 0.00% | 2.00% | |
Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 635 | $ 500 | |
Asset Allocation | 10.00% | 8.00% | |
Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ (1) | $ (1) | |
Asset Allocation | 0.00% | 0.00% | |
Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 631 | $ 615 | |
Asset Allocation | 9.00% | 10.00% | |
Private Equity Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Alternative investments measured at fair value | $ 57 | $ 33 | |
Asset Allocation | 1.00% | 0.00% | |
Level 1 | Investments Excluding in Investments at NAV [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,209 | $ 1,470 | |
Level 1 | Cash and short-term securities | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 695 | 1,048 | |
Level 1 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 514 | 422 | |
Level 1 | Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 1 | Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 2 | Investments Excluding in Investments at NAV [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 4,817 | 4,080 | |
Level 2 | Cash and short-term securities | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 379 | 464 | |
Level 2 | Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 27 | 13 | |
Level 2 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 1,569 | 1,269 | |
Level 2 | Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 251 | 106 | |
Level 2 | Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 1,237 | 1,245 | |
Level 2 | High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 689 | 372 | |
Level 2 | Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 31 | 112 | |
Level 2 | Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 635 | 500 | |
Level 2 | Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | (1) | (1) | |
Level 2 | Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Investments Excluding in Investments at NAV [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 631 | 615 | |
Level 3 | Cash and short-term securities | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
Level 3 | Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 631 | $ 615 | $ 587 |
Pension and Other Postemploym74
Pension and Other Postemployment Benefits (Details 4) - Pension - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | $ 6,198 | |
Actual return on plan assets: | ||
Ending balance | 6,714 | $ 6,198 |
Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 615 | |
Actual return on plan assets: | ||
Ending balance | 631 | 615 |
Level 3 | Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 615 | 587 |
Actual return on plan assets: | ||
Unrealized gains | 3 | 29 |
Realized gains (losses) | 10 | 14 |
Transfers in (out) | 3 | (15) |
Ending balance | $ 631 | $ 615 |
Pension and Other Postemploym75
Pension and Other Postemployment Benefits (Details 5) - OPEB - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 441 | $ 424 |
Asset Allocation | 100.00% | 100.00% |
Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 75 | $ 27 |
Asset Allocation | 17.00% | 6.00% |
Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 220 | $ 223 |
Asset Allocation | 50.00% | 53.00% |
U.S. treasuries | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 40 | |
Asset Allocation | 9.00% | |
Government bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 109 | $ 108 |
Asset Allocation | 24.00% | 26.00% |
Corporate bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 34 | $ 24 |
Asset Allocation | 8.00% | 6.00% |
Mortgaged-backed securities (non-government) | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 3 | $ 2 |
Asset Allocation | 1.00% | 0.00% |
Level 1 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 220 | $ 223 |
Level 1 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 1 | Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 220 | 223 |
Level 1 | U.S. treasuries | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | |
Level 1 | Government bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 1 | Corporate bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 1 | Mortgaged-backed securities (non-government) | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | |
Level 2 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 221 | 201 |
Level 2 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 75 | 27 |
Level 2 | Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 2 | U.S. treasuries | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 40 | |
Level 2 | Government bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 109 | 108 |
Level 2 | Corporate bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 34 | 24 |
Level 2 | Mortgaged-backed securities (non-government) | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 3 | 2 |
Level 3 | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 3 | Cash and short-term securities | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 3 | Domestic | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 3 | U.S. treasuries | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | |
Level 3 | Government bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 3 | Corporate bonds | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | 0 | 0 |
Level 3 | Mortgaged-backed securities (non-government) | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Pension investments measured at fair value | $ 0 | $ 0 |
Pension and Other Postemploym76
Pension and Other Postemployment Benefits (Details 6) | Dec. 31, 2017 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 100.00% |
Equities | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 38.00% |
Fixed income | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 30.00% |
Absolute return strategies | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 8.00% |
Real estate | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 10.00% |
Alternative investments | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 8.00% |
Cash | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Target Asset Allocations, Percent | 6.00% |
Pension and Other Postemploym77
Pension and Other Postemployment Benefits (Details 7) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Retirement Benefits [Abstract] | |
Effect of One percentage point increase on total of service and interest cost | $ 1 |
Effect of One percentage point increase on accumulated postretirement benefit obligation | 21 |
Effect of One percentage point decrease on total of service and interest cost | (1) |
Effect of One percentage point decrease on accumulated postretirement benefit obligation | $ (18) |
Pension and Other Postemploym78
Pension and Other Postemployment Benefits (Details 8) $ in Millions | Dec. 31, 2017USD ($) |
Pension | |
Estimated Future Benefit Payments | |
2,018 | $ 518 |
2,019 | 531 |
2,020 | 552 |
2,021 | 567 |
2,022 | 581 |
2023-2027 | 3,056 |
OPEB | |
Estimated Future Benefit Payments | |
2,018 | 55 |
2,019 | 54 |
2,020 | 53 |
2,021 | 53 |
2,022 | 52 |
2023-2027 | 241 |
Subsidy Receipts | |
2,018 | (1) |
2,019 | (1) |
2,020 | (1) |
2,021 | (1) |
2,022 | (1) |
Years 2023-2027 | $ (3) |
Pension and Other Postemploym79
Pension and Other Postemployment Benefits (Details 9) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-current liabilities | $ 954 | $ 866 |
FENOC | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-current liabilities | 626 | 570 |
Pension | FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net (Liability) Asset | (97) | (158) |
OPEB | FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net (Liability) Asset | $ 40 | $ 36 |
Pension and Other Postemploym80
Pension and Other Postemployment Benefits (Details 10) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | $ 265 | $ 377 | $ 485 |
Pension | FES | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | 60 | (5) | 10 |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | (66) | (60) | (108) |
OPEB | FES | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | $ (17) | $ (26) | $ (22) |
Pension and Other Postemploym81
Pension and Other Postemployment Benefits (Details Textuals) - USD ($) $ in Millions | Dec. 13, 2016 | Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Defined Benefit Plan Disclosure [Line Items] | |||||
Mark-to-market adjustment, net of capitalized amounts | $ 141 | $ 147 | $ 242 | ||
Decrease in mortality rate (percent) | 0.50% | ||||
Funding contributions made for current and future years | 882 | ||||
Pension contributions | $ 500 | $ 0 | 382 | 143 | |
Equity contribution from parent | 500 | ||||
Non-cash transaction: stock contribution to pension plan | 0 | 500 | 0 | ||
Pensions and OPEB | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Actual return on plan assets | $ 999 | $ 472 | $ (172) | ||
Actual return on plan assets (percent) | 15.10% | 8.20% | (2.70%) | ||
Expected return on plan assets | $ 478 | $ 429 | $ 476 | ||
Pension | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Company contributions | 18 | 899 | |||
Actual return on plan assets | $ 950 | $ 442 | |||
Expected long-term return on plan assets | 7.50% | 7.50% | 7.75% | ||
Expected return on plan assets | $ 448 | $ 399 | $ 443 | ||
Increase in benefit obligation due to RP2014 mortality table | 62 | ||||
Excluded from total investments | (10) | 16 | |||
OPEB | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Company contributions | 16 | 9 | |||
Actual return on plan assets | $ 49 | $ 30 | |||
Expected long-term return on plan assets | 7.50% | 7.50% | 7.75% | ||
Expected return on plan assets | $ 30 | $ 30 | $ 33 | ||
Excluded from total investments | (2) | (4) | |||
Minimum | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Company contributions | 382 | ||||
FE | Pension | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Non-cash transaction: stock contribution to pension plan | 293 | ||||
FES | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Pension contributions | $ 0 | $ 138 | $ 0 | ||
Subsequent Event | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Funding contributions made for current and future years | $ 750 | ||||
Subsequent Event | Minimum | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Company contributions | $ 500 |
Stock-Based Compensation Plan82
Stock-Based Compensation Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 98 | $ 105 | $ 89 |
Stock-based compensation costs capitalized | 37 | 38 | 32 |
Incentive Plans | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 49 | 62 | 46 |
Incentive Plans | Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 1 | 2 | 2 |
Incentive Plans | Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 0 | (3) | 0 |
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 42 | 39 | 38 |
EDCP & DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 6 | 5 | 3 |
FES | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 7 | 16 | 11 |
Stock-based compensation costs capitalized | 1 | 2 | 1 |
FES | Incentive Plans | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 4 | 11 | 6 |
FES | 401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 3 | $ 5 | $ 5 |
Stock-Based Compensation Plan83
Stock-Based Compensation Plans (Details 1) - Restricted Stock Units (RSUs) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Shares | |||
Nonvested, Beginning balance (shares) | 3,063,729 | ||
Granted (shares) | 1,577,844 | ||
Forfeited (shares) | (169,012) | ||
Vested (shares) | (1,156,810) | ||
Nonvested, Ending balance (shares) | 3,315,751 | 3,063,729 | |
Weighted-Average Grant Date Fair Value | |||
Beginning balance (in dollars per share) | $ 32.98 | ||
Granted (in dollars per share) | 31.71 | $ 34.77 | $ 35.27 |
Forfeited (in dollars per share) | 32.66 | ||
Vested (in dollars per share) | 30.81 | ||
Ending balance (in dollars per share) | $ 33.24 | $ 32.98 | |
Dividend shares earned during period, number of shares | 159,274 |
Stock-Based Compensation Plan84
Stock-Based Compensation Plans (Details 2) - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Options exercisable (in shares) | 1,366,875 | 1,376,821 |
Number of Shares | ||
Beginning option balance (shares) | 1,376,821 | |
Options forfeited (in shares) | (9,946) | |
Ending option balance (shares) | 1,366,875 | |
Weighted Average Exercise Price | ||
Beginning balance (in dollars per share) | $ 44.60 | |
Options forfeited (in dollars per share) | 70.60 | |
Ending balance (in dollars per share) | $ 44.41 |
Stock-Based Compensation Plan85
Stock-Based Compensation Plans (Details Textuals) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 3 years | ||
Realized tax benefits | $ 15,000,000 | $ 13,000,000 | $ 10,000,000 |
Tax benefit associated with stock-based compensation expense | $ 10,000,000 | 14,000,000 | 12,000,000 |
Stock option expiration period | 10 years | ||
Stock options granted in period (shares) | 0 | ||
Cash received from stock options exercised | $ 0 | 0 | |
Weighted-average remaining contractual term of options outstanding | 1 year 8 months 1 day | ||
Share-based liabilities paid | $ 0 | ||
EDCP | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Deferral period (years) | 3 years | ||
DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Net liability recognized | $ 8,000,000 | $ 7,000,000 | |
Performance-based Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award paid in stock (percent) | 66.67% | ||
Award paid in cash (percent) | 33.33% | ||
Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 3 years | ||
Liability recognized | $ 41,000,000 | ||
Granted (in dollars per share) | $ 31.71 | $ 34.77 | $ 35.27 |
Fair value of restricted stock units vested | $ 42,000,000 | $ 36,000,000 | $ 22,000,000 |
Unrecognized cost | $ 33,000,000 | ||
Unrecognized cost, period for recognition | 3 years | ||
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 3 years | ||
Share-based liabilities paid | $ 0 | 2,000,000 | |
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 1 year | ||
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 10 years | ||
FES | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Tax benefit associated with stock-based compensation expense | $ 1,000,000 | $ 2,000,000 | $ 2,000,000 |
ICP 2,007 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum limit of total stock awards (in shares) | 29,000,000 | ||
Stock-based compensation award number of shares available for future | 0 | ||
ICP 2,015 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Maximum limit of total stock awards (in shares) | 10,000,000 | ||
Stock-based compensation award number of shares available for future | 6,000,000 | ||
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares authorized for issuance | 1,304,863 | 1,159,215 |
Taxes (Details)
Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Currently payable (receivable)- | |||||||||||
Federal | $ 14 | $ (1) | $ 1 | ||||||||
State | 42 | 9 | 30 | ||||||||
Currently payable (receivable) Total | 56 | 8 | 31 | ||||||||
Deferred, net- | |||||||||||
Federal | 876 | (3,114) | 277 | ||||||||
State | (29) | 59 | 15 | ||||||||
Deferred Tax Total | 847 | (3,055) | 292 | ||||||||
Investment tax credit amortization | (8) | (8) | (8) | ||||||||
Total provision for income taxes (benefits) | $ 413 | $ 239 | $ 117 | $ 126 | $ (3,389) | $ 251 | $ (130) | $ 213 | 895 | (3,055) | 315 |
FES | |||||||||||
Currently payable (receivable)- | |||||||||||
Federal | (159) | (67) | (56) | ||||||||
State | (1) | (1) | 2 | ||||||||
Currently payable (receivable) Total | (160) | (68) | (54) | ||||||||
Deferred, net- | |||||||||||
Federal | 509 | (2,861) | 103 | ||||||||
State | (52) | (57) | 18 | ||||||||
Deferred Tax Total | 457 | (2,918) | 121 | ||||||||
Investment tax credit amortization | (2) | (2) | (2) | ||||||||
Total provision for income taxes (benefits) | $ 281 | $ 32 | $ 23 | $ (41) | $ (2,983) | $ 56 | $ (143) | $ 82 | $ 295 | $ (2,988) | $ 65 |
Taxes (Details 1)
Taxes (Details 1) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | |||||||||||
Income (loss) before income taxes (benefits) | $ (829) | $ (9,232) | $ 893 | ||||||||
Federal income tax expense (benefit) at statutory rate (35%) | (290) | (3,231) | 313 | ||||||||
Increases (reductions) in taxes resulting from- | |||||||||||
State income taxes, net of federal tax benefit | (4) | (192) | 17 | ||||||||
AFUDC equity and other flow-through | (15) | (13) | (16) | ||||||||
Amortization of investment tax credits | (8) | (8) | (8) | ||||||||
Change in accounting method | 0 | 0 | (8) | ||||||||
ESOP dividend | (6) | (6) | (6) | ||||||||
Impairment of non-deductible goodwill | 0 | 157 | 0 | ||||||||
Remeasurement of deferred taxes | 1,193 | 0 | 0 | ||||||||
Uncertain tax positions | (3) | (16) | 1 | ||||||||
Valuation allowances | 29 | 246 | 18 | ||||||||
Other, net | (1) | 8 | 4 | ||||||||
Total provision for income taxes (benefits) | $ 413 | $ 239 | $ 117 | $ 126 | $ (3,389) | $ 251 | $ (130) | $ 213 | $ 895 | $ (3,055) | $ 315 |
Effective income tax rate (percent) | (108.00%) | 33.10% | 35.30% | ||||||||
FES | |||||||||||
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | |||||||||||
Income (loss) before income taxes (benefits) | $ (2,096) | $ (8,443) | $ 147 | ||||||||
Federal income tax expense (benefit) at statutory rate (35%) | (734) | (2,955) | 51 | ||||||||
Increases (reductions) in taxes resulting from- | |||||||||||
State income taxes, net of federal tax benefit | (52) | (188) | 2 | ||||||||
Amortization of investment tax credits | (2) | (2) | (2) | ||||||||
ESOP dividend | 0 | (1) | (1) | ||||||||
Impairment of non-deductible goodwill | 0 | 9 | 0 | ||||||||
Remeasurement of deferred taxes | 1,067 | 0 | 0 | ||||||||
Uncertain tax positions | 0 | (8) | 5 | ||||||||
Valuation allowances | 18 | 151 | 14 | ||||||||
