Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Jan. 31, 2017 | Jun. 30, 2016 | |
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, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock Shares Outstanding | 442,477,633 | ||
Entity Public Float | $ 14,809,049,520 | ||
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, 2016 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,016 | ||
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
REVENUES: | ||||
Regulated Distribution | $ 9,629 | $ 9,625 | $ 9,102 | |
Regulated Transmission | 1,151 | 1,011 | 769 | |
Unregulated businesses | 3,782 | 4,390 | 5,178 | |
Total revenues | [1] | 14,562 | 15,026 | 15,049 |
OPERATING EXPENSES: | ||||
Fuel | 1,666 | 1,855 | 2,280 | |
Purchased power | 3,813 | 4,318 | 4,716 | |
Other operating expenses | 3,858 | 3,749 | 3,962 | |
Pension and OPEB mark-to-market adjustment | 147 | 242 | 835 | |
Provision for depreciation | 1,313 | 1,282 | 1,220 | |
Amortization of regulatory assets, net | 320 | 268 | 12 | |
General taxes | 1,042 | 978 | 962 | |
Impairment of assets (Note 2) | 10,665 | 42 | 0 | |
Total operating expenses | 22,824 | 12,734 | 13,987 | |
OPERATING INCOME (LOSS) | (8,262) | 2,292 | 1,062 | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss) | 84 | (22) | 72 | |
Impairment of equity method investment (Note 2) | 0 | (362) | 0 | |
Interest expense | (1,157) | (1,132) | (1,081) | |
Capitalized financing costs | 103 | 117 | 118 | |
Total other expense | (970) | (1,399) | (891) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (9,232) | 893 | 171 | |
INCOME TAXES (BENEFITS) | (3,055) | 315 | (42) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | (6,177) | 578 | 213 | |
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | 0 | 86 | |
NET INCOME (LOSS) | $ (6,177) | $ 578 | $ 299 | |
EARNINGS (LOSS) PER SHARE OF COMMON STOCK: | ||||
Basic - Continuing Operations, in dollars per share | $ (14.49) | $ 1.37 | $ 0.51 | |
Basic - Discontinued Operations, in dollars per share | 0 | 0 | 0.20 | |
Basic - Net Income (Loss), in dollars per share | (14.49) | 1.37 | 0.71 | |
Diluted - Continuing Operations, in dollars per share | (14.49) | 1.37 | 0.51 | |
Diluted - Discontinued Operations, in dollars per share | 0 | 0 | 0.20 | |
Diluted - Net Income (Loss), in dollars per share | $ (14.49) | $ 1.37 | $ 0.71 | |
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: | ||||
Basic, in shares | 426 | 422 | 420 | |
Diluted, in shares | 426 | 424 | 421 | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share | $ 1.44 | $ 1.44 | $ 1.44 | |
[1] | Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively. |
Consolidated Statements of Inc3
Consolidated Statements of Income (Loss) (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Statement [Abstract] | |||
Tax effect of discontinued operations | $ 0 | $ 0 | $ 69 |
Excise tax collections included in Revenue | $ 406 | $ 416 | $ 420 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) (FirstEnergy Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Comprehensive Income [Abstract] | |||
NET INCOME (LOSS) | $ (6,177) | $ 578 | $ 299 |
OTHER COMPREHENSIVE INCOME (LOSS): | |||
Pension and OPEB prior service costs | (59) | (116) | (76) |
Amortized losses (gains) on derivative hedges | 8 | 5 | (2) |
Change in unrealized gain on available-for-sale securities | 55 | (11) | 26 |
Other comprehensive income (loss) | 4 | (122) | (52) |
Income taxes (benefits) on other comprehensive income (loss) | 1 | (47) | (14) |
Other comprehensive income (loss), net of tax | 3 | (75) | (38) |
COMPREHENSIVE INCOME (LOSS) | $ (6,174) | $ 503 | $ 261 |
Consolidated Balance Sheets (Fi
Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 199 | $ 131 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $53 in 2016 and $69 in 2015 | 1,440 | 1,415 |
Other, net of allowance for uncollectible accounts of $1 in 2016 and $5 in 2015 | 175 | 180 |
Materials and supplies, at average cost | 564 | 785 |
Prepaid taxes | 98 | 135 |
Derivatives | 140 | 157 |
Collateral | 176 | 70 |
Other | 158 | 167 |
Total current assets | 2,950 | 3,040 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 43,767 | 49,952 |
Less — Accumulated provision for depreciation | 15,731 | 15,160 |
Property, plant and equipment in service net of accumulated provision for depreciation | 28,036 | 34,792 |
Construction work in progress | 1,351 | 2,422 |
Total net property, plant and equipment | 29,387 | 37,214 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 2,514 | 2,282 |
Other | 512 | 506 |
Total other property and investments | 3,026 | 2,788 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Goodwill | 5,618 | 6,418 |
Regulatory assets | 1,014 | 1,348 |
Other | 1,153 | 1,286 |
Total deferred charges and other assets | 7,785 | 9,052 |
Total assets | 43,148 | 52,094 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,685 | 1,166 |
Short-term borrowings | 2,675 | 1,708 |
Accounts payable | 1,043 | 1,075 |
Accrued taxes | 580 | 519 |
Accrued compensation and benefits | 363 | 334 |
Derivatives | 78 | 106 |
Collateral | 42 | 52 |
Other | 660 | 642 |
Total current liabilities | 7,126 | 5,602 |
Common stockholders’ equity- | ||
Common stock, $0.10 par value, authorized 490,000,000 shares - 442,344,218 and 423,560,397 shares outstanding as of December 31, 2016 and December 31, 2015, respectively | 44 | 42 |
Other paid-in capital | 10,555 | 9,952 |
Accumulated other comprehensive income | 174 | 171 |
Retained earnings (Accumulated deficit) | (4,532) | 2,256 |
Total common stockholders’ equity | 6,241 | 12,421 |
Noncontrolling interest | 0 | 1 |
Total equity | 6,241 | 12,422 |
Long-term debt and other long-term obligations | 18,192 | 19,099 |
Total capitalization | 24,433 | 31,521 |
NONCURRENT LIABILITIES: | ||
Accumulated deferred income taxes | 3,765 | 6,773 |
Retirement benefits | 3,719 | 4,245 |
Asset retirement obligations | 1,482 | 1,410 |
Deferred gain on sale and leaseback transaction | 757 | 791 |
Adverse power contract liability | 162 | 197 |
Other | 1,704 | 1,555 |
Total noncurrent liabilities | 11,589 | 14,971 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | $ 43,148 | $ 52,094 |
Consolidated Balance Sheets (F6
Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Common stockholders’ equity- | ||
Common stock, par value (in dollars per share) | $ 0.1 | $ 0.1 |
Common stock, shares authorized | 490,000,000 | 490,000,000 |
Common stock, shares outstanding | 442,344,218 | 423,560,397 |
Customer [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 53 | $ 69 |
Other [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 1 | $ 5 |
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, 2013 | 418,628,559 | ||||
Beginning Balance at Dec. 31, 2013 | $ 42 | $ 9,776 | $ 284 | $ 2,590 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income (loss) | $ 299 | 299 | |||
Amortized gain (loss) on derivative hedges, net of income taxes | (1) | ||||
Change in unrealized gain on investments, net of income taxes | 16 | ||||
Pensions and OPEB, net of income taxes | (53) | ||||
Stock-based compensation | 20 | ||||
Cash dividends declared on common stock | (604) | ||||
Stock Investment Plan and certain share-based benefit plans, Shares | 2,474,011 | ||||
Stock Investment Plan and certain share-based benefit plans | 51 | ||||
Ending Balance, Shares at Dec. 31, 2014 | 421,102,570 | ||||
Ending 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 | 423,560,397 | |||
Ending Balance at Dec. 31, 2015 | $ 12,421 | $ 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) | $ 2 | 498 | |||
Stock issuance (Note 12), Shares | 16,097,875 | ||||
Ending Balance, Shares at Dec. 31, 2016 | 442,344,218 | 442,344,218 | |||
Ending Balance at Dec. 31, 2016 | $ 6,241 | $ 44 | $ 10,555 | $ 174 | $ (4,532) |
Consolidated Statements of Com8
Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Statement of Stockholders' Equity [Abstract] | |||
Unrealized gain (loss) on derivative hedges taxes | $ 3 | $ 1 | $ (1) |
Unrealized gain (loss) on investment taxes | 21 | 4 | 10 |
Taxes on pension and other postretirement taxes | $ (23) | $ (44) | $ (23) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net Income (loss) | $ (6,177) | $ 578 | $ 299 |
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 | 1,997 | 1,922 | 1,592 |
Impairment of assets | 10,665 | 42 | 0 |
Investment impairment, including equity method investments | 21 | 464 | 37 |
Pension and OPEB mark-to-market adjustment | 147 | 242 | 835 |
Deferred income taxes and investment tax credits, net | (3,063) | 284 | 162 |
Deferred costs on sale leaseback transaction, net | 49 | 48 | 48 |
Deferred purchased power and fuel costs | (30) | (105) | (115) |
Asset removal costs charged to income | 54 | 55 | 28 |
Retirement benefits | 64 | (20) | (53) |
Commodity derivative transactions, net (Note 11) | 9 | (73) | 64 |
Pension trust contributions | (382) | (143) | 0 |
Gain on sale of investment securities held in trusts | (50) | (23) | (64) |
Lease payments on sale and leaseback transaction | (120) | (131) | (137) |
Income from discontinued operations (Note 20) | 0 | 0 | (86) |
Changes in current assets and liabilities- | |||
Receivables | (11) | 184 | 139 |
Materials and supplies | 41 | (15) | (65) |
Prepayments and other current assets | 27 | (10) | 126 |
Accounts payable | (37) | (243) | 42 |
Accrued taxes | 61 | 29 | (165) |
Accrued compensation and benefits | 29 | 5 | (22) |
Other current liabilities | 56 | 69 | 54 |
Cash collateral, net | (116) | 140 | (54) |
Other | 137 | 148 | 48 |
Net cash provided from operating activities | 3,371 | 3,447 | 2,713 |
New Financing- | |||
Long-term debt | 1,976 | 1,311 | 4,528 |
Short-term borrowings, net | 975 | 0 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (2,331) | (879) | (1,759) |
Short-term borrowings, net | 0 | (91) | (1,605) |
Common stock dividend payments | (611) | (607) | (604) |
Other | (31) | (13) | (47) |
Net cash (used for) provided from financing activities | (22) | (279) | 513 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,835) | (2,704) | (3,312) |
Nuclear fuel | (232) | (190) | (233) |
Proceeds from asset sales | 15 | 20 | 394 |
Sales of investment securities held in trusts | 1,678 | 1,534 | 2,133 |
Purchases of investment securities held in trusts | (1,789) | (1,648) | (2,236) |
Asset removal costs | (145) | (142) | (153) |
Other | 27 | 8 | 48 |
Net cash used for investing activities | (3,281) | (3,122) | (3,359) |
Net change in cash and cash equivalents | 68 | 46 | (133) |
Cash and cash equivalents at beginning of period | 131 | 85 | 218 |
Cash and cash equivalents at end of period | 199 | 131 | 85 |
SUPPLEMENTAL CASH FLOW INFORMATION: | |||
Non-cash transaction: stock contribution to pension plan | 500 | 0 | 0 |
Interest (net of amounts capitalized) | 1,050 | 1,028 | 931 |
Income taxes (received), net of refunds | $ (16) | $ 37 | $ (103) |
Consolidated Statements of In10
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
REVENUES: | ||||
Electric sales | $ 3,782 | $ 4,390 | $ 5,178 | |
Total revenues | [1] | 14,562 | 15,026 | 15,049 |
OPERATING EXPENSES: | ||||
Fuel | 1,666 | 1,855 | 2,280 | |
Purchased power | 3,813 | 4,318 | 4,716 | |
Other operating expenses | 3,858 | 3,749 | 3,962 | |
Pension and OPEB mark-to-market adjustment | 147 | 242 | 835 | |
Provision for depreciation | 1,313 | 1,282 | 1,220 | |
General taxes | 1,042 | 978 | 962 | |
Impairment of assets (Note 2) | 10,665 | 42 | 0 | |
Total operating expenses | 22,824 | 12,734 | 13,987 | |
OPERATING INCOME (LOSS) | (8,262) | 2,292 | 1,062 | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss), including net income from equity investees | 84 | (22) | 72 | |
Interest expense | (1,157) | (1,132) | (1,081) | |
Capitalized interest | 103 | 117 | 118 | |
Total other expense | (970) | (1,399) | (891) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (9,232) | 893 | 171 | |
INCOME TAXES (BENEFITS) | (3,055) | 315 | (42) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | (6,177) | 578 | 213 | |
Discontinued operations (net of income taxes of $70) (Note 20) | 0 | 0 | 86 | |
NET INCOME (LOSS) | (6,177) | 578 | 299 | |
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||
NET INCOME (LOSS) | (6,177) | 578 | 299 | |
OTHER COMPREHENSIVE INCOME (LOSS): | ||||
Pension and OPEB prior service costs | (59) | (116) | (76) | |
Amortized gain on derivative hedges | 8 | 5 | (2) | |
Change in unrealized gain on available-for-sale securities | 55 | (11) | 26 | |
Other comprehensive income (loss) | 4 | (122) | (52) | |
Income taxes (benefits) on other comprehensive income (loss ) | 1 | (47) | (14) | |
Other comprehensive income (loss), net of tax | 3 | (75) | (38) | |
FES | ||||
REVENUES: | ||||
Other | 160 | 188 | 169 | |
Total revenues | [2] | 4,398 | 5,005 | 6,144 |
OPERATING EXPENSES: | ||||
Fuel | 780 | 871 | 1,253 | |
Other operating expenses | 1,277 | 1,308 | 1,635 | |
Pension and OPEB mark-to-market adjustment | 48 | 57 | 297 | |
Provision for depreciation | 336 | 324 | 319 | |
General taxes | 88 | 98 | 128 | |
Impairment of assets (Note 2) | 8,622 | 33 | 0 | |
Total operating expenses | 12,795 | 4,728 | 6,674 | |
OPERATING INCOME (LOSS) | (8,397) | 277 | (530) | |
OTHER INCOME (EXPENSE): | ||||
Investment income (loss), including net income from equity investees | 67 | (14) | 61 | |
Miscellaneous income | 7 | 3 | 6 | |
Capitalized interest | 34 | 35 | 34 | |
Total other expense | (46) | (130) | (58) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (8,443) | 147 | (588) | |
INCOME TAXES (BENEFITS) | (2,988) | 65 | (228) | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | (5,455) | 82 | (360) | |