Other, net | (2) | 6 | (4) | ||||||||
Total provision for income taxes (benefits) | $ 281 | $ 32 | $ 23 | $ (41) | $ (2,983) | $ 56 | $ (143) | $ 82 | $ 295 | $ (2,988) | $ 65 |
Effective income tax rate (percent) | (14.10%) | 35.40% | 44.20% |
Taxes (Details 2)
Taxes (Details 2) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accumulated deferred income taxes | ||
Property basis differences | $ 3,662 | $ 7,088 |
Deferred sale and leaseback gain | (231) | (351) |
Pension and OPEB | (952) | (1,347) |
Nuclear decommissioning activities | 450 | 635 |
Asset retirement obligations | (453) | (669) |
Regulatory asset/liability | 416 | 545 |
Deferred compensation | (177) | (269) |
Nuclear Fuel | (375) | (90) |
Loss carryforwards and AMT credits | (1,467) | (2,251) |
Valuation reserve | 580 | 438 |
All other | (94) | 36 |
Net deferred income tax liability | 1,359 | 3,765 |
FES | ||
Accumulated deferred income taxes | ||
Property basis differences | (677) | (1,009) |
Deferred sale and leaseback gain | (219) | (328) |
Pension and OPEB | (244) | (366) |
Lease market valuation liability | 75 | 111 |
Nuclear decommissioning activities | 411 | 540 |
Asset retirement obligations | (296) | (453) |
Nuclear Fuel | (375) | (90) |
Loss carryforwards and AMT credits | (587) | (830) |
Valuation reserve | 268 | 197 |
All other | (110) | (51) |
Net deferred income tax asset | $ (1,754) | $ (2,279) |
Taxes (Details 3)
Taxes (Details 3) $ in Millions | Dec. 31, 2017USD ($) |
State | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 7,047 |
State | 2018-2022 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 806 |
State | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,963 |
State | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,382 |
State | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,896 |
Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,472 |
Local | 2018-2022 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,472 |
Local | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | State | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,719 |
FES | State | 2018-2022 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2 |
FES | State | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 32 |
FES | State | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 703 |
FES | State | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 982 |
FES | Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,954 |
FES | Local | 2018-2022 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,954 |
FES | Local | 2023-2027 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | Local | 2028-2032 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | Local | 2033-2037 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 0 |
Taxes (Details 4)
Taxes (Details 4) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Changes in unrecognized tax benefits | |||
Beginning balance | $ 84 | $ 34 | $ 34 |
Current year increases | 2 | 2 | 3 |
Prior years increases | 69 | 7 | |
Prior years decreases | (21) | (10) | |
Decrease for lapse in statute | (6) | ||
Ending balance | 80 | 84 | 34 |
FES | |||
Changes in unrecognized tax benefits | |||
Beginning balance | 0 | 8 | 3 |
Current year increases | 0 | 0 | 0 |
Prior years increases | 0 | 5 | |
Prior years decreases | (8) | 0 | |
Decrease for lapse in statute | 0 | ||
Ending balance | $ 0 | $ 0 | $ 8 |
Taxes (Details 5)
Taxes (Details 5) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
General Taxes | |||
KWH excise | $ 188 | $ 196 | $ 193 |
State gross receipts | 204 | 212 | 224 |
Real and personal property | 486 | 472 | 410 |
Social security and unemployment | 131 | 127 | 119 |
Other | 34 | 35 | 32 |
Total general taxes | 1,043 | 1,042 | 978 |
FES | |||
General Taxes | |||
State gross receipts | 20 | 28 | 44 |
Real and personal property | 27 | 42 | 36 |
Social security and unemployment | 11 | 15 | 16 |
Other | 0 | 3 | 2 |
Total general taxes | $ 58 | $ 88 | $ 98 |
Taxes (Details Textuals)
Taxes (Details Textuals) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||
Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Mar. 31, 2018 | Dec. 31, 2014 | |
Income Taxes (Textuals) [Abstract] | ||||||
Increase in income tax provision | $ 1,200 | |||||
Effective tax rate absent the impact from the Tax Act | 35.90% | |||||
Effective income tax rate (percent) | (108.00%) | 33.10% | 35.30% | |||
Impairment | $ 800 | $ 800 | ||||
Goodwill, Impairment Loss, Non-deductible Portion | 433 | |||||
Unrecognized tax benefits | $ 80 | $ 84 | $ 34 | $ 34 | ||
Unrecognized tax benefits that would impact future tax rates | 24 | |||||
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year | 2 | |||||
Unrecognized tax benefits that would impact effective tax rate | 0 | |||||
Federal | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Operating loss carryforwards, not subject to expiration | 39 | |||||
Federal | Begin To Expire in 2031 | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 4,300 | |||||
Operating loss carryforwards, subject to expiration | 908 | |||||
State and Local | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Operating loss carryforwards valuation allowance | 246 | |||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 10,500 | |||||
Operating loss carryforwards, subject to expiration | 496 | |||||
Pre-tax net operating loss carryforwards expected to utilized | 1,800 | |||||
Operating loss carryforwards expected to utilized, net of tax | 81 | |||||
FES | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Increase in income tax provision | $ 1,100 | |||||
Effective tax rate absent the impact from the Tax Act | 36.80% | |||||
Effective income tax rate (percent) | (14.10%) | 35.40% | 44.20% | |||
Impairment | $ 23 | $ 23 | ||||
Unrecognized tax benefits | $ 0 | $ 0 | $ 8 | $ 3 | ||
FES | Federal | Begin To Expire in 2031 | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,000 | |||||
Operating loss carryforwards, subject to expiration | 429 | |||||
FES | State and Local | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Operating loss carryforwards valuation allowance | 151 | |||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,700 | |||||
Operating loss carryforwards, subject to expiration | 154 | |||||
Pre-tax net operating loss carryforwards expected to utilized | 2 | |||||
Forecast | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | $ 45 | |||||
Regulated Distribution | ||||||
Income Taxes (Textuals) [Abstract] | ||||||
Excess deferred taxes | $ 2,300 |
Leases (Details)
Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Rentals for capital and operating leases | |||
Operating leases | $ 158 | $ 168 | $ 174 |
FES | |||
Rentals for capital and operating leases | |||
Operating leases | $ 93 | $ 94 | $ 94 |
Leases (Details 1)
Leases (Details 1) $ in Millions | Dec. 31, 2017USD ($) |
Future minimum capital lease payments | |
2,018 | $ 28 |
2,019 | 23 |
2,020 | 18 |
2,021 | 15 |
2,022 | 13 |
Years thereafter | 20 |
Total minimum lease payments | 117 |
Interest portion | (26) |
Present value of net minimum lease payments | 91 |
Less current portion | 24 |
Noncurrent portion | 67 |
FES | |
Future minimum capital lease payments | |
2,018 | 2 |
2,019 | 0 |
2,020 | 0 |
2,021 | 0 |
2,022 | 0 |
Years thereafter | 0 |
Total minimum lease payments | 2 |
Interest portion | 0 |
Present value of net minimum lease payments | 2 |
Less current portion | 2 |
Noncurrent portion | $ 0 |
Leases (Details 2)
Leases (Details 2) - Lease Payments $ in Millions | Dec. 31, 2017USD ($) |
Future minimum operating lease payments | |
2,018 | $ 146 |
2,019 | 128 |
2,020 | 102 |
2,021 | 124 |
2,022 | 111 |
Years thereafter | 1,263 |
Total minimum lease payments | 1,874 |
FES | |
Future minimum operating lease payments | |
2,018 | 101 |
2,019 | 97 |
2,020 | 68 |
2,021 | 93 |
2,022 | 91 |
Years thereafter | 1,131 |
Total minimum lease payments | $ 1,581 |
Leases (Details Textuals)
Leases (Details Textuals) - USD ($) $ in Millions | Jun. 01, 2017 | Jun. 30, 2016 | May 30, 2016 | May 23, 2016 | Dec. 31, 2007 | Dec. 30, 1987 | Dec. 31, 2017 |
Leases (Textuals) [Abstract] | |||||||
Period of lease terms on the portions sold by OE of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 in years | 29 years | ||||||
Period of lease terms on the portions sold by CEI and TE of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units | 30 years | ||||||
Bruce Mansfield Unit 1 | |||||||
Leases (Textuals) [Abstract] | |||||||
Percentage of leasehold interest related to sale leaseback arrangements | 93.83% | ||||||
Percentage leased | 93.83% | ||||||
Perry Power Plant Unit 1 | |||||||
Leases (Textuals) [Abstract] | |||||||
Percentage of leasehold interest related to sale leaseback arrangements | 3.75% | ||||||
FG | |||||||
Leases (Textuals) [Abstract] | |||||||
Percentage of undivided interest of FGCO in Bruce Mansfield Unit 1 | 93.825% | ||||||
FG | Bruce Mansfield Unit 1 | |||||||
Leases (Textuals) [Abstract] | |||||||
Basic terms of operating lease | 33 years | ||||||
NG | Beaver Valley Unit 2 | |||||||
Leases (Textuals) [Abstract] | |||||||
Increase in plant ownership percentage | 2.60% | ||||||
Payments to acquire additional interest in subsidiaries | $ 38 | ||||||
NG | Perry Power Plant Unit 1 | |||||||
Leases (Textuals) [Abstract] | |||||||
Payments to acquire interest in subsidiaries | $ 50 | ||||||
Plant ownership percentage | 100.00% | 100.00% |
Intangible Assets (Details)
Intangible Assets (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Intangible Assets (Textuals) [Abstract] | |
Intangible Assets, Gross | $ 382 |
Intangible Assets, Accumulated Amortization | 277 |
Intangible Assets, Net | 105 |
Amortization Expense | |
Actual, 2017 | 15 |
Estimated, 2018 | 11 |
Estimated, 2019 | 10 |
Estimated, 2020 | 7 |
Estimated, 2021 | 5 |
Estimated, 2022 | 5 |
Estimated, Thereafter | 67 |
NUG contracts | |
Intangible Assets (Textuals) [Abstract] | |
Intangible Assets, Gross | 124 |
Intangible Assets, Accumulated Amortization | 36 |
Intangible Assets, Net | 88 |
Amortization Expense | |
Actual, 2017 | 5 |
Estimated, 2018 | 5 |
Estimated, 2019 | 5 |
Estimated, 2020 | 5 |
Estimated, 2021 | 5 |
Estimated, 2022 | 5 |
Estimated, Thereafter | 63 |
OVEC | |
Intangible Assets (Textuals) [Abstract] | |
Intangible Assets, Gross | 8 |
Intangible Assets, Accumulated Amortization | 3 |
Intangible Assets, Net | 5 |
Amortization Expense | |
Actual, 2017 | 1 |
Estimated, 2018 | 0 |
Estimated, 2019 | 1 |
Estimated, 2020 | 0 |
Estimated, 2021 | 0 |
Estimated, 2022 | 0 |
Estimated, Thereafter | 4 |
Coal contracts | |
Intangible Assets (Textuals) [Abstract] | |
Intangible Assets, Gross | 102 |
Intangible Assets, Accumulated Amortization | 94 |
Intangible Assets, Net | 8 |
Amortization Expense | |
Actual, 2017 | 4 |
Estimated, 2018 | 3 |
Estimated, 2019 | 3 |
Estimated, 2020 | 2 |
Estimated, 2021 | 0 |
Estimated, 2022 | 0 |
Estimated, Thereafter | 0 |
FES customer contracts | |
Intangible Assets (Textuals) [Abstract] | |
Intangible Assets, Gross | 148 |
Intangible Assets, Accumulated Amortization | 144 |
Intangible Assets, Net | 4 |
Amortization Expense | |
Actual, 2017 | 5 |
Estimated, 2018 | 3 |
Estimated, 2019 | 1 |
Estimated, 2020 | 0 |
Estimated, 2021 | 0 |
Estimated, 2022 | 0 |
Estimated, Thereafter | $ 0 |
Variable Interest Entities (Det
Variable Interest Entities (Details) $ in Millions | Dec. 31, 2017USD ($) |
Net exposure to loss based upon the casualty value provisions | |
Maximum Exposure | $ 1,083 |
Discounted Lease Payments, net | 862 |
Net Exposure | $ 221 |
Variable Interest Entities (D99
Variable Interest Entities (Details Textuals) | 12 Months Ended | ||
Dec. 31, 2017USD ($)agreemententity | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Variable Interest Entities (Textuals) [Abstract] | |||
Transition bond outstanding | $ 56,000,000 | $ 85,000,000 | |
Environmental control bonds outstanding | 383,000,000 | 406,000,000 | |
Potential collateral obligations | $ 407,000,000 | ||
Number of contracts that may contain variable interest | entity | 1 | ||
Purchased power | $ 3,194,000,000 | 3,843,000,000 | $ 4,423,000,000 |
Power Purchase Agreements | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement | 12 | ||
Path-WV | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Percentage of high-voltage transmission line project owned by subsidiary of AE on the Allegheny Series | 100.00% | ||
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series | 50.00% | ||
Equity method investments | $ 17,000,000 | ||
Other FE subsidiaries | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Ownership interest (percent) | 0.00% | ||
Other FE subsidiaries | Power Purchase Agreements | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Purchased power | $ 112,000,000 | 108,000,000 | |
Ohio Funding Companies | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Aggregate annual servicing fees receivable for phase-in recovery bonds | $ 445,000 | ||
Global Holding | FEV | Signal Peak | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Ownership interest (percent) | 33.33% | ||
Phase In Recovery Bonds | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Long-term debt and other long-term obligations | $ 315,000,000 | $ 339,000,000 | |
Guarantee of Indebtedness of Others | Global Holding | |||
Variable Interest Entities (Textuals) [Abstract] | |||
Potential collateral obligations | $ 275,000,000 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Fair value, assets | $ 3,579 | $ 3,197 |
Liabilities | ||
Fair value, liabilities | (107) | (238) |
Net assets (liabilities) | 3,472 | 2,959 |
FES | ||
Assets | ||
Fair value, assets | 1,888 | 1,766 |
Liabilities | ||
Fair value, liabilities | (24) | (129) |
Net assets (liabilities) | 1,864 | 1,637 |
Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (27) | (124) |
Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (23) | (124) |
FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (1) | (6) |
FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (1) | (5) |
NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (79) | (108) |
Corporate debt securities | ||
Assets | ||
Fair value, assets | 1,196 | 1,247 |
Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 720 | 726 |
Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 33 | 210 |
Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 33 | 210 |
FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 4 | 7 |
FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 1 | 4 |
NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 1 |
Equity securities | ||
Assets | ||
Fair value, assets | 1,104 | 925 |
Equity securities | FES | ||
Assets | ||
Fair value, assets | 810 | 634 |
Foreign government debt securities | ||
Assets | ||
Fair value, assets | 88 | 78 |
Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 65 | 58 |
U.S. government debt securities | ||
Assets | ||
Fair value, assets | 154 | 161 |
U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 133 | 48 |
U.S. state debt securities | ||
Assets | ||
Fair value, assets | 276 | 246 |
U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 29 | 3 |
Other | ||
Assets | ||
Fair value, assets | 724 | 322 |
Other | FES | ||
Assets | ||
Fair value, assets | 97 | 83 |
Level 1 | ||
Assets | ||
Fair value, assets | 1,693 | 1,134 |
Liabilities | ||
Fair value, liabilities | 0 | (6) |
Net assets (liabilities) | 1,693 | 1,128 |
Level 1 | FES | ||
Assets | ||
Fair value, assets | 811 | 646 |
Liabilities | ||
Fair value, liabilities | 0 | (6) |
Net assets (liabilities) | 811 | 640 |
Level 1 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | (6) |
Level 1 | Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | 0 | (6) |
Level 1 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 1 | FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 1 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 1 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 10 |
Level 1 | Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 0 | 10 |
Level 1 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Equity securities | ||
Assets | ||
Fair value, assets | 1,104 | 925 |
Level 1 | Equity securities | FES | ||
Assets | ||
Fair value, assets | 810 | 634 |
Level 1 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 1 | Other | ||
Assets | ||
Fair value, assets | 589 | 199 |
Level 1 | Other | FES | ||
Assets | ||
Fair value, assets | 1 | 2 |
Level 2 | ||
Assets | ||
Fair value, assets | 1,882 | 2,055 |
Liabilities | ||
Fair value, liabilities | (27) | (118) |
Net assets (liabilities) | 1,855 | 1,937 |
Level 2 | FES | ||
Assets | ||
Fair value, assets | 1,076 | 1,116 |
Liabilities | ||
Fair value, liabilities | (23) | (118) |
Net assets (liabilities) | 1,053 | 998 |
Level 2 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (27) | (118) |
Level 2 | Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (23) | (118) |
Level 2 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 2 | FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 2 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 2 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 1,196 | 1,247 |
Level 2 | Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 720 | 726 |
Level 2 | Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 33 | 200 |
Level 2 | Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 33 | 200 |
Level 2 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | Equity securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 2 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 88 | 78 |
Level 2 | Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 65 | 58 |
Level 2 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 154 | 161 |
Level 2 | U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 133 | 48 |
Level 2 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 276 | 246 |
Level 2 | U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 29 | 3 |
Level 2 | Other | ||
Assets | ||
Fair value, assets | 135 | 123 |
Level 2 | Other | FES | ||
Assets | ||
Fair value, assets | 96 | 81 |
Level 3 | ||
Assets | ||
Fair value, assets | 4 | 8 |
Liabilities | ||
Fair value, liabilities | (80) | (114) |
Net assets (liabilities) | (76) | (106) |
Level 3 | FES | ||
Assets | ||
Fair value, assets | 1 | 4 |
Liabilities | ||
Fair value, liabilities | (1) | (5) |
Net assets (liabilities) | 0 | (1) |
Level 3 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 3 | Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | 0 | 0 |
Level 3 | FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (1) | (6) |
Level 3 | FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (1) | (5) |
Level 3 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (79) | (108) |
Level 3 | Corporate debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 4 | 7 |
Level 3 | FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 1 | 4 |
Level 3 | NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 0 | 1 |
Level 3 | Equity securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Equity securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Foreign government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Other | ||
Assets | ||
Fair value, assets | 0 | 0 |
Level 3 | Other | FES | ||
Assets | ||
Fair value, assets | $ 0 | $ 0 |
Fair Value Measurements (Det101
Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
NUG contracts | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | $ 1 | $ 1 |
Beginning Balance, Derivative Liabilities | (108) | (137) |
Beginning Balance, Net | (107) | (136) |
Unrealized gain (loss), Derivative Assets | 0 | 2 |
Unrealized gain (loss), Derivative Liabilities | (10) | (17) |
Unrealized gain (loss), Net | (10) | (15) |
Purchases, Derivative Assets | 0 | 0 |
Purchases, Derivative Liabilities | 0 | 0 |
Purchases, Net | 0 | 0 |
Settlements, Derivative Assets | (1) | (2) |
Settlements, Derivative Liabilities | 39 | 46 |
Settlements, Net | 38 | 44 |
Ending Balance, Derivative Assets | 0 | 1 |
Ending Balance, Derivative Liabilities | (79) | (108) |
Ending Balance, Net | (79) | (107) |
FTRs | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | 7 | 8 |
Beginning Balance, Derivative Liabilities | (6) | (13) |
Beginning Balance, Net | 1 | (5) |
Unrealized gain (loss), Derivative Assets | 1 | (6) |
Unrealized gain (loss), Derivative Liabilities | (2) | (4) |
Unrealized gain (loss), Net | (1) | (10) |
Purchases, Derivative Assets | 4 | 16 |
Purchases, Derivative Liabilities | (1) | (7) |
Purchases, Net | 3 | 9 |
Settlements, Derivative Assets | (8) | (11) |
Settlements, Derivative Liabilities | 8 | 18 |
Settlements, Net | 0 | 7 |
Ending Balance, Derivative Assets | 4 | 7 |
Ending Balance, Derivative Liabilities | (1) | (6) |
Ending Balance, Net | 3 | 1 |
FES | FTRs | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | 4 | 5 |
Beginning Balance, Derivative Liabilities | (5) | (11) |
Beginning Balance, Net | (1) | (6) |
Unrealized gain (loss), Derivative Assets | 0 | (4) |
Unrealized gain (loss), Derivative Liabilities | (1) | (3) |
Unrealized gain (loss), Net | (1) | (7) |
Purchases, Derivative Assets | 1 | 10 |
Purchases, Derivative Liabilities | (1) | (5) |
Purchases, Net | 0 | 5 |
Settlements, Derivative Assets | (4) | (7) |
Settlements, Derivative Liabilities | 6 | 14 |
Settlements, Net | 2 | 7 |
Ending Balance, Derivative Assets | 1 | 4 |
Ending Balance, Derivative Liabilities | (1) | (5) |
Ending Balance, Net | $ 0 | $ (1) |
Fair Value Measurements (Det102
Fair Value Measurements (Details 2) - Level 3 $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MWh$ / MWh | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ 3 | $ 1 | $ (5) |
FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | 0 | (1) | (6) |
NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | (79) | $ (107) | $ (136) |
Model | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | 3 | ||
Model | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | 0 | ||
Model | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ (79) | ||
Model | Minimum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | (4.60) | ||
Model | Minimum | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | (4.60) | ||
Model | Minimum | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Power (in dollars per MWH) | MWh | 400 | ||
Power, Regional prices (in dollars per unit) | 30.70 | ||
Model | Maximum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 5.40 | ||
Model | Maximum | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 3.30 | ||
Model | Maximum | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Power (in dollars per MWH) | MWh | 2,099,000 | ||
Power, Regional prices (in dollars per unit) | 32 | ||
Model | Weighted Average | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 0.70 | ||
Model | Weighted Average | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 0.10 | ||
Model | Weighted Average | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Power (in dollars per MWH) | MWh | 426,000 | ||
Power, Regional prices (in dollars per unit) | 30.70 |
Fair Value Measurements (Det103
Fair Value Measurements (Details 3) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | $ 1,707 | $ 1,735 |
Unrealized Gains | 31 | 38 |
Fair Value | 1,738 | 1,773 |
Equity securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 949 | 822 |
Unrealized Gains | 155 | 103 |
Fair Value | 1,104 | 925 |
FES | Debt securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 950 | 847 |
Unrealized Gains | 20 | 27 |
Fair Value | 970 | 874 |
FES | Equity securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 695 | 564 |
Unrealized Gains | 115 | 70 |
Fair Value | $ 810 | $ 634 |
Fair Value Measurements (Det104
Fair Value Measurements (Details 4) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | |||
Sale Proceeds | $ 2,170 | $ 1,678 | $ 1,534 |
Realized Gains | 330 | 170 | 209 |
Realized Losses | (253) | (121) | (191) |
OTTI | (13) | (21) | (102) |
Interest and Dividend Income | 98 | 100 | 101 |
FES | |||
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | |||
Sale Proceeds | 940 | 717 | 733 |
Realized Gains | 256 | 117 | 158 |
Realized Losses | (195) | (69) | (134) |
OTTI | (13) | (19) | (90) |
Interest and Dividend Income | $ 59 | $ 56 | $ 57 |
Fair Value Measurements (Det105
Fair Value Measurements (Details 5) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Carrying Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | $ 22,261 | $ 19,885 |
Fair Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | 23,038 | 19,829 |
FES | Carrying Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | 2,836 | 3,000 |
FES | Fair Value | ||
Fair value and related carrying amounts of long-term debt and other long-term obligations | ||
Long-term debt and other long-term obligations | $ 1,487 | $ 1,555 |
Fair Value Measurements (Det106
Fair Value Measurements (Details Textuals) - USD ($) $ in Millions | 3 Months Ended | ||
Jun. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value of Financial Instruments [Line Items] | |||
Investment excludes receivables, payables and accrued income | $ (8) | $ (3) | |
Cash balance excluded from available for sale securities | 87 | 61 | |
Investments not required to be disclosed | 255 | 266 | |
FES | |||
Fair Value of Financial Instruments [Line Items] | |||
Investment excludes receivables, payables and accrued income | 3 | 2 | |
Cash balance excluded from available for sale securities | $ 76 | $ 44 | |
Beaver Valley Unit 2 | NG | |||
Fair Value of Financial Instruments [Line Items] | |||
Transfers of decommissioning liability | $ 189 |
Derivative Instruments (Details
Derivative Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair value of derivatives | ||
Derivative Assets | $ 37 | $ 218 |
Derivative Liabilities | (107) | (238) |
Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 37 | 140 |
Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 78 |
Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (28) | (78) |
Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (79) | (160) |
Commodity contracts | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 33 | 133 |
Commodity contracts | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 77 |
Commodity contracts | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (27) | (72) |
Commodity contracts | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | 0 | (52) |
FTRs | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 4 | 7 |
FTRs | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 0 |
FTRs | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (1) | (6) |
FTRs | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | 0 | 0 |
NUGs | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 1 |
NUGs | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (79) | (108) |
FES | ||
Fair value of derivatives | ||
Derivative Assets | 34 | 214 |
Derivative Liabilities | (24) | (129) |
FES | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 34 | 137 |
FES | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 77 |
FES | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (24) | (77) |
FES | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | 0 | (52) |
FES | Commodity contracts | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 33 | 133 |
FES | Commodity contracts | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 77 |
FES | Commodity contracts | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (23) | (72) |
FES | Commodity contracts | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | 0 | (52) |
FES | FTRs | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 1 | 4 |
FES | FTRs | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | $ (1) | $ (5) |
Derivative Instruments (Deta108
Derivative Instruments (Details 1) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Assets | ||
Fair Value | $ 37 | $ 218 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (20) | (123) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 17 | 95 |
Derivative Liabilities | ||
Fair Value | (107) | (238) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 20 | 123 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 3 | 1 |
Net Fair Value | (84) | (114) |
Commodity contracts | ||
Derivative Assets | ||
Fair Value | 33 | 210 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (19) | (117) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 14 | 93 |
Derivative Liabilities | ||
Fair Value | (27) | (124) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 19 | 117 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 3 | 1 |
Net Fair Value | (5) | (6) |
FTRs | ||
Derivative Assets | ||
Fair Value | 4 | 7 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (1) | (6) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 3 | 1 |
Derivative Liabilities | ||
Fair Value | (1) | (6) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 1 | 6 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 0 | 0 |
NUGs | ||
Derivative Assets | ||
Fair Value | 1 | |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 0 | |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | |
Net Fair Value | 1 | |
Derivative Liabilities | ||
Fair Value | (79) | (108) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 0 | 0 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | (79) | (108) |
FES | ||
Derivative Assets | ||
Fair Value | 34 | 214 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (20) | (121) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 14 | 93 |
Derivative Liabilities | ||
Fair Value | (24) | (129) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 20 | 121 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 2 |
Net Fair Value | (4) | (6) |
FES | Commodity contracts | ||
Derivative Assets | ||
Fair Value | 33 | 210 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (19) | (117) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 14 | 93 |
Derivative Liabilities | ||
Fair Value | (23) | (124) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 19 | 117 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 1 |
Net Fair Value | (4) | (6) |
FES | FTRs | ||
Derivative Assets | ||
Fair Value | 1 | 4 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (1) | (4) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 0 | 0 |
Derivative Liabilities | ||
Fair Value | (1) | (5) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 1 | 4 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 1 |
Net Fair Value | $ 0 | $ 0 |
Derivative Instruments (Deta109
Derivative Instruments (Details 2) MWh in Millions | Dec. 31, 2017MWh |
Power Contracts | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 2 |
Sales (in MWH or mmBTUs) | 11 |
Net (in MWH or mmBTUs) | (9) |
FTRs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 9 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 9 |
NUGs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 2 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 2 |
FES | Power Contracts | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 2 |
Sales (in MWH or mmBTUs) | 11 |
Net (in MWH or mmBTUs) | (9) |
FES | FTRs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 5 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 5 |
Derivative Instruments (Deta110
Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | $ 50 | $ 218 | $ 161 |
Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (17) | (131) | (130) |
Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | (81) | (9) | 73 |
Realized Gain (Loss) Reclassified | (14) | (35) | (49) |
Fuel Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 5 | (8) | (34) |
Commodity contracts | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 54 | 210 | 111 |
Commodity contracts | Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (17) | (131) | (130) |
Commodity contracts | Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | (82) | (14) | 93 |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 |
Commodity contracts | Fuel Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 5 | (8) | (34) |
FTRs | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (4) | 8 | 50 |
FTRs | Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | 0 | 0 |
FTRs | Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | 1 | 5 | (20) |
Realized Gain (Loss) Reclassified | (14) | (35) | (49) |
FTRs | Fuel Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | 0 | 0 |
FES | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 50 | 218 | 160 |
FES | Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (17) | (131) | (130) |
FES | Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | (78) | (9) | 74 |
Realized Gain (Loss) Reclassified | (14) | (35) | (49) |
FES | Commodity contracts | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 54 | 210 | 111 |
FES | Commodity contracts | Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (17) | (131) | (130) |
FES | Commodity contracts | Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | (79) | (14) | 93 |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 |
FES | FTRs | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (4) | 8 | 49 |
FES | FTRs | Purchase Power Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | 0 | 0 |
FES | FTRs | Other Operating Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Unrealized Gain (Loss) Recognized | 1 | 5 | (19) |
Realized Gain (Loss) Reclassified | $ (14) | $ (35) | $ (49) |
Derivative Instruments (Deta111
Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | $ (105) | $ (135) |
Unrealized loss | (10) | (18) |
Purchases | 3 | 4 |
Settlements | 36 | 44 |
Outstanding net asset (liability), Ending Balance | (76) | (105) |
NUGs | ||
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | (107) | (136) |
Unrealized loss | (9) | (15) |
Purchases | 0 | 0 |
Settlements | 37 | 44 |
Outstanding net asset (liability), Ending Balance | (79) | (107) |
Regulated FTRs | ||
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | 2 | 1 |
Unrealized loss | (1) | (3) |
Purchases | 3 | 4 |
Settlements | (1) | 0 |
Outstanding net asset (liability), Ending Balance | $ 3 | $ 2 |
Derivative Instruments (Deta112
Derivative Instruments (Details Textuals) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)agreement | Dec. 31, 2016USD ($)agreement | |
Derivative [Line Items] | ||
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements | $ 3 | $ 10 |
Expected adverse change in quoted market prices of derivative instruments | 10.00% | |
Decrease net income due to adverse change in commodity prices | $ 6 | |
NUGs | ||
Derivative [Line Items] | ||
Liability position | 79 | |
Cash Flow Hedges | ||
Derivative [Line Items] | ||
Unamortized gains or (losses) associated with designated cash flow hedges | (10) | (12) |
Unamortized losses associated with prior interest rate hedges | $ 25 | $ 33 |
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement | 0 | 0 |
Fair Value Hedging | ||
Derivative [Line Items] | ||
Gains (losses) to be amortized to interest expenses during next twelve months | $ (2) | |
Reclassifications from long-term debt | $ 7 | $ 10 |
Number of fixed-for-floating interest rate swap agreements outstanding | agreement | 0 | 0 |
FES | ||
Derivative [Line Items] | ||
Decrease net income due to adverse change in commodity prices | $ 4 | |