Discontinued operations (net of income taxes of $70) (Note 20) | 0 | 0 | 116 | |
NET INCOME (LOSS) | (5,455) | 82 | (244) | |
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||
NET INCOME (LOSS) | (5,455) | 82 | (244) | |
OTHER COMPREHENSIVE INCOME (LOSS): | ||||
Pension and OPEB prior service costs | (14) | (6) | (6) | |
Amortized gain on derivative hedges | 0 | (3) | (10) | |
Change in unrealized gain on available-for-sale securities | 52 | (9) | 21 | |
Other comprehensive income (loss) | 38 | (18) | 5 | |
Income taxes (benefits) on other comprehensive income (loss ) | 15 | (7) | 2 | |
Other comprehensive income (loss), net of tax | 23 | (11) | 3 | |
COMPREHENSIVE INCOME (LOSS) | (5,432) | 71 | (241) | |
FES | Affiliates | ||||
REVENUES: | ||||
Electric sales | 457 | 664 | 861 | |
OPERATING EXPENSES: | ||||
Purchased power | 624 | 353 | 271 | |
OTHER INCOME (EXPENSE): | ||||
Interest expense | (7) | (7) | (7) | |
FES | Non-Affiliates | ||||
REVENUES: | ||||
Electric sales | 3,781 | 4,153 | 5,114 | |
OPERATING EXPENSES: | ||||
Purchased power | 1,020 | 1,684 | 2,771 | |
OTHER INCOME (EXPENSE): | ||||
Interest expense | $ (147) | $ (147) | $ (152) | |
[1] | Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively. | |||
[2] | Includes excise tax collections of $28 million, $44 million and $69 million in 2016, 2015 and 2014, respectively. |
Consolidated Statements of In11
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Tax effect of discontinued operations | $ 0 | $ 0 | $ 69 |
Excise tax collections included in Revenue | 406 | 416 | 420 |
FES | |||
Tax effect of discontinued operations | 0 | 0 | 70 |
Excise tax collections included in Revenue | $ 28 | $ 44 | $ 69 |
Consolidated Balance Sheets (12
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 199 | $ 131 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $5 in 2016 and $8 in 2015 | 1,440 | 1,415 |
Other, net of allowance for uncollectible accounts of $0 in 2016 and $3 in 2015 | 175 | 180 |
Materials and supplies | 564 | 785 |
Derivatives | 140 | 157 |
Collateral | 176 | 70 |
Prepayments and other | 158 | 167 |
Total current assets | 2,950 | 3,040 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 43,767 | 49,952 |
Less — Accumulated provision for depreciation | 15,731 | 15,160 |
Property, plant and equipment in service net of accumulated provision for depreciation | 28,036 | 34,792 |
Construction work in progress | 1,351 | 2,422 |
Total net property, plant and equipment | 29,387 | 37,214 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 2,514 | 2,282 |
Other | 512 | 506 |
Total other property and investments | 3,026 | 2,788 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Customer intangibles | 120 | |
Goodwill | 5,618 | 6,418 |
Accumulated deferred income taxes | 2,279 | 0 |
Other | 1,153 | 1,286 |
Total deferred charges and other assets | 7,785 | 9,052 |
Total assets | 43,148 | 52,094 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 1,685 | 1,166 |
Short-term borrowings- | ||
Short-term borrowings | 2,675 | 1,708 |
Accounts payable- | ||
Accrued taxes | 580 | 519 |
Derivatives | 78 | 106 |
Other | 660 | 642 |
Total current liabilities | 7,126 | 5,602 |
Common stockholders’ equity- | ||
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of December 31, 2016 and 2015 | 44 | 42 |
Accumulated other comprehensive income | 174 | 171 |
Retained earnings (Accumulated deficit) | (4,532) | 2,256 |
Total common stockholders’ equity | 6,241 | 12,421 |
Long-term debt and other long-term obligations | 18,192 | 19,099 |
Total capitalization | 24,433 | 31,521 |
NONCURRENT LIABILITIES: | ||
Deferred gain on sale and leaseback transaction | 757 | 791 |
Accumulated deferred income taxes | 3,765 | 6,773 |
Retirement benefits | 3,719 | 4,245 |
Asset retirement obligations | 1,482 | 1,410 |
Other | 1,704 | 1,555 |
Total noncurrent liabilities | 11,589 | 14,971 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | 43,148 | 52,094 |
FES | ||
CURRENT ASSETS: | ||
Cash and cash equivalents | 2 | 2 |
Receivables- | ||
Customers, net of allowance for uncollectible accounts of $5 in 2016 and $8 in 2015 | 213 | 275 |
Affiliated companies | 452 | 451 |
Other, net of allowance for uncollectible accounts of $0 in 2016 and $3 in 2015 | 27 | 59 |
Notes receivable from affiliated companies | 29 | 11 |
Materials and supplies | 267 | 470 |
Derivatives | 137 | 154 |
Collateral | 157 | 70 |
Prepayments and other | 63 | 66 |
Total current assets | 1,347 | 1,558 |
PROPERTY, PLANT AND EQUIPMENT: | ||
In service | 7,057 | 14,311 |
Less — Accumulated provision for depreciation | 5,929 | 5,765 |
Property, plant and equipment in service net of accumulated provision for depreciation | 1,128 | 8,546 |
Construction work in progress | 427 | 1,157 |
Total net property, plant and equipment | 1,555 | 9,703 |
INVESTMENTS: | ||
Nuclear plant decommissioning trusts | 1,552 | 1,327 |
Other | 10 | 10 |
Total other property and investments | 1,562 | 1,337 |
DEFERRED CHARGES AND OTHER ASSETS: | ||
Customer intangibles | 9 | 61 |
Goodwill | 0 | 23 |
Property taxes | 40 | 40 |
Derivatives | 77 | 79 |
Other | 372 | 367 |
Total deferred charges and other assets | 2,777 | 570 |
Total assets | 7,241 | 13,168 |
CURRENT LIABILITIES: | ||
Currently payable long-term debt | 179 | 512 |
Short-term borrowings- | ||
Short-term borrowings | 0 | 8 |
Accounts payable- | ||
Affiliated companies | 550 | 542 |
Other | 110 | 139 |
Accrued taxes | 143 | 76 |
Derivatives | 77 | 104 |
Other | 156 | 181 |
Total current liabilities | 1,316 | 1,562 |
Common stockholders’ equity- | ||
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of December 31, 2016 and 2015 | 3,658 | 3,613 |
Accumulated other comprehensive income | 69 | 46 |
Retained earnings (Accumulated deficit) | (3,509) | 1,946 |
Total common stockholders’ equity | 218 | 5,605 |
Long-term debt and other long-term obligations | 2,813 | 2,510 |
Total capitalization | 3,031 | 8,115 |
NONCURRENT LIABILITIES: | ||
Deferred gain on sale and leaseback transaction | 757 | 791 |
Accumulated deferred income taxes | 0 | 600 |
Retirement benefits | 197 | 332 |
Asset retirement obligations | 901 | 831 |
Derivatives | 52 | 38 |
Other | 987 | 899 |
Total noncurrent liabilities | 2,894 | 3,491 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 16) | ||
Total liabilities and capitalization | 7,241 | 13,168 |
FES | Affiliates | ||
Short-term borrowings- | ||
Other Short-term Borrowings | $ 101 | $ 0 |
Consolidated Balance Sheets (13
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Common stockholders’ equity- | ||
Common stock, shares authorized | 490,000,000 | 490,000,000 |
Common stock, shares outstanding | 442,344,218 | 423,560,397 |
Customer [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 53 | $ 69 |
Other Receivables [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 1 | $ 5 |