FES | Commodity contracts | ||
Derivative [Line Items] | ||
Collateral posted | 1 | |
FES | Cash Flow Hedges | ||
Derivative [Line Items] | ||
Unamortized losses associated with prior interest rate hedges | $ 3 | $ 3 |
Capitalization (Details)
Capitalization (Details) | Dec. 31, 2017$ / sharesshares |
Preferred stock and preference stock authorizations | |
Shares Authorized | 5,000,000 |
Par Value, in dollars per share | $ / shares | $ 100 |
Penn | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 1,200,000 |
Par Value, in dollars per share | $ / shares | $ 100 |
CEI | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 4,000,000 |
JCP&L | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 15,600,000 |
ME | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 10,000,000 |
PN | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 11,435,000 |
PE | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 10,000,000 |
Par Value, in dollars per share | $ / shares | $ 0.01 |
WP | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 32,000,000 |
Preferred Stock With Par Value $100 | OE | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 6,000,000 |
Par Value, in dollars per share | $ / shares | $ 100 |
Preferred Stock With Par Value $100 | TE | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 3,000,000 |
Par Value, in dollars per share | $ / shares | $ 100 |
Preferred Stock With Par Value $100 | MP | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 940,000 |
Par Value, in dollars per share | $ / shares | $ 100 |
Preferred Stock With Par Value $25 | OE | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 8,000,000 |
Par Value, in dollars per share | $ / shares | $ 25 |
Preferred Stock With Par Value $25 | TE | |
Preferred stock and preference stock authorizations | |
Shares Authorized | 12,000,000 |
Par Value, in dollars per share | $ / shares | $ 25 |
Preference Stock | OE | |
Preferred stock and preference stock authorizations | |
Preference Stock Shares Authorized | 8,000,000 |
Preference Stock | CEI | |
Preferred stock and preference stock authorizations | |
Preference Stock Shares Authorized | 3,000,000 |
Preference Stock | TE | |
Preferred stock and preference stock authorizations | |
Preference Stock Shares Authorized | 5,000,000 |
Preference Stock Par Value, in dollars per share | $ / shares | $ 25 |
Capitalization (Details 1)
Capitalization (Details 1) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 5,455 | $ 5,633 |
Unsecured debt | 16,820 | 14,258 |
Capital lease obligations | 91 | 104 |
Unamortized debt premiums (discounts) | (42) | (25) |
Unamortized debt issuance costs | (113) | (87) |
Unamortized fair value adjustments | (14) | (6) |
Currently payable long-term debt | (1,082) | (1,685) |
Total long-term debt and other long-term obligations | 21,115 | 18,192 |
FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | 621 | 627 |
Capital lease obligations | 2 | 8 |
Unamortized debt premiums (discounts) | (1) | (1) |
Unamortized debt issuance costs | (14) | (15) |
Currently payable long-term debt | (524) | (179) |
Total long-term debt and other long-term obligations | 2,299 | 2,813 |
FMBs and secured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
FMBs and secured notes - fixed rate | $ 5,446 | 5,623 |
FMBs and secured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 1.726% | |
FMBs and secured notes - fixed rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 9.74% | |
Secured notes - fixed rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 612 | 617 |
Secured notes - fixed rate | FES | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 4.25% | |
Secured notes - fixed rate | FES | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 5.625% | |
Secured notes - variable rate | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 9 | 10 |
Secured notes - variable rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 4.50% | |
Secured notes - variable rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 4.50% | |
Secured notes - variable rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 9 | 10 |
Secured notes - variable rate | FES | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 4.50% | |
Secured notes - variable rate | FES | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 4.50% | |
Unsecured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
Unsecured debt | $ 15,370 | 13,058 |
Unsecured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.55% | |
Unsecured notes - fixed rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 7.70% | |
Unsecured notes - fixed rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Unsecured debt | $ 2,215 | 2,373 |
Unsecured notes - fixed rate | FES | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.55% | |
Unsecured notes - fixed rate | FES | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 6.80% | |
Unsecured notes - variable rate | ||
Schedule of Capitalization [Line Items] | ||
Unsecured debt | $ 1,450 | $ 1,200 |
Unsecured notes - variable rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.227% | |
Unsecured notes - variable rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.227% |
Capitalization (Details 2)
Capitalization (Details 2) $ in Millions | Dec. 31, 2017USD ($) |
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years | |
2,018 | $ 1,051 |
2,019 | 1,267 |
2,020 | 1,281 |
2,021 | 2,032 |
2,022 | 1,428 |
FES | |
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years | |
2,018 | 515 |
2,019 | 323 |
2,020 | 667 |
2,021 | 674 |
2,022 | $ 284 |
Capitalization (Details 3)
Capitalization (Details 3) $ in Millions | Dec. 31, 2017USD ($) |
Outstanding PCRBs | |
2,018 | $ 1,051 |
2,019 | 1,267 |
2,020 | 1,281 |
2,021 | 2,032 |
2,022 | 1,428 |
PCRB | |
Outstanding PCRBs | |
2,018 | 375 |
2,019 | 232 |
2,020 | 490 |
2,021 | 342 |
2,022 | 284 |
FES | |
Outstanding PCRBs | |
2,018 | 515 |
2,019 | 323 |
2,020 | 667 |
2,021 | 674 |
2,022 | 284 |
FES | PCRB | |
Outstanding PCRBs | |
2,018 | 375 |
2,019 | 232 |
2,020 | 490 |
2,021 | 342 |
2,022 | $ 284 |
Capitalization (Details Textual
Capitalization (Details Textuals) | Jan. 22, 2018USD ($) | Jan. 16, 2018$ / shares | Dec. 15, 2017USD ($) | Oct. 05, 2017USD ($) | Sep. 08, 2017USD ($) | Jun. 21, 2017USD ($) | Jun. 01, 2017USD ($) | Mar. 15, 2017USD ($) | Mar. 01, 2017USD ($) | Dec. 13, 2016USD ($)shares | Dec. 31, 2017USD ($)$ / sharesshares | Sep. 30, 2017$ / shares | Jun. 30, 2017$ / shares | Mar. 31, 2017$ / shares | Dec. 31, 2016USD ($)$ / sharesshares | Sep. 30, 2016$ / shares | Jun. 30, 2016$ / shares | Mar. 31, 2016$ / shares | Dec. 31, 2017USD ($)subsidiary$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Sep. 15, 2017USD ($) | Aug. 31, 2017USD ($) | May 16, 2017USD ($) | Jun. 30, 2013USD ($) |
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Retained earnings (accumulated deficit) | $ (6,262,000,000) | $ (4,532,000,000) | $ (6,262,000,000) | $ (4,532,000,000) | |||||||||||||||||||||
Dividends declared, in dollars per share | $ / shares | $ 1.44 | $ 1.44 | $ 1.44 | ||||||||||||||||||||||
Common stock dividends per share paid, in dollars per share | $ / shares | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | $ 0.36 | |||||||||||||||||
FERC-defined equity to total capitalization ratio | 35.00% | ||||||||||||||||||||||||
Preferred shares shares outstanding | shares | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Preference shares outstanding | shares | 0 | 0 | 0 | 0 | |||||||||||||||||||||
Repayments of debt | $ 2,291,000,000 | $ 2,331,000,000 | $ 879,000,000 | ||||||||||||||||||||||
Number of subsidiaries that issued environmental control bonds | subsidiary | 2 | ||||||||||||||||||||||||
Environmental control bonds outstanding | $ 383,000,000 | $ 406,000,000 | $ 383,000,000 | 406,000,000 | |||||||||||||||||||||
Transition bond outstanding | 56,000,000 | 85,000,000 | 56,000,000 | 85,000,000 | |||||||||||||||||||||
Principal default amount specified in debt covenants | 100,000,000 | ||||||||||||||||||||||||
Phase In Recovery Bonds | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Long-term debt and other long-term obligations | $ 315,000,000 | $ 339,000,000 | $ 315,000,000 | $ 339,000,000 | |||||||||||||||||||||
Senior Notes | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 3,000,000,000 | ||||||||||||||||||||||||
Senior Notes | 2.85% Senior Unsecured Notes Due 2022 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 500,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 2.85% | ||||||||||||||||||||||||
Senior Notes | 3.90% Senior Notes Due 2027 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 1,500,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 3.90% | ||||||||||||||||||||||||
Senior Notes | 4.85% Senior Notes Due 2047 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 1,000,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 4.85% | ||||||||||||||||||||||||
Senior Notes | 2.75% Senior Notes Due 2018 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Repayments of Senior notes | $ 650,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 2.75% | ||||||||||||||||||||||||
AGC | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
FERC-defined equity to total capitalization ratio | 45.00% | ||||||||||||||||||||||||
FG | PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Repayments of Senior notes | $ 28,000,000 | ||||||||||||||||||||||||
FG | FMBs | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 130,000,000 | ||||||||||||||||||||||||
MP | FMBs | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 150,000,000 | ||||||||||||||||||||||||
Face amount of loan | $ 250,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 3.55% | ||||||||||||||||||||||||
WP | FMBs | 275 Million FMBs, 4.14% Due 2047 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 275,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 4.14% | ||||||||||||||||||||||||
WP | FMBs | 275 Million FMBs, 5.95% Due 2017 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 5.95% | ||||||||||||||||||||||||
Repayments of debt | $ 275,000,000 | ||||||||||||||||||||||||
WP | Senior Notes | 100 Million FMBs, 4.09% Due 2047 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 0 | ||||||||||||||||||||||||
Interest rate (percent) | 4.09% | ||||||||||||||||||||||||
JCP&L | Senior Notes | 5.65% Senior Notes Due 2017 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 5.65% | ||||||||||||||||||||||||
Repayments of debt | $ 250,000,000 | ||||||||||||||||||||||||
ATSI | Senior Notes | 3.66% Senior Unsecured Notes Due 2032 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 150,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 3.66% | ||||||||||||||||||||||||
PN | Senior Notes | 3.25% Senior Notes Due 2028 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 300,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 3.25% | ||||||||||||||||||||||||
PN | Senior Notes | 6.05% Senior Notes Due 2017 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 6.05% | ||||||||||||||||||||||||
Repayments of debt | $ 300,000,000 | ||||||||||||||||||||||||
CEI | FMBs | 300 Million FMBs, 7.88% Due November 2017 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 300,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 7.88% | ||||||||||||||||||||||||
CEI | Senior Notes | 3.50% Senior Notes Due 2028 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 350,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 3.50% | ||||||||||||||||||||||||
Ohio Funding Companies | Phase In Recovery Bonds | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 445,000,000 | ||||||||||||||||||||||||
Common Stock | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Stock issuance - employee benefits, shares | shares | 2,989,893 | 2,685,946 | 2,457,827 | ||||||||||||||||||||||
Pension | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Stock issuance - employee benefits, shares | shares | 16,097,875 | ||||||||||||||||||||||||
Stock Investment Plan and certain share-based benefit plans | $ 500,000,000 | ||||||||||||||||||||||||
Subsequent Event | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Dividends declared, in dollars per share | $ / shares | $ 0.36 | ||||||||||||||||||||||||
Proceeds from issuance of equity | $ 2,500,000,000 | ||||||||||||||||||||||||
Repayments of debt | $ 1,450,000,000 |
Short-Term Borrowings and Ba118
Short-Term Borrowings and Bank Lines of Credit (Details) - USD ($) | Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Short-term Debt [Line Items] | |||||
Cash and Cash Equivalents, at Carrying Value | $ 589,000,000 | $ 199,000,000 | $ 131,000,000 | $ 85,000,000 | |
Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | ||||
Available Liquidity | 4,740,000,000 | ||||
Cash, Available Liquidity | 358,000,000 | ||||
Total Available Liquidity | 5,098,000,000 | ||||
FirstEnergy | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Available Liquidity | 3,740,000,000 | ||||
FET | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Available Liquidity | 1,000,000,000 | ||||
FES | |||||
Short-term Debt [Line Items] | |||||
Cash and Cash Equivalents, at Carrying Value | 1,000,000 | 2,000,000 | $ 2,000,000 | $ 2,000,000 | |
FES | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | ||||
Total Available Liquidity | 501,000,000 | ||||
FES | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Available Liquidity | 500,000,000 | ||||
Revolving Credit Facility | Line of Credit | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | 500,000,000 | |||
Revolving Credit Facility | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | 5,000,000,000 | ||||
Revolving Credit Facility | FirstEnergy | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | 4,000,000,000 | ||||
Revolving Credit Facility | FET | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | 1,000,000,000 | ||||
Revolving Credit Facility | FES | Line of Credit | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | ||||
Revolving Credit Facility | FES | Line of Credit | Subsequent Event | |||||
Short-term Debt [Line Items] | |||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 |
Short-Term Borrowings and Ba119
Short-Term Borrowings and Bank Lines of Credit (Details 1) - Subsequent Event | Jan. 31, 2018USD ($) |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | $ 5,000,000,000 |
FET | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 0 |
OE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
CEI | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
TE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 300,000,000 |
JCP&L | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
ME | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
PN | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 300,000,000 |
WP | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 200,000,000 |
MP | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
PE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 150,000,000 |
ATSI | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
Penn | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 100,000,000 |
TrAIL | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 400,000,000 |
MAIT | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 400,000,000 |
FE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Regulatory and Other Short-Term Debt Limitations | 0 |
FE | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 4,000,000,000 |
FE | FET | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 0 |
FE | OE | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
FE | CEI | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
FE | TE | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 300,000,000 |
FE | JCP&L | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 600,000,000 |
FE | ME | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 300,000,000 |
FE | PN | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 300,000,000 |
FE | WP | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 200,000,000 |
FE | MP | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
FE | PE | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 150,000,000 |
FE | ATSI | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 0 |
FE | Penn | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 50,000,000 |
FE | TrAIL | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 0 |
FE | MAIT | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 0 |
FET Sub-limits | FET | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 1,000,000,000 |
FET Sub-limits | ATSI | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
FET Sub-limits | TrAIL | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 400,000,000 |
FET Sub-limits | MAIT | Line of Credit | Revolving Credit Facility | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | $ 400,000,000 |
Short-Term Borrowings and Ba120
Short-Term Borrowings and Bank Lines of Credit (Details 2) | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Disclosure [Abstract] | ||
Weighted average interest rate | 3.24% | 2.47% |
Short-Term Borrowings and Ba121
Short-Term Borrowings and Bank Lines of Credit (Details Textuals) | Jan. 22, 2018USD ($) | Dec. 06, 2016 | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)money_pool | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jan. 31, 2018USD ($) | Feb. 16, 2017USD ($)agreement |
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Number of money pools | money_pool | 2 | |||||||
Short-term borrowings | $ 2,675,000,000 | $ 300,000,000 | $ 2,675,000,000 | |||||
Average interest rate for borrowings | 2.47% | 3.24% | 2.47% | |||||