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) | $ 5 | $ 8 |
FES | Other Receivables [Member] | ||
Receivables- | ||
Allowance for uncollectible accounts (in dollars) | $ 0 | $ 3 |
Consolidated Statements of Co14
Consolidated Statements of Common Stockholders' Equity (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, 2013 | 418,628,559 | 7 | ||||||
Beginning Balance at Dec. 31, 2013 | $ 42 | $ 284 | $ 2,590 | $ 3,080 | $ 54 | $ 2,178 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net Income (loss) | $ 299 | $ (244) | (244) | |||||
Amortized loss on derivative hedges, net of income taxes | (1) | (6) | ||||||
Change in unrealized gain on investments, net of income taxes | 16 | 13 | ||||||
Pensions and OPEB, net of income taxes | (53) | (4) | ||||||
Equity contribution from parent | 500 | 500 | ||||||
Stock-based compensation | 7 | |||||||
Consolidated tax benefit allocation | $ 7 | |||||||
Cash dividends declared on common stock | (604) | |||||||
Ending Balance, Shares at Dec. 31, 2014 | 421,102,570 | 7 | ||||||
Ending 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 | $ 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) | ||||||
Equity contribution from parent | 0 | |||||||
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 | 423,560,397 | 7 | 7 | ||||
Ending Balance at Dec. 31, 2015 | $ 12,421 | $ 42 | 171 | 2,256 | $ 5,605 | $ 3,613 | 46 | 1,946 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||||
Net Income (loss) | $ (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) | ||||||
Equity contribution from parent | $ 0 | |||||||
Inter-company asset transfer | 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 | $ 6,241 | $ 44 | $ 174 | $ (4,532) | $ 218 | $ 3,658 | $ 69 | $ (3,509) |
Consolidated Statements of Co15
Consolidated Statements of Common Stockholders' Equity (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Unrealized gain (loss) on derivative hedges taxes | $ 3 | $ 1 | $ (1) |
Unrealized gain (loss) on investment taxes | 21 | 4 | 10 |
Taxes on pension and other postretirement taxes | (23) | (44) | (23) |
FES | |||
Unrealized gain (loss) on derivative hedges taxes | 0 | (1) | (4) |
Unrealized gain (loss) on investment taxes | 20 | (4) | 8 |
Taxes on pension and other postretirement taxes | $ (5) | $ (2) | $ (2) |
Consolidated Statements of Ca16
Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net Income (loss) | $ (6,177) | $ 578 | $ 299 |
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 | 1,997 | 1,922 | 1,592 |
Investment impairment, including equity method investments | 21 | 464 | 37 |
Pension and OPEB mark-to-market adjustment | 147 | 242 | 835 |
Deferred income taxes and investment tax credits, net | (3,063) | 284 | 162 |
Deferred costs on sale leaseback transaction, net | 49 | 48 | 48 |
Impairment of assets | 10,665 | 42 | 0 |
Pension trust contributions | (382) | (143) | 0 |
Gain on investment securities held in trusts | (50) | (23) | (64) |
Commodity derivative transactions, net (Note 11) | 9 | (73) | 64 |
Lease payments on sale and leaseback transaction | (120) | (131) | (137) |
Income from discontinued operations (Note 20) | 0 | 0 | (86) |
Changes in current assets and liabilities- | |||
Receivables | (11) | 184 | 139 |
Materials and supplies | 41 | (15) | (65) |
Prepayments and other current assets | 27 | (10) | 126 |
Accounts payable | (37) | (243) | 42 |
Accrued taxes | 61 | 29 | (165) |
Other current liabilities | 56 | 69 | 54 |
Cash collateral, net | (116) | 140 | (54) |
Other | 137 | 148 | 48 |
Net cash provided from operating activities | 3,371 | 3,447 | 2,713 |
New financing- | |||
Long-term debt | 1,976 | 1,311 | 4,528 |
Short-term borrowings, net | 975 | 0 | 0 |
Redemptions and Repayments- | |||
Long-term debt | (2,331) | (879) | (1,759) |
Short-term borrowings, net | 0 | (91) | (1,605) |
Common stock dividend payments | (611) | (607) | (604) |
Other | (31) | (13) | (47) |
Net cash (used for) provided from financing activities | (22) | (279) | 513 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (2,835) | (2,704) | (3,312) |
Nuclear fuel | (232) | (190) | (233) |
Proceeds from asset sales | 15 | 20 | 394 |
Sales of investment securities held in trusts | 1,678 | 1,534 | 2,133 |
Purchases of investment securities held in trusts | (1,789) | (1,648) | (2,236) |
Other | 27 | 8 | 48 |
Net cash used for investing activities | (3,281) | (3,122) | (3,359) |
Net change in cash and cash equivalents | 68 | 46 | (133) |
Cash and cash equivalents at beginning of period | 131 | 85 | 218 |
Cash and cash equivalents at end of period | 199 | 131 | 85 |
Cash paid (received) during the year - | |||
Interest (net of amounts capitalized) | 1,050 | 1,028 | 931 |
Income taxes (received), net of refunds | (16) | 37 | (103) |
FES | |||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||
Net Income (loss) | (5,455) | 82 | (244) |
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 | 633 | 579 | 615 |
Investment impairment, including equity method investments | 19 | 90 | 33 |
Pension and OPEB mark-to-market adjustment | 48 | 57 | 297 |
Deferred income taxes and investment tax credits, net | (2,920) | 119 | 7 |
Deferred costs on sale leaseback transaction, net | 49 | 48 | 48 |
Impairment of assets | 8,622 | 33 | 0 |
Pension trust contributions | (138) | 0 | 0 |
Gain on investment securities held in trusts | (48) | (24) | (61) |
Commodity derivative transactions, net (Note 11) | 9 | (74) | 65 |
Lease payments on sale and leaseback transaction | (120) | (131) | (131) |
Income from discontinued operations (Note 20) | 0 | 0 | (116) |
Changes in current assets and liabilities- | |||
Receivables | 89 | 277 | 674 |
Materials and supplies | 26 | (25) | (44) |
Prepayments and other current assets | (8) | 14 | 14 |
Accounts payable | (30) | (76) | (477) |
Accrued taxes | 76 | (26) | (50) |
Other current liabilities | 15 | 43 | (18) |
Cash collateral, net | (87) | 159 | (92) |
Other | 5 | 6 | 51 |
Net cash provided from operating activities | 785 | 1,151 | 571 |
New financing- | |||
Long-term debt | 471 | 341 | 878 |
Short-term borrowings, net | 101 | 0 | 0 |
Equity contribution from parent | 0 | 500 | |
Redemptions and Repayments- | |||
Long-term debt | (507) | (411) | (816) |
Short-term borrowings, net | 0 | (126) | (301) |
Common stock dividend payments | 0 | (70) | 0 |
Other | (8) | (6) | (15) |
Net cash (used for) provided from financing activities | 57 | (272) | 246 |
CASH FLOWS FROM INVESTING ACTIVITIES: | |||
Property additions | (546) | (627) | (839) |
Nuclear fuel | (232) | (190) | (233) |
Proceeds from asset sales | 9 | 13 | 307 |
Sales of investment securities held in trusts | 717 | 733 | 1,163 |
Purchases of investment securities held in trusts | (783) | (791) | (1,219) |
Cash investments | 10 | (10) | 0 |
Loans to affiliated companies, net | (18) | (11) | 0 |
Other | 1 | 4 | 4 |
Net cash used for investing activities | (842) | (879) | (817) |
Net change in cash and cash equivalents | 0 | 0 | 0 |
Cash and cash equivalents at beginning of period | 2 | 2 | 2 |
Cash and cash equivalents at end of period | 2 | 2 | 2 |
Cash paid (received) during the year - | |||
Interest (net of amounts capitalized) | 111 | 114 | 118 |
Income taxes (received), net of refunds | $ (193) | $ (5) | $ (384) |
Organization, Basis of Presenta
Organization, Basis of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
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 organized under the laws of the State of Ohio 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 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 six million customers in the Midwest and Mid-Atlantic regions. Its regulated and unregulated generation subsidiaries control nearly 17,000 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 24,000 miles of lines and two regional transmission operation centers. FES, a subsidiary of FE, was organized under the laws of the State of Ohio 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. FES purchases the entire output of the generation facilities owned by FG and NG, and purchases the uncommitted output of AE Supply, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs. 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 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 the Consolidated Financial Statements are combined for FirstEnergy and FES. Certain prior year amounts have been reclassified to conform to the current year presentation. Strategic Review of Competitive Operations FirstEnergy believes having a combination of distribution, transmission and generation assets in a regulated or regulated-like construct is the best way to serve customers. FirstEnergy’s strategy is to be a fully regulated utility, focusing on stable and predictable earnings and cash flow from its regulated business units. Over the past several years, CES has been impacted by a prolonged decrease in demand and excess generation supply in the PJM Region, which has resulted in a period of protracted low power and capacity prices. To address this, CES sold or deactivated more than 6,770 MWs of competitive generation from 2012 to 2015. Additionally, CES has continued to focus on cost reductions, including those identified as part of FirstEnergy’s previously disclosed cash flow improvement plan. However, the energy and capacity markets continue to be weak, as evidenced by the significantly depressed capacity prices from the 2019/2020 PJM Base Residual Auction in May of 2016 as well as the current forward pricing and the long-term fundamental view on energy and capacity prices, which resulted in a non-cash pre-tax impairment charge of $800 million ( $23 million at FES) recognized in the second quarter of 2016 representing the total amount of goodwill at CES. As part of a continual process to evaluate its overall generation business, on July 22, 2016, FirstEnergy announced its intent to exit the 136 MW Bay Shore Unit 1 generating station by October 2020 and to deactivate Units 1-4 of the W.H. Sammis generating station totaling 720 MWs by May 2020, resulting in a $647 million ( $517 million at FES) non-cash pre-tax impairment charge in the second quarter of 2016. Furthermore, in November of 2016, FirstEnergy announced that it had begun a strategic review of its competitive operations as it transitions to a fully regulated utility with a target to implement its exit from competitive operations by mid-2018. As a result of this strategic review, FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement to sell four of AE Supply’s natural gas generating plants and approximately 59% of AGC’s interest in Bath County ( 1,572 MWs of combined capacity) for an all-cash purchase price of $925 million , subject to customary and other closing conditions as further discussed in Note 22, Subsequent Events, including the satisfaction and discharge of $305 million of AE Supply’s senior notes, which is expected to require the payment of a “make-whole” premium currently estimated to be approximately $100 million based on current interest rates. Additionally, in connection with MP's RFP seeking additional generation capacity, AE Supply offered the Pleasants power station ( 1,300 MWs) for approximately $195 million . Although FirstEnergy is targeting mid-2018 to exit from competitive operations, the options for the remaining portion of CES' generation are still uncertain, but could include one or more of the following: • Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits, • Additional asset sales and/or plant deactivations, • Restructuring FES debt with its creditors, and/or • Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC. Furthermore, adverse outcomes in previously disclosed disputes regarding long-term coal transportation contracts and/or the inability to extend or refinance debt maturities at FES subsidiaries, could accelerate management’s targeted timeline and limit its options to fully exit competitive operations to either restructuring debt with its creditors or seeking protection under U.S. bankruptcy laws for FES and possibly FENOC. 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. Today, the competitive generation portfolio is comprised of more than 13,000 MWs of generation, primarily from coal, nuclear and natural gas and oil fuel sources. The assets can generate approximately 70 - 75 million MWHs annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar, and CES' entitlement in OVEC, of which a portion is sold through various retail channels and the remainder targeting forward wholesale or spot sales. Subject to the completion of the sale of the AE Supply natural gas generating plants and AGC’s interest in Bath County and, if accepted in the MP RFP process as the winning bidder, the transfer of the Pleasants Power station to MP, the size and generation capacity of CES’ current portfolio will reduce to approximately 10,000 MWs with approximately 60 - 65 million MWHs produced annually. The competitive business continues to be managed conservatively due to the stress of weak energy prices, insufficient results from recent capacity auctions and anemic demand forecasts that have lowered the value of the business. Furthermore, the credit quality of CES, specifically FES' unsecured debt rating of Caa1 at Moody’s, CCC+ at S&P and C at Fitch and negative outlook from each of the rating agencies has challenged its ability to hedge generation with retail and forward wholesale sales due to collateral requirements that otherwise would reduce available liquidity. A lack of viable alternative strategies for its competitive portfolio has and would further stress the financial condition of FES. As a result, CES' contract