Repayments of debt | $ 2,291,000,000 | $ 2,331,000,000 | $ 879,000,000 | |||||
Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Available Liquidity | $ 4,740,000,000 | |||||||
Maximum amount borrowed under revolving credit facility | 5,000,000,000 | |||||||
Repayments of debt | $ 1,450,000,000 | |||||||
Term Loan | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Face amount of loan | $ 1,200,000,000 | |||||||
Number of agreements | agreement | 2 | |||||||
Term Loan | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Repayments of debt | $ 1,200,000,000 | |||||||
Term Loan | $125M Term Loan | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Face amount of loan | $ 125,000,000 | |||||||
FET | Minimum | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Consolidated debt to total capitalization ratio (percent) | 65.00% | |||||||
FET | Maximum | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Consolidated debt to total capitalization ratio (percent) | 75.00% | |||||||
FES | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Short-term borrowings | $ 101,000,000 | $ 102,000,000 | 101,000,000 | |||||
Repayments of debt | 163,000,000 | 507,000,000 | $ 411,000,000 | |||||
FES | Affiliates | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Other Short-term Borrowings | 101,000,000 | $ 105,000,000 | 101,000,000 | |||||
FES | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | |||||||
FG | FMBs | $250M FMB's | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Face amount of loan | 250,000,000 | 250,000,000 | ||||||
NG | FMBs | $450M FMB's | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Face amount of loan | $ 450,000,000 | 450,000,000 | ||||||
Line of Credit | FE and the Utilities | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Available Liquidity | 10,000,000 | |||||||
Line of Credit | FET | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Available Liquidity | 1,000,000,000 | |||||||
Line of Credit | FES | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Available Liquidity | 500,000,000 | |||||||
Line of Credit | Letter of Credit [Member] | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Term of revolving credit facility | 1 year | |||||||
Line of Credit | Letter of Credit [Member] | FET | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | $ 100,000,000 | |||||||
Line of Credit | Revolving Credit Facility | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Term of revolving credit facility | 2 years | |||||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | 5,000,000,000 | 500,000,000 | |||||
Line of Credit | Revolving Credit Facility | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 5,000,000,000 | |||||||
Line of Credit | Revolving Credit Facility | FET | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 1,000,000,000 | |||||||
Line of Credit | Revolving Credit Facility | FES | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | 500,000,000 | ||||||
Line of Credit | Revolving Credit Facility | FES | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 500,000,000 | |||||||
Line of Credit | Secured Debt | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 200,000,000 | 200,000,000 | ||||||
Line of Credit | Surety Bond | Little Bull Run | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | 169,000,000 | 169,000,000 | 169,000,000 | |||||
Line of Credit | Surety Bond | FES | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | $ 31,000,000 | $ 31,000,000 | ||||||
Revolving Credit Facility | Parent and Certain Subsidiaries | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Term of revolving credit facility | 5 years | |||||||
Available for Issuance of Letters of Credit | Minimum | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Cross-default provision for other indebtedness | $ 100,000,000 | |||||||
Money Pool | Maximum | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Term of revolving credit facility | 364 days | |||||||
Money Pool | Regulated Companies | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Average interest rate for borrowings | 1.48% | |||||||
Money Pool | Unregulated Companies | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Average interest rate for borrowings | 2.30% | |||||||
FE | Line of Credit | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Available Liquidity | 3,740,000,000 | |||||||
FE | Line of Credit | Letter of Credit [Member] | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | $ 250,000,000 | |||||||
FE | Line of Credit | Revolving Credit Facility | Subsequent Event | ||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||
Maximum amount borrowed under revolving credit facility | $ 4,000,000,000 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | Jun. 30, 2016 | May 30, 2016 | Jun. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Asset Retirement Obligations [Line Items] | |||||
Nuclear plant decommissioning trusts | $ 2,678 | $ 2,514 | |||
Changes to the asset retirement obligations | |||||
Beginning Balance | 1,482 | 1,410 | |||
Changes in timing of estimated cash flows (1) | 944 | ||||
Liabilities settled | (12) | (27) | |||
Accretion | 101 | 95 | |||
Liabilities Incurred | 0 | 4 | |||
Ending Balance | 2,515 | 1,482 | |||
FES | |||||
Asset Retirement Obligations [Line Items] | |||||
Nuclear plant decommissioning trusts | 1,856 | 1,552 | |||
Changes to the asset retirement obligations | |||||
Beginning Balance | 901 | 831 | |||
Changes in timing of estimated cash flows (1) | 944 | ||||
Liabilities settled | (11) | (18) | |||
Accretion | 62 | 56 | |||
Liabilities Incurred | 49 | 32 | |||
Ending Balance | 1,945 | 901 | |||
FES | Beaver Valley, Davis-Besse and Perry Nuclear Generating Stations | |||||
Changes to the asset retirement obligations | |||||
Beginning Balance | 713 | ||||
Ending Balance | $ 1,758 | 713 | |||
FES | Beaver Valley Unit 2 | |||||
Changes to the asset retirement obligations | |||||
Asset retirement obligations transfers | $ 73 | ||||
NG | Perry Power Plant Unit 1 | |||||
Changes to the asset retirement obligations | |||||
Asset retirement obligations transfers | $ 28 | ||||
Plant ownership percentage | 100.00% | 100.00% |
Regulatory Matters - Maryland a
Regulatory Matters - Maryland and New Jersey (Details) $ in Millions | Jan. 19, 2018USD ($)rebate | Dec. 12, 2016USD ($) | Jul. 16, 2015 | Feb. 27, 2013USD ($) | Dec. 31, 2017component | Dec. 31, 2020USD ($) | Dec. 31, 2017USD ($)component | Feb. 15, 2018USD ($) |
Maryland | ||||||||
Regulatory Matters [Line Items] | ||||||||
Expected infrastructure investments | $ 2,700 | |||||||
Expected infrastructure investments, period | 15 years | |||||||
New Jersey | ||||||||
Regulatory Matters [Line Items] | ||||||||
Number of supply components | component | 2 | 2 | ||||||
PE | Maryland | ||||||||
Regulatory Matters [Line Items] | ||||||||
Incremental energy savings goal in the next 12 months (percent) | 0.97% | |||||||
Incremental energy savings goal per year (percent) | 0.20% | |||||||
Incremental energy savings goal thereafter (percent) | 2.00% | |||||||
Expenditures for cost recovery program incurred | $ 60 | |||||||
Amortization period for expenditures for cost recovery program | 5 years | |||||||
JCP&L | New Jersey | NJBPU | ||||||||
Regulatory Matters [Line Items] | ||||||||
Requested increase in revenues | $ 80 | |||||||
Forecast | PE | Maryland | ||||||||
Regulatory Matters [Line Items] | ||||||||
Expenditures for cost recovery program | $ 116 | |||||||
Recovery period for expenditures for cost recovery program | 3 years | |||||||
Subsequent Event | PE | MDPSC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Number of residential charging equipment rebates | rebate | 2,000 | |||||||
Number of commercial charging equipment rebates | rebate | 259 | |||||||
Cost of charging equipment rebates | $ 12 | |||||||
Charging equipment rebates amortization period | 5 years | |||||||
Subsequent Event | PE | Maryland | MDPSC | Minimum | ||||||||
Regulatory Matters [Line Items] | ||||||||
Impact on base rate due to Tax Act | $ 7 | |||||||
Subsequent Event | PE | Maryland | MDPSC | Maximum | ||||||||
Regulatory Matters [Line Items] | ||||||||
Impact on base rate due to Tax Act | $ 8 |
Regulatory Matters - Ohio (Deta
Regulatory Matters - Ohio (Details) $ in Millions | Dec. 01, 2017USD ($) | Oct. 12, 2016USD ($) | Apr. 15, 2016 | Aug. 07, 2013USD ($)auction | Dec. 31, 2017USD ($) | Feb. 15, 2018USD ($) |
Regulatory Matters [Line Items] | ||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | |||||
Ohio | ||||||
Regulatory Matters [Line Items] | ||||||
Cumulative benchmark of annual energy savings | 22.20% | |||||
Energy efficient portfolio plan term | 3 years | |||||
Portfolio plan estimated cost | $ 268 | |||||
Credit to non-shopping customers | $ 43.4 | |||||
Ohio | Year 2017 | ||||||
Regulatory Matters [Line Items] | ||||||
Annual energy savings yearly increase (percent) | 1.00% | |||||
Ohio | Annually Through 2020 | ||||||
Regulatory Matters [Line Items] | ||||||
Utilities required to additionally reduce peak demand | 0.75% | |||||
Ohio | Years 2021 Through 2027 | ||||||
Regulatory Matters [Line Items] | ||||||
Annual energy savings yearly increase (percent) | 2.00% | |||||
Ohio | Distribution Modernization Rider | ||||||
Regulatory Matters [Line Items] | ||||||
Rider valuation | $ 558 | |||||
Rider valuation period | 8 years | |||||
Ohio | PUCO | ||||||
Regulatory Matters [Line Items] | ||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | |||||
Number of renewable energy auctions | auction | 1 | |||||
Ohio | PUCO | Distribution Modernization Rider | ||||||
Regulatory Matters [Line Items] | ||||||
Annual revenue cap for rider | $ 132.5 | |||||
Cost recovery period | 3 years | |||||
Possible extension period | 2 years | |||||
Approved annual revenue cap amount for rider | $ 204 | |||||
Excessive earnings test cost recovery exclusion period | 3 years | |||||
Potential extension period for excessive earnings test cost recovery | 2 years | |||||
Ohio | PUCO | DCR Rider | ||||||
Regulatory Matters [Line Items] | ||||||
Increased annual revenue cap for rider | $ 30 | |||||
Revenue cap for Rider for years 3-6 | 20 | |||||
Revenue cap for Rider for years 6-8 | 15 | |||||
Ohio | PUCO | DPM Plan | ||||||
Regulatory Matters [Line Items] | ||||||
Requested rate increase (decrease) | $ 450 | |||||
Ohio | PUCO | Energy Conservation, Economic Development and Job Retention | ||||||
Regulatory Matters [Line Items] | ||||||
Contribution amount | $ 51 | |||||
Ohio Companies | Subsequent Event | Ohio | PUCO | ||||||
Regulatory Matters [Line Items] | ||||||
Impact on base rate due to Tax Act | $ 40 |
Regulatory Matters - Pennsylvan
Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Millions | Dec. 11, 2017proposalMW | Sep. 01, 2017USD ($) | Jun. 14, 2017USD ($) | Jan. 19, 2017USD ($) | Dec. 09, 2016USD ($) | Jun. 19, 2015 | Mar. 31, 2016USD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2017USD ($)proposal | Dec. 31, 2027MW | Dec. 31, 2020MW | Mar. 06, 2017USD ($)MW | Sep. 23, 2016program |
Pennsylvania | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Number of RFP's | proposal | 1 | ||||||||||||
Project term | 2 years | ||||||||||||
Pennsylvania | 12 Month Period | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Energy contract term | 12 months | ||||||||||||
Pennsylvania | 24 Month Period | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Energy contract term | 24 months | ||||||||||||
Pennsylvania | ME | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase | $ 96 | ||||||||||||
Pennsylvania | Penn | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase | 29 | ||||||||||||
Pennsylvania | WP | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase | 66 | ||||||||||||
Pennsylvania | PN | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase | $ 100 | ||||||||||||
Pennsylvania | PPUC | ME | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Demand reduction targets proposed | 1.80% | ||||||||||||
Energy consumption reduction targets (percent) | 4.00% | ||||||||||||
Requested rate increase (decrease) | $ 51.3 | ||||||||||||
Pennsylvania | PPUC | Penn | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Demand reduction targets proposed | 1.70% | ||||||||||||
Energy consumption reduction targets (percent) | 3.30% | ||||||||||||
Requested rate increase (decrease) | 33.2 | ||||||||||||
Pennsylvania | PPUC | WP | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Demand reduction targets proposed | 1.80% | ||||||||||||
Energy consumption reduction targets (percent) | 2.60% | ||||||||||||
Requested rate increase (decrease) | 50.1 | ||||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Number of RFP's | proposal | 2 | ||||||||||||
Project term | 2 years | ||||||||||||
New hourly priced default service threshold (in MW's) | MW | 0.1 | ||||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 3 Month Period | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Energy contract term | 3 months | ||||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 12 Month Period | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Energy contract term | 12 months | ||||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 24 Month Period | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Energy contract term | 24 months | ||||||||||||
Pennsylvania | PPUC | Pennsylvania Companies | EE&C | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Approved amount of rate increase | $ 390 | ||||||||||||
Pennsylvania | PPUC | PN | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Demand reduction targets proposed | 0.00% | ||||||||||||
Energy consumption reduction targets (percent) | 3.90% | ||||||||||||
Requested rate increase (decrease) | $ 44.8 | ||||||||||||
West Virginia | WVPSC | VMS Rates | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Requested rate increase (decrease) | $ (15) | ||||||||||||
Requested rate increase (decrease) (percent) | (1.00%) | ||||||||||||
West Virginia | WVPSC | VMS Rates | Forecast | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Requested additional rate decrease | $ (15) | ||||||||||||
West Virginia | WVPSC | MP and PE | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Number of proposed efficient programs | program | 3 | ||||||||||||
Energy efficient reduction requirement (percent) | 0.50% | ||||||||||||
Expenditures for cost recovery program | $ 10.4 | ||||||||||||
West Virginia | WVPSC | MP and PE | ENEC | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Requested rate increase (decrease) | $ 25 | ||||||||||||
Rate stability period | 2 years | ||||||||||||
West Virginia | WVPSC | MP | Accelerated Recovery Costs For Modernizing and Improving Coal-Fired Boilers | Forecast | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Capacity shortfall (in MW's) | MW | 700 | ||||||||||||
West Virginia | WVPSC | MP | IRP | Forecast | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Capacity shortfall (in MW's) | MW | 850 | ||||||||||||
Pleasants Power Station | |||||||||||||
Regulatory Matters [Line Items] | |||||||||||||
Plant generation capacity (in MW's) | MW | 1,300 | ||||||||||||
Assets purchase agreement consideration to be received | $ 195 |
Regulatory Matters - Reliabilit
Regulatory Matters - Reliability and FERC Matters (Details) $ in Millions | Dec. 20, 2017USD ($) | Oct. 13, 2017 | Mar. 10, 2017 | Feb. 20, 2017 | Jan. 19, 2017 | Jun. 15, 2016kv | Aug. 04, 2014 | Aug. 24, 2012USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2017 | Dec. 31, 2017USD ($)entity | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Regulatory Matters [Line Items] | ||||||||||||||
Regional enforcement entities | entity | 8 | |||||||||||||
Impairment of assets and related charges (Note 2) | $ 2,406 | $ 10,665 | $ 42 | |||||||||||
FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Power threshold for cost methodology (in KW) | kv | 500 | |||||||||||||
Denied recovery charges of exit fees | $ 78.8 | $ 78.8 | ||||||||||||
Ohio Companies | FERC | Unit Power Agreement [Member] | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Term of proposed purchase power agreement | 8 years | |||||||||||||
MAIT | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Impairment of assets and related charges (Note 2) | $ 13 | |||||||||||||
MAIT | FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Approved ROE | 10.30% | 11.00% | ||||||||||||
Approved capital structure | 60.00% | |||||||||||||
JCP&L | FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Impairment of assets and related charges (Note 2) | $ 28 | |||||||||||||
Approved suspension period | 5 months | |||||||||||||
JCP&L | FERC | Network Integration Transmission Service | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Annual revenue requirement | $ 135 | |||||||||||||
JCP&L | FERC | PJM Tariff | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Annual revenue requirement | $ 20 | |||||||||||||
PATH-Allegheny | FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Cost recovery PP&E reclassified to Regulatory Assets | $ 62 | |||||||||||||
Path-WV | FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Cost recovery PP&E reclassified to Regulatory Assets | $ 59 | |||||||||||||
PATH | FERC | ||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||
Cost recovery proposed ROE (percent) | 10.90% | |||||||||||||
Base ROE (percent) | 10.40% | 8.11% | 10.40% | |||||||||||
ROE granted for RTO's (percent) | 0.50% | |||||||||||||
Remaining recovery period of regulatory assets | 5 years |
Commitments, Guarantees and 127
Commitments, Guarantees and Contingencies (Details) $ in Millions | Dec. 31, 2017USD ($) |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 407 |
Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 148 |
FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 237 |
FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 20 |
AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 2 |
At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 5 |
At Current Credit Rating | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
At Current Credit Rating | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
At Current Credit Rating | FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 4 |
At Current Credit Rating | AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 1 |
Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 41 |
Upon Further Downgrade | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 41 |
Upon Further Downgrade | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
Upon Further Downgrade | FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
Upon Further Downgrade | AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
Surety Bond | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 361 |
Surety Bond | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 107 |
Surety Bond | FE | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 237 |
Surety Bond | FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 16 |
Surety Bond | AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 1 |
Commitments, Guarantees and 128
Commitments, Guarantees and Contingencies - Nuclear Insurance, Commitments and Collateral (Details) | 12 Months Ended | |
Dec. 31, 2017USD ($)Nuclear_Power_Plant | Dec. 31, 2016USD ($) | |
Loss Contingencies [Line Items] | ||
Liability assessed with respect to single nuclear incident | $ 13,400,000,000 | |
Plants licensed to operate | Nuclear_Power_Plant | 102 | |
Portion of insurance coverage of private insurer included in single nuclear incident | $ 450,000,000 | |
Portion of insurance coverage by industry retrospective rating plan | 13,000,000,000 | |
Losses in excess of private insurance contributed for each nuclear unit license | 127,000,000 | |
Losses in excess of private insurance contributed for each nuclear unit license per unit | 19,000,000 | |
Nuclear incidence liability per incident of parent and subsidiary companys based on their present nuclear ownership and leasehold interests | 509,000,000 | |
Nuclear incident liability not more than in any one year per incident of parent and subsidiary companies based on their present nuclear ownership and leasehold interests | 76,000,000 | |
Aggregate indemnity | $ 1,400,000,000 | |
Waiting period | 84 days | |
Coverage of decontamination costs | $ 2,750,000,000 | |
Insurance coverage for replacement power costs | $ 1,060,000,000 | |
Environmental plan, submission period | 30 days | |
Outstanding guarantees and other assurances aggregated | $ 3,800,000,000 | |
Potential additional collateral obligations | 407,000,000 | |
FE | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 1,200,000,000 | |
Subsidiaries' Guarantees | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 1,800,000,000 | |
Other Guarantees | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 275,000,000 | |
Other Assurances | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 459,000,000 | |
Regulated Distribution | ||
Loss Contingencies [Line Items] | ||
Company posted collateral related to net liability positions | 4,000,000 | |
Potential additional collateral obligations | $ 148,000,000 | |
FEV | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding | ||
Loss Contingencies [Line Items] | ||
Investment ownership percentage | 33.33% | |
FES | ||
Loss Contingencies [Line Items] | ||
Company posted collateral related to net liability positions | $ 123,000,000 | |
Potential additional collateral obligations | 20,000,000 | |
FES | CES | ||
Loss Contingencies [Line Items] | ||
Potential additional collateral obligations | $ 2,000,000 | |
WMB Marketing Ventures, LLC | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding | ||
Loss Contingencies [Line Items] | ||
Investment ownership percentage | 33.33% | |
Global Holding | Senior Secured Term Loan | Senior Loans | ||
Loss Contingencies [Line Items] | ||
Long-term debt and other long-term obligations | $ 275,000,000 | |
AE Supply | ||
Loss Contingencies [Line Items] | ||
Company posted collateral related to net liability positions | 4,000,000 | |
Potential additional collateral obligations | 2,000,000 | |
Surety Bond | Line of Credit | FES | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | $ 31,000,000 | |
Surety Bond | Little Bull Run | Line of Credit | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | 169,000,000 | $ 169,000,000 |
Surety Bond | Hatfield Ferry | Line of Credit | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | $ 31,000,000 |
Commitments, Guarantees and 129
Commitments, Guarantees and Contingencies - Clean Air Act and Climate Change (Details) $ in Millions | Feb. 18, 2018USD ($) | May 01, 2017USD ($) | Oct. 01, 2015 | Aug. 03, 2015T | Mar. 31, 2017USD ($) | Dec. 31, 2017phaseT | Nov. 12, 2014 |
Loss Contingencies [Line Items] | |||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | ||||||
National Ambient Air Quality Standards | |||||||
Loss Contingencies [Line Items] | |||||||
Capping of SO2 Emissions Under CSAPR | T | 2,400,000 | ||||||
Capping of NOx emissions under CSAPR | T | 1,200,000 | ||||||
National Ambient Air Quality Standards | CSAPR | |||||||
Loss Contingencies [Line Items] | |||||||
Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | phase | 2 | ||||||
Mercury and Air Toxic Standards | FG | Certain Coal-Fired Power Plant | |||||||
Loss Contingencies [Line Items] | |||||||
Contractual amount in dispute (in T) | T | 3,500,000 | ||||||
Mercury and Air Toxic Standards | FG | Another Coal-Fired Power Plant | |||||||
Loss Contingencies [Line Items] | |||||||
Contractual amount in dispute (in T) | T | 2,500,000 | ||||||
Minimum | Climate Change | |||||||
Loss Contingencies [Line Items] | |||||||
Reduction in emissions (percent) | 26.00% | ||||||
Maximum | Climate Change | |||||||
Loss Contingencies [Line Items] | |||||||
Reduction in emissions (percent) | 28.00% | ||||||
EPA | Caa Compliance | |||||||
Loss Contingencies [Line Items] | |||||||
Period of time to implement plan | 3 years | ||||||
Signal Peak, Global Rail and Affiliates | Senior Secured Term Loan | Senior Loans | Global Holding | |||||||
Loss Contingencies [Line Items] | |||||||
Investment ownership percentage | 69.99% | ||||||
Settled Litigation | Caa Compliance | |||||||
Loss Contingencies [Line Items] | |||||||
Loss in period | $ 116 | ||||||
Settled Litigation | Caa Compliance | FG | |||||||
Loss Contingencies [Line Items] | |||||||
Amount of damages awarded | $ 109 | ||||||
Settled Litigation | Caa Compliance | FES | |||||||
Loss Contingencies [Line Items] | |||||||
Loss in period | $ 116 | ||||||
Subsequent Event | |||||||
Loss Contingencies [Line Items] | |||||||
Amount of damages awarded to other party | $ 93 | ||||||
Subsequent Event | AE Supply | |||||||
Loss Contingencies [Line Items] | |||||||
Amount of damages awarded to other party | $ 93 |
Commitments, Guarantees and 130
Commitments, Guarantees and Contingencies - Clean Water Act and Regulation of Waste Disposal (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Loss Contingencies [Line Items] | ||
Renewal cycle of waste water discharge permit | 5 years | |
Regulation of Waste Disposal | ||
Loss Contingencies [Line Items] | ||
Accrual for environmental loss contingencies | $ 125 | |
Environmental liabilities former gas facilities | 80 | |
Bond closure and post closure period | 45 years | |
Period of time to implement plan | 12 years | |
Minimum | Clean Water Act | ||
Loss Contingencies [Line Items] | ||
Maximum capital investment required to install technology to meet TDS and Sulfate limits | 150 | |
Maximum | Clean Water Act | ||
Loss Contingencies [Line Items] | ||
Maximum capital investment required to install technology to meet TDS and Sulfate limits | $ 300 |
Commitments, Guarantees and 131
Commitments, Guarantees and Contingencies - Other Legal Proceedings (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Loss Contingencies [Line Items] | ||
Nuclear plant decommissioning trusts | $ 2,678,000,000 | $ 2,514,000,000 |
Parental support agreement | 3,800,000,000 | |
Nuclear Plant Matters | ||
Loss Contingencies [Line Items] | ||
Nuclear plant decommissioning trusts | 2,700,000,000 | |
FES | ||
Loss Contingencies [Line Items] | ||
Nuclear plant decommissioning trusts | 1,856,000,000 | 1,552,000,000 |
FES | Nuclear Plant Matters | ||
Loss Contingencies [Line Items] | ||
Nuclear plant decommissioning trusts | 1,900,000,000 | |
NG | Parent Support Agreement | FES | Nuclear Plant Matters | ||
Loss Contingencies [Line Items] | ||
Parental support agreement | 400,000,000 | |
Revolving Credit Facility | Line of Credit | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | 5,000,000,000 | 500,000,000 |
Revolving Credit Facility | Line of Credit | Nuclear Plant Matters | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | |
Revolving Credit Facility | Line of Credit | FES | ||
Loss Contingencies [Line Items] | ||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 |
Transactions With Affiliated132
Transactions With Affiliated Companies (Details) T in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)T | Dec. 31, 2016USD ($)T | Dec. 31, 2015USD ($)T | |
MP | FES | |||
REVENUES: | |||
Revenues | $ 31 | ||
Interest Expense: | |||
Amount of coal sold under purchase agreement (in T) | T | 0.7 | ||
AE Supply and MP | FES | |||
REVENUES: | |||
Revenues | $ 0 | ||
AE Supply | FES | |||
REVENUES: | |||
Revenues | $ 41 | $ 16 | |
Interest Expense: | |||
Amount of coal sold under purchase agreement (in T) | T | 1.1 | 0.4 | |
FES | |||
Investment Income: | |||
Interest income from FE | $ 13 | $ 2 | 2 |
Interest Expense: | |||
Interest expense to affiliates | 0 | 5 | 4 |
Interest expense to FE | 19 | 2 | 3 |
FES | AE Supply | |||
REVENUES: | |||
Revenues | $ 15 | $ 80 | $ 63 |
Interest Expense: | |||
Amount of coal sold under purchase agreement (in T) | T | 0.4 | 1.5 | 1.2 |
FES | Electric sales to affiliates | |||
REVENUES: | |||
Revenues | $ 366 | $ 459 | $ 666 |
FES | Other | |||
REVENUES: | |||
Revenues | 11 | 11 | 14 |
FES | Purchased power from affiliates | |||
Expenses: | |||
Expenses | 201 | 622 | 353 |
FES | Fuel | |||
Expenses: | |||
Expenses | 4 | 4 | 1 |
FES | Support services | |||
Expenses: | |||
Expenses | $ 775 | $ 748 | $ 705 |
Supplemental Guarantor Infor133
Supplemental Guarantor Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | $ 3,442 | $ 3,714 | $ 3,309 | $ 3,552 | $ 3,375 | $ 3,917 | $ 3,401 | $ 3,869 | $ 14,017 | [1] | $ 14,562 | [1] | $ 15,026 | [1] |
OPERATING EXPENSES: | ||||||||||||||
Fuel | 1,383 | 1,666 | 1,855 | |||||||||||
Purchased power | 3,194 | 3,843 | 4,423 | |||||||||||
Other operating expenses | 1,195 | 940 | 956 | 1,141 | 1,021 | 950 | 963 | 917 | 4,232 | 3,851 | 3,740 | |||
Pension and OPEB mark-to-market adjustment | 141 | 0 | 0 | 0 | 147 | 0 | 0 | 0 | 141 | 147 | 242 | |||
Provision for depreciation | 293 | 289 | 281 | 275 | 339 | 311 | 334 | 329 | 1,138 | 1,313 | 1,282 | |||
General taxes | 1,043 | 1,042 | 978 | |||||||||||
Impairment of assets and related charges | 2,244 | 31 | 131 | 0 | 9,218 | 0 | 1,447 | 0 | 2,406 | 10,665 | 42 | |||
Total operating expenses | 13,845 | 22,824 | 12,734 | |||||||||||
OPERATING INCOME (LOSS) | (1,830) | 884 | 544 | 574 | (8,924) | 861 | (975) | 776 | 172 | (8,262) | 2,292 | |||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | 98 | 84 | (22) | |||||||||||
Interest expense | (1,178) | (1,157) | (1,132) | |||||||||||
Capitalized financing costs | 79 | 103 | 117 | |||||||||||
Total other expense | (1,001) | (970) | (1,399) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (829) | (9,232) | 893 | |||||||||||
INCOME TAXES (BENEFITS) | 413 | 239 | 117 | 126 | (3,389) | 251 | (130) | 213 | 895 | (3,055) | 315 | |||
NET INCOME (LOSS) | (2,499) | 396 | 174 | 205 | (5,796) | 380 | (1,089) | 328 | (1,724) | (6,177) | 578 | |||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | (85) | (59) | (116) | |||||||||||
Amortized gain on derivative hedges | 10 | 8 | 5 | |||||||||||
Change in unrealized gain on available-for-sale securities | 22 | 55 | (11) | |||||||||||
Other comprehensive income (loss) | (53) | 4 | (122) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (21) | 1 | (47) | |||||||||||
Other comprehensive income (loss), net of tax | (32) | 3 | (75) | |||||||||||
Eliminations | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | (2,363) | (3,587) | (3,758) | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 0 | 0 | 0 | |||||||||||
Other operating expenses | 49 | 49 | 49 | |||||||||||
Pension and OPEB mark-to-market adjustment | 0 | 0 | 0 | |||||||||||
Provision for depreciation | (2) | (3) | (3) | |||||||||||
General taxes | 0 | 0 | 0 | |||||||||||
Impairment of assets and related charges | 0 | (83) | 0 | |||||||||||
Total operating expenses | (2,316) | (3,624) | (3,712) | |||||||||||
OPERATING INCOME (LOSS) | (47) | 37 | (46) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | 1,806 | 4,538 | (870) | |||||||||||
Miscellaneous income | 0 | 0 | 0 | |||||||||||
Capitalized financing costs | 0 | 0 | 0 | |||||||||||
Total other expense | 1,930 | 4,652 | (778) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | 1,883 | 4,689 | (824) | |||||||||||
INCOME TAXES (BENEFITS) | 27 | 35 | 15 | |||||||||||
NET INCOME (LOSS) | 1,856 | 4,654 | (839) | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | 13 | 14 | 5 | |||||||||||
Amortized gain on derivative hedges | 0 | 0 | 0 | |||||||||||
Change in unrealized gain on available-for-sale securities | (30) | (52) | 8 | |||||||||||
Other comprehensive income (loss) | (17) | (38) | 13 | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (5) | (15) | 5 | |||||||||||
Other comprehensive income (loss), net of tax | (12) | (23) | 8 | |||||||||||
COMPREHENSIVE INCOME (LOSS) | 1,844 | 4,631 | (831) | |||||||||||
Eliminations | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | (2,363) | (3,587) | (3,758) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | 68 | 57 | 34 | |||||||||||
Eliminations | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | 56 | 57 | 58 | |||||||||||
FES | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 3,037 | 4,242 | 4,824 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 0 | 0 | 0 | |||||||||||
Other operating expenses | 322 | 310 | 378 | |||||||||||
Pension and OPEB mark-to-market adjustment | (12) | (1) | (8) | |||||||||||
Provision for depreciation | 12 | 13 | 12 | |||||||||||
General taxes | 20 | 31 | 45 | |||||||||||
Impairment of assets and related charges | 0 | 39 | 21 | |||||||||||
Total operating expenses | 3,458 | 5,436 | 5,958 | |||||||||||
OPERATING INCOME (LOSS) | (421) | (1,194) | (1,134) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | (1,864) | (4,585) | 844 | |||||||||||
Miscellaneous income | 1 | 4 | 1 | |||||||||||
Capitalized financing costs | 0 | 0 | 0 | |||||||||||
Total other expense | (1,984) | (4,686) | 764 | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (2,405) | (5,880) | (370) | |||||||||||
INCOME TAXES (BENEFITS) | (14) | (425) | (452) | |||||||||||
NET INCOME (LOSS) | (2,391) | (5,455) | 82 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | (14) | (14) | (6) | |||||||||||
Amortized gain on derivative hedges | 2 | 0 | (3) | |||||||||||
Change in unrealized gain on available-for-sale securities | 30 | 52 | (9) | |||||||||||
Other comprehensive income (loss) | 18 | 38 | (18) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | 6 | 15 | (7) | |||||||||||
Other comprehensive income (loss), net of tax | 12 | 23 | (11) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (2,379) | (5,432) | 71 | |||||||||||
FES | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 2,488 | 4,024 | 3,826 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (75) | (50) | (29) | |||||||||||
FES | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 628 | 1,020 | 1,684 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (46) | (55) | (52) | |||||||||||
FG | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 1,062 | 1,739 | 1,801 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 390 | 582 | 679 | |||||||||||
Other operating expenses | 490 | 286 | 273 | |||||||||||
Pension and OPEB mark-to-market adjustment | (30) | (4) | 10 | |||||||||||
Provision for depreciation | 32 | 120 | 124 | |||||||||||
General taxes | 21 | 30 | 26 | |||||||||||
Impairment of assets and related charges | 0 | 3,937 | 2 | |||||||||||
Total operating expenses | 903 | 4,951 | 1,114 | |||||||||||
OPERATING INCOME (LOSS) | 159 | (3,212) | 687 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | 39 | 30 | 17 | |||||||||||
Miscellaneous income | 1 | 3 | 2 | |||||||||||
Capitalized financing costs | 2 | 8 | 6 | |||||||||||
Total other expense | (73) | (74) | (87) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | 86 | (3,286) | 600 | |||||||||||
INCOME TAXES (BENEFITS) | 360 | (1,169) | 224 | |||||||||||
NET INCOME (LOSS) | (274) | (2,117) | 376 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | (13) | (14) | (5) | |||||||||||
Amortized gain on derivative hedges | 0 | 0 | 0 | |||||||||||
Change in unrealized gain on available-for-sale securities | 0 | 0 | 0 | |||||||||||
Other comprehensive income (loss) | (13) | (14) | (5) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (5) | (5) | (2) | |||||||||||
Other comprehensive income (loss), net of tax | (8) | (9) | (3) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (282) | (2,126) | 373 | |||||||||||