sales are expected to decline from 53 million MWHs in 2016 to 40 - 45 million MWHs in 2017, and to 35 - 40 million MWHs in 2018. While the reduced contract sales will decrease potential collateral requirements, market price volatility may significantly impact CES' financial results due to the increased exposure to the wholesale spot market. Going Concern at FES Although FES has access to a $500 million credit facility with FE, in lieu of access to the unregulated money pool, all of which is available as of January 31, 2017, its current credit rating and the current forward wholesale pricing environment are a significant challenge to FES. Furthermore, a lack of viable alternative strategies for its competitive portfolio would further stress the liquidity and financial condition of FES. As previously disclosed, FES has $130 million of debt maturities that need to be refinanced in 2017 (and $515 million of maturing debt in 2018 beginning in the second quarter). Based on its current senior unsecured debt rating and current capital structure, reflecting the impact of the impairment charges discussed above, as well as the forecasted decline in wholesale forward market prices over the next few years, these debt maturities will be difficult to refinance, even on a secured basis, which would further stress FES' anticipated liquidity. Furthermore, lack of clarity regarding the timing and viability of alternative strategies, including additional asset sales or deactivations and/or converting generation from competitive operations to a regulated or regulated-like construct in a way that provides FES with the means to satisfy its obligations over the long-term, may require FES to restructure debt and other financial obligations with its creditors or seek protection under U.S bankruptcy laws. In the event FES seeks protection under U.S. bankruptcy laws, FENOC may similarly seek such protection. Although management is exploring capital and other cost reductions, asset sales, and other options to improve cash flow as well as continuing with legislative efforts to explore a regulatory solution, these obligations and their impact on 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, PATH 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 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. The following table provides information about the composition of net regulatory assets as of December 31, 2016 and December 31, 2015 , and the changes during the year ended December 31, 2016 : Regulatory Assets by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 90 $ 185 $ (95 ) Customer receivables for future income taxes 444 355 89 Nuclear decommissioning and spent fuel disposal costs (304 ) (272 ) (32 ) Asset removal costs (470 ) (372 ) (98 ) Deferred transmission costs 127 115 12 Deferred generation costs 215 243 (28 ) Deferred distribution costs 296 335 (39 ) Contract valuations 153 186 (33 ) Storm-related costs 353 403 (50 ) Other 110 170 (60 ) Net Regulatory Assets included on the Consolidated Balance Sheets $ 1,014 $ 1,348 $ (334 ) Regulatory assets that do not earn a current return totaled approximately $153 million and $ 148 million as of December 31, 2016 and 2015 , respectively, primarily related to storm damage costs, and are currently being recovered through rates. As of December 31, 2016 and December 31, 2015 , FirstEnergy had approximately $ 157 million and $116 million of net regulatory liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within other noncurrent liabilities on the Consolidated Balance Sheets. REVENUES AND RECEIVABLES The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and Maryland. FES' principal business is supplying electric power to end-use customers through retail and wholesale arrangements, including affiliated company power sales to meet a portion of the POLR and default service requirements, and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. Retail customers are metered on a cycle basis. 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, 2016 and 2015 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2016 and 2015 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2016 Billed $ 833 $ 123 Unbilled 607 90 Total $ 1,440 $ 213 December 31, 2015 Billed $ 836 $ 165 Unbilled 579 110 Total $ 1,415 $ 275 EARNINGS (LOSS) PER SHARE OF COMMON STOCK Basic earnings (loss) 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. The following table reconciles basic and diluted earnings (loss) per share of common stock: Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock 2016 2015 2014 (In millions, except per share amounts) Income (loss) from continuing operations available to common shareholders $ (6,177 ) $ 578 $ 213 Discontinued operations (Note 20) — — 86 Net income (loss) $ (6,177 ) $ 578 $ 299 Weighted average number of basic shares outstanding 426 422 420 Assumed exercise of dilutive stock options and awards (1) — 2 1 Weighted average number of diluted shares outstanding 426 424 421 Earnings (loss) per share: Basic earnings (loss) per share: Continuing operations $ (14.49 ) $ 1.37 $ 0.51 Discontinued operations (Note 20) — — 0.20 Earnings (loss) per basic share $ (14.49 ) $ 1.37 $ 0.71 Diluted earnings (loss) per share: Continuing operations $ (14.49 ) $ 1.37 $ 0.51 Discontinued operations (Note 20) — — 0.20 Earnings (loss) per diluted share $ (14.49 ) $ 1.37 $ 0.71 (1) For the year ended December 31, 2016 , approximately three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss for the period. For the years ended December 31, 2015 and 2014, approximately one million and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive. 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, 2016 and 2015 were as follows: December 31, 2016 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution (2) $ 24,979 $ (7,169 ) $ 17,810 $ 472 $ 18,282 Regulated Transmission (2) 9,342 (1,948 ) 7,394 383 7,777 Competitive Energy Services (3) 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 December 31, 2015 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution (2) $ 24,034 $ (6,865 ) $ 17,169 $ 530 $ 17,699 Regulated Transmission (2) 8,222 (1,840 ) 6,382 484 6,866 Competitive Energy Services (3) 17,214 (6,213 ) 11,001 1,304 12,305 Corporate/Other 482 (242 ) 240 104 344 Total $ 49,952 $ (15,160 ) $ 34,792 $ 2,422 $ 37,214 (1) Includes capital leases of $244 million and $253 million at December 31, 2016 and 2015, respectively. (2) Net plant in service of $326 million as of December 31, 2015 was reclassified to conform to the current presentation reflecting the transfer of certain transmission assets from Regulated Distribution to Regulated Transmission during the fourth quarter of 2016. See "Note 19, Segment Information", for more information. (3) Primarily consists of generating assets and nuclear fuel as discussed above. 