FG | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (11) | (10) | (8) | |||||||||||
FG | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (104) | (105) | (104) | |||||||||||
NG | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 1,362 | 2,004 | 2,138 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 209 | 198 | 192 | |||||||||||
Other operating expenses | 653 | 632 | 608 | |||||||||||
Pension and OPEB mark-to-market adjustment | 66 | 53 | 55 | |||||||||||
Provision for depreciation | 67 | 206 | 191 | |||||||||||
General taxes | 17 | 27 | 27 | |||||||||||
Impairment of assets and related charges | 2,031 | 4,729 | 10 | |||||||||||
Total operating expenses | 3,119 | 6,032 | 1,368 | |||||||||||
OPERATING INCOME (LOSS) | (1,757) | (4,028) | 770 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | 113 | 84 | (5) | |||||||||||
Miscellaneous income | 5 | 0 | 0 | |||||||||||
Capitalized financing costs | 24 | 26 | 29 | |||||||||||
Total other expense | 97 | 62 | (29) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (1,660) | (3,966) | 741 | |||||||||||
INCOME TAXES (BENEFITS) | (78) | (1,429) | 278 | |||||||||||
NET INCOME (LOSS) | (1,582) | (2,537) | 463 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | 0 | 0 | 0 | |||||||||||
Amortized gain on derivative hedges | 0 | 0 | 0 | |||||||||||
Change in unrealized gain on available-for-sale securities | 30 | 52 | (8) | |||||||||||
Other comprehensive income (loss) | 30 | 52 | (8) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | 10 | 20 | (3) | |||||||||||
Other comprehensive income (loss), net of tax | 20 | 32 | (5) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (1,562) | (2,505) | 458 | |||||||||||
NG | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 76 | 187 | 285 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (1) | (4) | (4) | |||||||||||
NG | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (44) | (44) | (49) | |||||||||||
Consolidated | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 700 | 743 | 741 | 914 | 997 | 1,100 | 1,102 | 1,199 | 3,098 | [2] | 4,398 | [2] | 5,005 | [2] |
OPERATING EXPENSES: | ||||||||||||||
Fuel | 599 | 780 | 871 | |||||||||||
Other operating expenses | 419 | 291 | 286 | 518 | 352 | 316 | 369 | 240 | 1,514 | 1,277 | 1,308 | |||
Pension and OPEB mark-to-market adjustment | 24 | 0 | 0 | 0 | 48 | 0 | 0 | 0 | 24 | 48 | 57 | |||
Provision for depreciation | 29 | 28 | 27 | 25 | 86 | 83 | 84 | 83 | 109 | 336 | 324 | |||
General taxes | 58 | 88 | 98 | |||||||||||
Impairment of assets and related charges | 2,031 | 0 | 0 | 0 | 8,082 | 0 | 540 | 0 | 2,031 | 8,622 | 33 | |||
Total operating expenses | 5,164 | 12,795 | 4,728 | |||||||||||
OPERATING INCOME (LOSS) | (2,112) | 102 | 61 | (117) | (8,153) | 101 | (571) | 226 | (2,066) | (8,397) | 277 | |||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income (loss) from equity investees | 94 | 67 | (14) | |||||||||||
Miscellaneous income | 7 | 7 | 3 | |||||||||||
Capitalized financing costs | 26 | 34 | 35 | |||||||||||
Total other expense | (30) | (46) | (130) | |||||||||||
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS) | (2,096) | (8,443) | 147 | |||||||||||
INCOME TAXES (BENEFITS) | 281 | 32 | 23 | (41) | (2,983) | 56 | (143) | 82 | 295 | (2,988) | 65 | |||
NET INCOME (LOSS) | $ (2,406) | $ 76 | $ 19 | $ (80) | $ (5,188) | $ 40 | $ (438) | $ 131 | (2,391) | (5,455) | 82 | |||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
Pension and OPEB prior service costs | (14) | (14) | (6) | |||||||||||
Amortized gain on derivative hedges | 2 | 0 | (3) | |||||||||||
Change in unrealized gain on available-for-sale securities | 30 | 52 | (9) | |||||||||||
Other comprehensive income (loss) | 18 | 38 | (18) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss) | 6 | 15 | (7) | |||||||||||
Other comprehensive income (loss), net of tax | 12 | 23 | (11) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (2,379) | (5,432) | 71 | |||||||||||
Consolidated | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 201 | 624 | 353 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (19) | (7) | (7) | |||||||||||
Consolidated | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 628 | 1,020 | 1,684 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | $ (138) | $ (147) | $ (147) | |||||||||||
Bruce Mansfield Unit 1 | ||||||||||||||
Condensed Financial Statements, Captions [Line Items] | ||||||||||||||
Percentage of leasehold interest related to sale leaseback arrangements | 93.83% | 93.83% | ||||||||||||
[1] | Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. | |||||||||||||
[2] | Includes excise tax collections of $20 million, $28 million and $44 million in 2017, 2016 and 2015, respectively. |
Supplemental Guarantor Infor134
Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
CURRENT ASSETS: | ||||
Cash and cash equivalents | $ 589 | $ 199 | $ 131 | $ 85 |
Receivables- | ||||
Customers | 1,463 | 1,440 | ||
Other Receivables | 191 | 175 | ||
Materials and supplies, at average cost | 463 | 564 | ||
Derivatives | 37 | 140 | ||
Collateral | 146 | 176 | ||
Total current assets | 3,108 | 2,950 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 39,778 | 43,767 | ||
Less — Accumulated provision for depreciation | 11,925 | 15,731 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 27,853 | 28,036 | ||
Construction work in progress | 1,026 | 1,351 | ||
Total net property, plant and equipment | 28,879 | 29,387 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 2,678 | 2,514 | ||
Other | 506 | 512 | ||
Total other property and investments | 3,184 | 3,026 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Goodwill | 5,618 | 5,618 | 6,418 | |
Other | 1,053 | 1,153 | ||
Total deferred charges and other assets | 6,711 | 7,785 | ||
Total assets | 42,257 | 43,148 | 52,094 | |
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 1,082 | 1,685 | ||
Accounts payable- | ||||
Accrued taxes | 571 | 580 | ||
Other | 722 | 738 | ||
Total current liabilities | 4,077 | 7,126 | ||
CAPITALIZATION: | ||||
Long-term debt and other long-term obligations | 21,115 | 18,192 | ||
Total capitalization | 25,040 | 24,433 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 723 | 757 | ||
Accumulated deferred income taxes | 1,359 | 3,765 | ||
Retirement benefits | 3,975 | 3,719 | ||
Asset retirement obligations | 2,515 | 1,482 | ||
Other | 1,718 | 1,547 | ||
Total noncurrent liabilities | 13,140 | 11,589 | ||
Total liabilities and capitalization | 42,257 | 43,148 | ||
Eliminations | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | (326) | (612) | ||
Other Receivables | 0 | 0 | ||
Notes receivable from affiliated companies | (3,622) | (3,351) | ||
Materials and supplies, at average cost | 0 | 0 | ||
Derivatives | 0 | 0 | ||
Collateral | 0 | 0 | ||
Prepaid taxes and other | 0 | 0 | ||
Total current assets | (3,948) | (3,963) | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | (281) | (290) | ||
Less — Accumulated provision for depreciation | (189) | (187) | ||
Property, plant and equipment in service net of accumulated provision for depreciation | (92) | (103) | ||
Construction work in progress | 0 | 0 | ||
Total net property, plant and equipment | (92) | (103) | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | (1,153) | (2,923) | ||
Other | 0 | 0 | ||
Total other property and investments | (1,153) | (2,923) | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | (193) | (270) | ||
Property taxes | 0 | 0 | ||
Derivatives | 0 | |||
Other | 25 | 21 | ||
Total deferred charges and other assets | (168) | (249) | ||
Total assets | (5,361) | (7,238) | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | (28) | (26) | ||
Accounts payable- | ||||
Affiliated companies | (319) | (706) | ||
Other | 0 | 0 | ||
Accrued taxes | (13) | (16) | ||
Derivatives | 0 | 0 | ||
Other | 41 | 36 | ||
Total current liabilities | (3,941) | (4,063) | ||
CAPITALIZATION: | ||||
Total equity | (1,075) | (2,834) | ||
Long-term debt and other long-term obligations | (1,065) | (1,091) | ||
Total capitalization | (2,140) | (3,925) | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 723 | 757 | ||
Retirement benefits | 0 | 0 | ||
Asset retirement obligations | 0 | 0 | ||
Other | (3) | (7) | ||
Total noncurrent liabilities | 720 | 750 | ||
Total liabilities and capitalization | (5,361) | (7,238) | ||
Eliminations | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | (3,622) | (3,351) | ||
FES | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 181 | 213 | ||
Affiliated companies | 210 | 332 | ||
Other Receivables | 13 | 17 | ||
Notes receivable from affiliated companies | 366 | 501 | ||
Materials and supplies, at average cost | 41 | 45 | ||
Derivatives | 34 | 137 | ||
Collateral | 105 | 157 | ||
Prepaid taxes and other | 10 | 38 | ||
Total current assets | 960 | 1,440 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 122 | 120 | ||
Less — Accumulated provision for depreciation | 65 | 52 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 57 | 68 | ||
Construction work in progress | 3 | 2 | ||
Total net property, plant and equipment | 60 | 70 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | 1,153 | 2,923 | ||
Other | 0 | 0 | ||
Total other property and investments | 1,153 | 2,923 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 267 | 395 | ||
Property taxes | 0 | 0 | ||
Derivatives | 77 | |||
Other | 45 | 33 | ||
Total deferred charges and other assets | 312 | 505 | ||
Total assets | 2,485 | 4,938 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 0 | 0 | ||
Accounts payable- | ||||
Affiliated companies | 320 | 743 | ||
Other | 22 | 17 | ||
Accrued taxes | 52 | 50 | ||
Derivatives | 22 | 71 | ||
Other | 44 | 56 | ||
Total current liabilities | 3,785 | 3,906 | ||
CAPITALIZATION: | ||||
Total equity | (2,070) | 218 | ||
Long-term debt and other long-term obligations | 691 | 691 | ||
Total capitalization | (1,379) | 909 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Retirement benefits | 28 | 25 | ||
Asset retirement obligations | 0 | 0 | ||
Other | 51 | 98 | ||
Total noncurrent liabilities | 79 | 123 | ||
Total liabilities and capitalization | 2,485 | 4,938 | ||
FES | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 3,325 | 2,969 | ||
FG | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 1 | 2 | 2 | 2 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | 80 | 315 | ||
Other Receivables | 8 | 2 | ||
Notes receivable from affiliated companies | 1,744 | 1,585 | ||
Materials and supplies, at average cost | 142 | 142 | ||
Derivatives | 0 | 0 | ||
Collateral | 25 | 0 | ||
Prepaid taxes and other | 12 | 24 | ||
Total current assets | 2,012 | 2,070 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 2,646 | 2,524 | ||
Less — Accumulated provision for depreciation | 1,947 | 1,920 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 699 | 604 | ||
Construction work in progress | 19 | 67 | ||
Total net property, plant and equipment | 718 | 671 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 9 | 9 | ||
Total other property and investments | 9 | 9 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 790 | 1,271 | ||
Property taxes | 9 | 12 | ||
Derivatives | 0 | |||
Other | 310 | 327 | ||
Total deferred charges and other assets | 1,109 | 1,610 | ||
Total assets | 3,848 | 4,360 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 438 | 200 | ||
Accounts payable- | ||||
Affiliated companies | 60 | 107 | ||
Other | 83 | 93 | ||
Accrued taxes | 12 | 48 | ||
Derivatives | 2 | 6 | ||
Other | 73 | 54 | ||
Total current liabilities | 1,070 | 991 | ||
CAPITALIZATION: | ||||
Total equity | 547 | 828 | ||
Long-term debt and other long-term obligations | 1,666 | 2,093 | ||
Total capitalization | 2,213 | 2,921 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Retirement benefits | 125 | 172 | ||
Asset retirement obligations | 187 | 188 | ||
Other | 253 | 88 | ||
Total noncurrent liabilities | 565 | 448 | ||
Total liabilities and capitalization | 3,848 | 4,360 | ||
FG | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 402 | 483 | ||
NG | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | 260 | 417 | ||
Other Receivables | 0 | 8 | ||
Notes receivable from affiliated companies | 1,512 | 1,294 | ||
Materials and supplies, at average cost | 0 | 80 | ||
Derivatives | 0 | 0 | ||
Collateral | 0 | 0 | ||
Prepaid taxes and other | 0 | 1 | ||
Total current assets | 1,772 | 1,800 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 8 | 4,703 | ||
Less — Accumulated provision for depreciation | 0 | 4,144 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 8 | 559 | ||
Construction work in progress | 0 | 358 | ||
Total net property, plant and equipment | 8 | 917 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 1,856 | 1,552 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 0 | 1 | ||
Total other property and investments | 1,856 | 1,553 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 890 | 883 | ||
Property taxes | 16 | 28 | ||
Derivatives | 0 | |||
Other | 0 | 0 | ||
Total deferred charges and other assets | 906 | 911 | ||
Total assets | 4,542 | 5,181 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 114 | 5 | ||
Accounts payable- | ||||
Affiliated companies | 194 | 406 | ||
Other | 0 | 0 | ||
Accrued taxes | 21 | 61 | ||
Derivatives | 0 | 0 | ||
Other | 11 | 10 | ||
Total current liabilities | 340 | 482 | ||
CAPITALIZATION: | ||||
Total equity | 528 | 2,006 | ||
Long-term debt and other long-term obligations | 1,007 | 1,120 | ||
Total capitalization | 1,535 | 3,126 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Retirement benefits | 0 | 0 | ||
Asset retirement obligations | 1,758 | 713 | ||
Other | 909 | 860 | ||
Total noncurrent liabilities | 2,667 | 1,573 | ||
Total liabilities and capitalization | 4,542 | 5,181 | ||
NG | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 0 | 0 | ||
Consolidated | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 1 | 2 | $ 2 | $ 2 |
Receivables- | ||||
Customers | 181 | 213 | ||
Affiliated companies | 224 | 452 | ||
Other Receivables | 21 | 27 | ||
Notes receivable from affiliated companies | 0 | 29 | ||
Materials and supplies, at average cost | 183 | 267 | ||
Derivatives | 34 | 137 | ||
Collateral | 130 | 157 | ||
Prepaid taxes and other | 22 | 63 | ||
Total current assets | 796 | 1,347 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 2,495 | 7,057 | ||
Less — Accumulated provision for depreciation | 1,823 | 5,929 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 672 | 1,128 | ||
Construction work in progress | 22 | 427 | ||
Total net property, plant and equipment | 694 | 1,555 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 1,856 | 1,552 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 9 | 10 | ||
Total other property and investments | 1,865 | 1,562 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 1,754 | 2,279 | ||
Property taxes | 25 | 40 | ||
Derivatives | 0 | 77 | ||
Other | 380 | 381 | ||
Total deferred charges and other assets | 2,159 | 2,777 | ||
Total assets | 5,514 | 7,241 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 524 | 179 | ||
Accounts payable- | ||||
Affiliated companies | 255 | 550 | ||
Other | 105 | 110 | ||
Accrued taxes | 72 | 143 | ||
Derivatives | 24 | 77 | ||
Other | 169 | 156 | ||
Total current liabilities | 1,254 | 1,316 | ||
CAPITALIZATION: | ||||
Total equity | (2,070) | 218 | ||
Long-term debt and other long-term obligations | 2,299 | 2,813 | ||
Total capitalization | 229 | 3,031 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 723 | 757 | ||
Retirement benefits | 153 | 197 | ||
Asset retirement obligations | 1,945 | 901 | ||
Other | 1,210 | 1,039 | ||
Total noncurrent liabilities | 4,031 | 2,894 | ||
Total liabilities and capitalization | 5,514 | 7,241 | ||
Consolidated | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | $ 105 | $ 101 |
Supplemental Guarantor Infor135
Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ 3,808 | $ 3,383 | $ 3,460 |
New Financing- | |||
Long-term debt | 4,675 | 1,976 | 1,311 |
Short-term borrowings, net | 0 | 975 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (2,291) | (2,331) | (879) |
Short-term borrowings, net | (2,375) | 0 | (91) |
Common stock dividend payments | (639) | (611) | (607) |
Other | (72) | (43) | (26) |
Net cash used for financing activities | (702) | (34) | (292) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,587) | (2,835) | (2,704) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 388 | 15 | 20 |
Sales of investment securities held in trusts | 2,170 | 1,678 | 1,534 |
Purchases of investment securities held in trusts | (2,268) | (1,789) | (1,648) |
Other | 7 | 27 | 8 |
Net cash used for investing activities | (2,716) | (3,281) | (3,122) |
Net change in cash and cash equivalents | 390 | 68 | 46 |
Cash and cash equivalents at beginning of period | 199 | 131 | 85 |
Cash and cash equivalents at end of period | 589 | 199 | 131 |
Eliminations | |||
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | (26) | (25) | (24) |
New Financing- | |||
Long-term debt | 0 | 0 | |
Short-term borrowings, net | (271) | (941) | (863) |
Redemptions and Repayments- | |||
Long-term debt | 26 | 25 | 24 |
Short-term borrowings, net | (98) | ||
Common stock dividend payments | 0 | ||
Other | 0 | 0 | 0 |
Net cash used for financing activities | (245) | (916) | (937) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | 0 | 0 | 0 |
Nuclear fuel | 0 | 0 | 0 |
Proceeds from asset sales | 0 | 0 | |
Sales of investment securities held in trusts | 0 | 0 | 0 |
Purchases of investment securities held in trusts | 0 | 0 | 0 |
Cash investments | 0 | 0 | 0 |
Loans to affiliated companies, net | 271 | 941 | 961 |
Other | 0 | 0 | |
Net cash used for investing activities | 271 | 941 | 961 |
Net change in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 |
Cash and cash equivalents at end of period | 0 | 0 | 0 |
FES | |||
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | (485) | (842) | (637) |
New Financing- | |||
Long-term debt | 0 | 0 | |
Short-term borrowings, net | 356 | 948 | 796 |
Redemptions and Repayments- | |||
Long-term debt | 0 | 0 | (17) |
Short-term borrowings, net | 0 | ||
Common stock dividend payments | (70) | ||
Other | (1) | 0 | 0 |
Net cash used for financing activities | 355 | 948 | 709 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2) | (30) | (5) |
Nuclear fuel | 0 | 0 | 0 |
Proceeds from asset sales | 9 | 10 | |
Sales of investment securities held in trusts | 0 | 0 | 0 |
Purchases of investment securities held in trusts | 0 | 0 | 0 |
Cash investments | (3) | 10 | (10) |
Loans to affiliated companies, net | 135 | (95) | (67) |
Other | 0 | 0 | |
Net cash used for investing activities | 130 | (106) | (72) |
Net change in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 |
Cash and cash equivalents at end of period | 0 | 0 | 0 |
FG | |||
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 516 | 550 | 552 |
New Financing- | |||
Long-term debt | 186 | 45 | |
Short-term borrowings, net | (81) | 94 | 67 |
Redemptions and Repayments- | |||
Long-term debt | (184) | (224) | (70) |
Short-term borrowings, net | 0 | ||
Common stock dividend payments | 0 | ||
Other | (6) | (7) | (6) |
Net cash used for financing activities | (271) | 49 | 36 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (88) | (224) | (223) |
Nuclear fuel | 0 | 0 | 0 |
Proceeds from asset sales | 0 | 3 | |
Sales of investment securities held in trusts | 0 | 0 | 0 |
Purchases of investment securities held in trusts | 0 | 0 | 0 |
Cash investments | 0 | 0 | 0 |
Loans to affiliated companies, net | (158) | (376) | (372) |
Other | 1 | 4 | |
Net cash used for investing activities | (246) | (599) | (588) |
Net change in cash and cash equivalents | (1) | 0 | 0 |
Cash and cash equivalents at beginning of period | 2 | 2 | 2 |
Cash and cash equivalents at end of period | 1 | 2 | 2 |
NG | |||
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 722 | 1,103 | 1,261 |
New Financing- | |||
Long-term debt | 285 | 296 | |
Short-term borrowings, net | 0 | 0 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (5) | (308) | (348) |
Short-term borrowings, net | (28) | ||
Common stock dividend payments | 0 | ||
Other | 0 | (2) | (1) |
Net cash used for financing activities | (5) | (25) | (81) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (185) | (292) | (399) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 0 | 0 | |
Sales of investment securities held in trusts | 940 | 717 | 733 |
Purchases of investment securities held in trusts | (999) | (783) | (791) |
Cash investments | 0 | 0 | 0 |
Loans to affiliated companies, net | (219) | (488) | (533) |
Other | 0 | 0 | |
Net cash used for investing activities | (717) | (1,078) | (1,180) |
Net change in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 |
Cash and cash equivalents at end of period | 0 | 0 | 0 |
Consolidated | |||
Consolidated Statements of Cash Flows [Abstract] | |||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 727 | 786 | 1,152 |
New Financing- | |||
Long-term debt | 0 | 471 | 341 |
Short-term borrowings, net | 4 | 101 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (163) | (507) | (411) |
Short-term borrowings, net | 0 | 0 | (126) |
Common stock dividend payments | 0 | 0 | (70) |
Other | (7) | (9) | (7) |
Net cash used for financing activities | (166) | 56 | (273) |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (275) | (546) | (627) |
Nuclear fuel | (254) | (232) | (190) |
Proceeds from asset sales | 0 | 9 | 13 |
Sales of investment securities held in trusts | 940 | 717 | 733 |
Purchases of investment securities held in trusts | (999) | (783) | (791) |
Cash investments | (3) | 10 | (10) |
Loans to affiliated companies, net | 29 | (18) | (11) |
Other | 0 | 1 | 4 |
Net cash used for investing activities | (562) | (842) | (879) |
Net change in cash and cash equivalents | (1) | 0 | 0 |
Cash and cash equivalents at beginning of period | 2 | 2 | 2 |
Cash and cash equivalents at end of period | $ 1 | $ 2 | $ 2 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | $ (2,499) | $ 396 | $ 174 | $ 205 | $ (5,796) | $ 380 | $ (1,089) | $ 328 | $ (1,724) | $ (6,177) | $ 578 | |||
Segment Financial Information | ||||||||||||||
Revenues | 14,017 | 14,562 | 15,026 | |||||||||||
Total revenues | 3,442 | 3,714 | 3,309 | 3,552 | 3,375 | 3,917 | 3,401 | 3,869 | 14,017 | [1] | 14,562 | [1] | 15,026 | [1] |
Depreciation | 293 | 289 | 281 | 275 | 339 | 311 | 334 | 329 | 1,138 | 1,313 | 1,282 | |||
Amortization of regulatory assets, net | 308 | 297 | 172 | |||||||||||
Impairment of assets and related charges | 2,244 | 31 | 131 | 0 | 9,218 | 0 | 1,447 | 0 | 2,406 | 10,665 | 42 | |||
Investment income (loss) | 98 | 84 | (22) | |||||||||||
Impairment of equity method investment | 0 | 0 | 362 | |||||||||||
Interest expense | 1,178 | 1,157 | 1,132 | |||||||||||
Income taxes (benefits) | 413 | $ 239 | $ 117 | $ 126 | (3,389) | $ 251 | (130) | $ 213 | 895 | (3,055) | 315 | |||
Total assets | 42,257 | 43,148 | 42,257 | 43,148 | 52,094 | |||||||||
Total goodwill | 5,618 | 5,618 | 5,618 | 5,618 | 6,418 | |||||||||
Property additions | 2,587 | 2,835 | 2,704 | |||||||||||
Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Regulated Distribution | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | 916 | 651 | 588 | |||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 9,734 | 9,629 | 9,582 | |||||||||||
Total revenues | 9,734 | 9,629 | 9,582 | |||||||||||
Depreciation | 724 | 676 | 664 | |||||||||||
Amortization of regulatory assets, net | 292 | 290 | 165 | |||||||||||
Impairment of assets and related charges | 0 | 0 | 8 | |||||||||||
Investment income (loss) | 54 | 49 | 42 | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 535 | 586 | 600 | |||||||||||
Income taxes (benefits) | 580 | 375 | 325 | |||||||||||
Total assets | 27,730 | 27,702 | 27,730 | 27,702 | 27,390 | |||||||||
Total goodwill | 5,004 | 5,004 | 5,004 | 5,004 | 5,092 | |||||||||
Property additions | 1,191 | 1,063 | 1,040 | |||||||||||
Regulated Distribution | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Regulated Transmission | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | 336 | 331 | 328 | |||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 1,325 | 1,144 | 1,046 | |||||||||||
Total revenues | 1,325 | 1,144 | 1,046 | |||||||||||
Depreciation | 224 | 187 | 164 | |||||||||||
Amortization of regulatory assets, net | 16 | 7 | 7 | |||||||||||
Impairment of assets and related charges | 41 | 0 | 0 | |||||||||||
Investment income (loss) | 0 | 0 | 0 | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 156 | 158 | 147 | |||||||||||
Income taxes (benefits) | 205 | 187 | 191 | |||||||||||
Total assets | 9,525 | 8,755 | 9,525 | 8,755 | 7,800 | |||||||||
Total goodwill | 614 | 614 | 614 | 614 | 526 | |||||||||
Property additions | 1,030 | 1,101 | 1,020 | |||||||||||
Regulated Transmission | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Competitive Energy Services | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | (2,641) | (6,919) | 89 | |||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 3,143 | 4,070 | 4,698 | |||||||||||
Total revenues | 3,529 | 4,549 | 5,384 | |||||||||||
Depreciation | 118 | 387 | 394 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets and related charges | $ 647 | 2,365 | 10,665 | 34 | ||||||||||
Investment income (loss) | 81 | 66 | (16) | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 179 | 194 | 192 | |||||||||||
Income taxes (benefits) | 155 | (3,498) | 50 | |||||||||||
Total assets | 4,339 | 5,952 | 4,339 | 5,952 | 16,027 | |||||||||
Total goodwill | 0 | 0 | 0 | 0 | 800 | |||||||||
Property additions | 317 | 619 | 588 | |||||||||||
Competitive Energy Services | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 386 | 479 | 686 | |||||||||||
Other/Corporate | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | (335) | (240) | (427) | |||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Total revenues | 0 | 0 | 0 | |||||||||||
Depreciation | 72 | 63 | 60 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets and related charges | 0 | 0 | 0 | |||||||||||
Investment income (loss) | 11 | 10 | (9) | |||||||||||
Impairment of equity method investment | 362 | |||||||||||||
Interest expense | 308 | 219 | 193 | |||||||||||
Income taxes (benefits) | (45) | (119) | (251) | |||||||||||
Total assets | 663 | 739 | 663 | 739 | 877 | |||||||||
Total goodwill | 0 | 0 | 0 | 0 | 0 | |||||||||
Property additions | 49 | 52 | 56 | |||||||||||
Other/Corporate | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Reconciling Adjustments | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
NET INCOME (LOSS) | 0 | 0 | 0 | |||||||||||
Segment Financial Information | ||||||||||||||
Revenues | (185) | (281) | (300) | |||||||||||
Total revenues | (571) | (760) | (986) | |||||||||||
Depreciation | 0 | 0 | 0 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets and related charges | 0 | 0 | 0 | |||||||||||
Investment income (loss) | (48) | (41) | (39) | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 0 | 0 | 0 | |||||||||||
Income taxes (benefits) | 0 | 0 | 0 | |||||||||||
Total assets | 0 | 0 | 0 | 0 | 0 | |||||||||
Total goodwill | $ 0 | $ 0 | 0 | 0 | 0 | |||||||||
Property additions | 0 | 0 | 0 | |||||||||||
Reconciling Adjustments | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | $ (386) | $ (479) | $ (686) | |||||||||||
[1] | Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. |
Segment Information (Details Te
Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Millions | Jan. 22, 2018USD ($) | Dec. 31, 2017USD ($)mi²customercompanyMW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Aug. 31, 2017MW | Mar. 06, 2017MW |
Segment Reporting Information [Line Items] | ||||||
Repayments of debt | $ 2,291 | $ 2,331 | $ 879 | |||
Subsequent Event | ||||||
Segment Reporting Information [Line Items] | ||||||
Repayments of debt | $ 1,450 | |||||
Proceeds from issuance of equity | $ 2,500 | |||||
Other/Corporate | ||||||
Segment Reporting Information [Line Items] | ||||||
Long-term debt and other long-term obligations | 6,800 | |||||
Debt subject to variable interest rate | $ 1,450 | |||||
Regulated Distribution | ||||||
Segment Reporting Information [Line Items] | ||||||
Number of existing utility operating companies | company | 10 | |||||
Number of customers served by utility operating companies | customer | 6 | |||||
Number of square miles in service area | mi² | 65 | |||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 3,790 | |||||
CES | ||||||
Segment Reporting Information [Line Items] | ||||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 12,303 | |||||
FE | Revolving Credit Facility | Other/Corporate | ||||||
Segment Reporting Information [Line Items] | ||||||
Long-term line of credit | $ 300 | |||||
Pleasants Power Station | ||||||
Segment Reporting Information [Line Items] | ||||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 1,300 | |||||
Purchase Agreement with Aspen Generating, LLC | ||||||
Segment Reporting Information [Line Items] | ||||||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW | 756 | 1,615 |
Summary of Quarterly Financi138
Summary of Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||||
Quarterly Financial Data [Line Items] | ||||||||||||||
Revenues | $ 3,442 | $ 3,714 | $ 3,309 | $ 3,552 | $ 3,375 | $ 3,917 | $ 3,401 | $ 3,869 | $ 14,017 | [1] | $ 14,562 | [1] | $ 15,026 | [1] |
Other operating expenses | 1,195 | 940 | 956 | 1,141 | 1,021 | 950 | 963 | 917 | 4,232 | 3,851 | 3,740 | |||
Pension and OPEB mark-to-market adjustment | 141 | 0 | 0 | 0 | 147 | 0 | 0 | 0 | 141 | 147 | 242 | |||
Provision for depreciation | 293 | 289 | 281 | 275 | 339 | 311 | 334 | 329 | 1,138 | 1,313 | 1,282 | |||
Impairment of assets and related charges | 2,244 | 31 | 131 | 0 | 9,218 | 0 | 1,447 | 0 | 2,406 | 10,665 | 42 | |||
Operating Income (Loss) | (1,830) | 884 | 544 | 574 | (8,924) | 861 | (975) | 776 | 172 | (8,262) | 2,292 | |||
Income (loss) before income taxes (benefits) | (2,086) | 635 | 291 | 331 | (9,185) | 631 | (1,219) | 541 | ||||||
Income taxes (benefits) | 413 | 239 | 117 | 126 | (3,389) | 251 | (130) | 213 | 895 | (3,055) | 315 | |||
Net income (loss) | $ (2,499) | $ 396 | $ 174 | $ 205 | $ (5,796) | $ 380 | $ (1,089) | $ 328 | $ (1,724) | $ (6,177) | $ 578 | |||
Earnings (loss) per share of common stock- | ||||||||||||||
Basic earnings (loss) per share of common stock, in dollars per share | $ (5.62) | $ 0.89 | $ 0.39 | $ 0.46 | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.78 | $ (3.88) | $ (14.49) | $ 1.37 | |||
Diluted earnings (loss) per share of common stock, in dollars per share | $ (5.62) | $ 0.89 | $ 0.39 | $ 0.46 | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.77 | $ (3.88) | $ (14.49) | $ 1.37 | |||
FES | ||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||
Revenues | $ 700 | $ 743 | $ 741 | $ 914 | $ 997 | $ 1,100 | $ 1,102 | $ 1,199 | $ 3,098 | [2] | $ 4,398 | [2] | $ 5,005 | [2] |
Other operating expenses | 419 | 291 | 286 | 518 | 352 | 316 | 369 | 240 | 1,514 | 1,277 | 1,308 | |||
Pension and OPEB mark-to-market adjustment | 24 | 0 | 0 | 0 | 48 | 0 | 0 | 0 | 24 | 48 | 57 | |||
Provision for depreciation | 29 | 28 | 27 | 25 | 86 | 83 | 84 | 83 | 109 | 336 | 324 | |||
Impairment of assets and related charges | 2,031 | 0 | 0 | 0 | 8,082 | 0 | 540 | 0 | 2,031 | 8,622 | 33 | |||
Operating Income (Loss) | (2,112) | 102 | 61 | (117) | (8,153) | 101 | (571) | 226 | (2,066) | (8,397) | 277 | |||
Income (loss) before income taxes (benefits) | (2,125) | 108 | 42 | (121) | (8,171) | 96 | (581) | 213 | ||||||
Income taxes (benefits) | 281 | 32 | 23 | (41) | (2,983) | 56 | (143) | 82 | 295 | (2,988) | 65 | |||
Net income (loss) | $ (2,406) | $ 76 | $ 19 | $ (80) | $ (5,188) | $ 40 | $ (438) | $ 131 | $ (2,391) | $ (5,455) | $ 82 | |||
[1] | Includes excise tax collections of $390 million, $406 million and $416 million in 2017, 2016 and 2015, respectively. | |||||||||||||
[2] | Includes excise tax collections of $20 million, $28 million and $44 million in 2017, 2016 and 2015, respectively. |
Subsequent Events (Details)
Subsequent Events (Details) | Jan. 22, 2018USD ($)employees$ / sharesshares | Dec. 31, 2017$ / shares | Dec. 31, 2016$ / shares |
Subsequent Event [Line Items] | |||
Par Value, in dollars per share | $ 100 | ||
Common stock, par value (in dollars per share) | $ 0.1 | $ 0.1 | |
Subsequent Event | |||
Subsequent Event [Line Items] | |||
Proceeds from issuance of equity | $ | $ 2,500,000,000 | ||
Par Value, in dollars per share | $ 100 | ||
Amount of private placement shares | shares | 30,120,482 | ||
Common stock, par value (in dollars per share) | $ 0.10 | ||
Amount of private placement | $ | $ 850,000,000 | ||
Liquidation preference value | $ | $ 1,000 | ||
Conversion price (in dollars per share) | $ 27.42 | ||
Conversion threshold of Preferred Stock (in shares) | shares | 323,200 | ||
Common stock share cap (in shares) | shares | 58,964,222 | ||
RWG number of board members | employees | 2 | ||
Series A Convertible Preferred Stock | Subsequent Event | |||
Subsequent Event [Line Items] | |||
Preferred stock shares issued | shares | 1,616,000 | ||
Amount of preferred stock investment | $ | $ 1,620,000,000 | ||
FE | Subsequent Event | |||
Subsequent Event [Line Items] | |||
RWG number of board members | employees | 3 |
Consolidated Valuation and Q140
Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accumulated provision for uncollectible accounts - customers | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | $ 53,307 | $ 68,775 | $ 59,266 |
Charged to Income | 75,859 | 81,719 | 114,249 |
Charged to Other Accounts | 49,728 | 15,222 | 54,199 |
Deductions | 127,607 | 112,409 | 158,939 |
Ending Balance | 51,287 | 53,307 | 68,775 |
Accumulated provision for uncollectible accounts - customers | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 4,898 | 8,466 | 17,862 |
Charged to Income | 2,373 | 4,766 | 7,411 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 4,921 | 8,334 | 16,807 |
Ending Balance | 2,350 | 4,898 | 8,466 |
Accumulated provision for uncollectible accounts - other | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 884 | 5,231 | 5,197 |
Charged to Income | 6,495 | 13,597 | 899 |
Charged to Other Accounts | 0 | 11,329 | 4,189 |
Deductions | 6,357 | 29,273 | 5,054 |
Ending Balance | 1,022 | 884 | 5,231 |
Accumulated provision for uncollectible accounts - other | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 0 | 2,500 | 2,500 |
Charged to Income | 34 | 0 | 0 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 2 | 2,500 | 0 |
Ending Balance | 32 | 0 | 2,500 |
Valuation allowance on state and local DTAs | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 437,779 | 192,397 | 174,004 |
Charged to Income | 142,623 | 245,382 | 18,393 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 0 | 0 | 0 |
Ending Balance | 580,402 | 437,779 | 192,397 |
Valuation allowance on state and local DTAs | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 197,490 | 45,808 | 32,126 |
Charged to Income | 70,777 | 151,682 | 13,682 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 0 | 0 | 0 |
Ending Balance | $ 268,267 | $ 197,490 | $ 45,808 |