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, 2016 and 2015 were as follows: 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 December 31, 2015 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 5,911 $ (1,937 ) $ 3,974 $ 218 $ 4,192 Nuclear Generation 5,617 (1,574 ) 4,043 512 4,555 Nuclear Fuel 2,616 (2,198 ) 418 283 701 Other 167 (56 ) 111 144 255 Total $ 14,311 $ (5,765 ) $ 8,546 $ 1,157 $ 9,703 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 2016 , 2015 and 2014 are shown in the following table: Annual Composite Depreciation Rate 2016 2015 2014 FirstEnergy 2.5 % 2.5 % 2.5 % FES 3.3 % 3.2 % 3.1 % 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 has determined this adjustment is not material to the current period or any prior periods. For the years ended December 31, 2016 , 2015 and 2014 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $37 million , $49 million and $49 million , respectively, of allowance for equity funds used during construction and $66 million , $68 million and $69 million , respectively, of capitalized interest. For the years ended December 31, 2016 , 2015 and 2014 , capitalized financing costs on FES' Consolidated Statements of Income (Loss) includes $34 million , $35 million and $34 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, Virginia Electric and Power Company, a non-affiliated utility. Net Property, plant and equipment includes $639 million representing AGC's share in this facility as of December 31, 2016 of which $458 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 with Aspen to sell AE Supply's indirect interest ( 23.75% ) in Bath County, as discussed in "Note 22, Subsequent Events". Additionally, on December 16, 2016, MP issued an RFP for the sale of its ownership interest in Bath County, discussed in "Note 15, Regulatory Matters". 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. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended license term and expected remediation dates. 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, 2016 , are described further in "Note 14, Asset Retirement Obligations". ASSET IMPAIRMENTS Long-Lived Assets 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 Impairments, for long-lived asset impairments recognized during 2016 and 2015. 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 the changes in the carrying value of goodwill for the year ended December 31, 2016 : Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418 Impairment — — (800 ) (800 ) Transmission Segment (1) (88 ) 88 — — Balance as of December 31, 2016 $ 5,004 $ 614 $ — $ 5,618 (1) See Note 19, Segment Information for discussion of transfer of certain transmission assets from the Regulated Distribution segment to the Regulated Transmission segment during the fourth quarter of 2016, resulting in the transfer of $88 million of goodwill between the segments based on the relative fair value of the transmission assets to fair value of the Regulated Distribution segment. 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, 2016, 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. It was determined that the fair value 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 Impairments, for goodwill impairment recognized during 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, 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. In 2016 , 2015 and 2014 , FirstEnergy recognized $21 million , $102 million and $37 million , respectively, of OTTI. During the same periods, FES recognized OTTI of $19 million , $90 million and $33 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 Impairments, for inventory-related charges recognized during 2016. NEW ACCOUNTING PRONOUNCEMENTS In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent a |
Asset Impairments
Asset Impairments | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Asset Impairments | ASSET IMPAIRMENTS Property, Plant, and Equipment 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 that it had begun a strategic review of its competitive operations as it transitions to a fully regulated utility with a target to implement its exit from competitive operations by mid-2018. Although FirstEnergy is targeting mid-2018 to exit from competitive operations, the options for the remaining portion of CES' generation are still uncertain, but could include one or more of the following: • Legislative or regulatory solutions for generation assets that recognize their environmental or energy security benefits, • Additional asset sales and/or plant deactivations, • Restructuring FES debt with its creditors, and/or • Seeking protection under U.S. bankruptcy laws for FES and possibly FENOC. Once a plan is finalized, FE’s implementation of that plan may result in long-lived asset impairment charges, exit related losses and costs, contingencies, and reserves against deferred tax assets that may not be realizable. 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. FE Consolidated FES Consolidated Impaired Asset Net Book Value Fair Value Impairment Net Book Value Fair Value Impairment (In millions) Coal generation assets $ 4,672 $ 614 $ 4,058 $ 3,699 $ 435 $ 3,264 Nuclear generation assets 4,842 460 4,382 4,825 460 4,365 Gas/Hydro generation assets 1,187 921 266 — — — Nuclear Fuel 703 460 243 703 460 243 Other assets (1) 382 113 269 314 104 210 Totals $ 11,786 $ 2,568 $ 9,218 $ 9,541 $ 1,459 $ 8,082 (1) Includes the impairment of materials and supplies ( $142 million ), AE Supply coal contracts ( $55 million ) and AE Supply's investment in OVEC ( $37 million ). 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. 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. The impairment charges are included within the Regulated Distribution segment ( $8 million ) and the CES segment ( $34 million ). 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 within the caption Impairment of assets in the Consolidated Statement of Income (Loss). |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |
ACCUMULATED OTHER COMPREHENSIVE INCOME | ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2016 , 2015 and 2014 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, 2014 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 89 92 181 Amounts reclassified from AOCI (2 ) (63 ) (168 ) (233 ) Other comprehensive income (loss) (2 ) 26 (76 ) (52 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 10 (23 ) (14 ) Other comprehensive income (loss), net of tax (1 ) 16 (53 ) (38 ) AOCI Balance, December 31, 2014 $ (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 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2016 , 2015 and 2014 : FirstEnergy Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (3 ) $ (10 ) Other operating expenses Long-term debt 8 8 8 Interest expense 8 5 (2 ) Total before taxes (3 ) (1 ) 1 Income taxes (benefits) $ 5 $ 4 $ (1 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (51 ) $ (25 ) $ (63 ) Investment income (loss) 19 9 24 Income taxes (benefits) $ (32 ) $ (16 ) $ (39 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (72 ) $ (126 ) $ (168 ) (1) 27 49 65 Income taxes (benefits) $ (45 ) $ (77 ) $ (103 ) 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, 2016 , 2015 and 2014 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, 2014 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 80 13 93 Amounts reclassified from AOCI (10 ) (59 ) (19 ) (88 ) Other comprehensive income (loss) (10 ) 21 (6 ) 5 Income tax (benefits) on other comprehensive income (loss) (4 ) 8 (2 ) 2 Other comprehensive income (loss), net of tax (6 ) 13 (4 ) 3 AOCI Balance, December 31, 2014 $ (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 The following amounts were reclassified from AOCI for FES in the years ended December 31, 2016 , 2015 and 2014 : FES Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (3 ) $ (10 ) Other operating expenses — 1 4 Income taxes (benefits) $ — $ (2 ) $ (6 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (48 ) $ (24 ) $ (59 ) Investment income (loss) 18 9 22 Income taxes (benefits) $ (30 ) $ (15 ) $ (37 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14 ) $ (16 ) $ (19 ) (1) 5 6 7 Income taxes (benefits) $ (9 ) $ (10 ) $ (12 ) 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, 2016 | |
Compensation and Retirement Disclosure [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. In 2014, the qualified pension plan was amended authorizing a voluntary cashout window program for certain eligible terminated participants with vested benefits. Payment of benefits for participants that elected an immediate lump sum cash payment or an annuity resulted in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2016 and 2015, certain unions ratified their labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately $13 million and $10 million , respectively. 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, 2016, 2015, and 2014 were $194 million ( $147 million net of amounts capitalized), $369 million ( $242 million net of amounts capitalized), and $1,243 million ( $835 million net of amounts capitalized), respectively. In 2016, the pension and OPEB mark-to-market adjustment primarily reflects a 25 basis point decline in the discount rate, partially offset by changes in actuarial assumptions, including mortality assumptions and 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 funding obligations for future years 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. 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 2016 , FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $472 million , or 8.2% compared to losses of $(172) million , or (2.7)% in 2015 and earnings of $387 million , or 6.2% in 2014 , and assumed a 7.50% rate of return for 2016 and a 7.75% rate of return for 2015 and 2014 on plan assets which generated $429 million , $476 million and $496 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 2016, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2016, incorporating three additional years of SSA data on U.S. population mortality. MP-2016 incorporates SSA mortality data from 2012 to 2014 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 as a result of the slower average rate of mortality improvement. Due to the additional years of data on population mortality, the RP2014 mortality table with the projection scale MP-2016 was utilized to determine the 2016 benefit cost and obligation as of December 31, 2016 for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2016 resulted in a decrease in the projected benefit obligation of $141 million and $8 million for the pension and OPEB plans, respectively, and was included in the 2016 pension and OPEB mark-to-market adjustment. Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2016 2015 2016 2015 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,079 $ 9,249 $ 724 $ 757 Service cost 191 193 5 5 Interest cost 398 383 30 29 Plan participants’ contributions — — 5 6 Plan amendments — — (13 ) (10 ) Medicare retiree drug subsidy — — 1 1 Actuarial (gain) loss 224 (277 ) 14 (2 ) Benefits paid (466 ) (469 ) (55 ) (62 ) Benefit obligation as of December 31 $ 9,426 $ 9,079 $ 711 $ 724 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 5,338 $ 5,824 $ 431 $ 464 Actual return (losses) on plan assets 442 (178 ) 30 6 Company contributions 899 161 9 17 Plan participants’ contributions — — 5 6 Benefits paid (466 ) (469 ) (55 ) (62 ) Fair value of plan assets as of December 31 $ 6,213 $ 5,338 $ 420 $ 431 Funded Status: Qualified plan $ (2,821 ) $ (3,366 ) Non-qualified plans (392 ) (375 ) Funded Status $ (3,213 ) $ (3,741 ) $ (291 ) $ (293 ) Accumulated benefit obligation $ 8,913 $ 8,579 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ 9 $ — $ — $ — Current liabilities (19 ) (18 ) — — Noncurrent liabilities (3,203 ) (3,723 ) (291 ) (293 ) Net liability as of December 31 $ (3,213 ) $ (3,741 ) $ (291 ) $ (293 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 28 $ 37 $ (288 ) $ (355 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.25 % 4.50 % 4.00 % 4.25 % 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 2027 2026 Allocation of Plan Assets (as of December 31) Equity securities 44 % 40 % 53 % 51 % Bonds 30 % 34 % 41 % 43 % Absolute return strategies 8 % 7 % — % — % Real estate 10 % 11 % — % — % Cash and short-term securities 8 % 8 % 6 % 6 % Total 100 % 100 % 100 % 100 % The estimated 2017 amortization of pension and OPEB prior service costs (credits) from AOCI into net periodic pension and OPEB costs (credits) is approximately $8 million and $(81) million , respectively. Pension OPEB Components of Net Periodic Benefit Costs 2016 2015 2014 2016 2015 2014 (In millions) Service cost $ 191 $ 193 $ 167 $ 5 $ 5 $ 9 Interest cost 398 383 402 30 29 39 Expected return on plan assets (399 ) (443 ) (462 ) (30 ) (33 ) (34 ) Amortization of prior service cost (credit) 8 8 8 (80 ) (134 ) (176 ) Pension & OPEB mark-to-market adjustment 179 344 1,235 15 25 8 Net periodic benefit cost (credit) $ 377 $ 485 $ 1,350 $ (60 ) $ (108 ) $ (154 ) Assumptions Used to Determine Net Periodic Benefit Cost * for Years Ended December 31 Pension OPEB 2016 2015 2014 2016 2015 2014 Weighted-average discount rate 4.50 % 4.25 % 5.00 % 4.25 % 4.00 % 4.75 % Expected long-term return on plan assets 7.50 % 7.75 % 7.75 % 7.50 % 7.75 % 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 2016 and 2015 . 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 (2) 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 ) — % Private equity funds — — 33 33 — % Real estate funds — — 615 615 10 % Total (1) $ 1,470 $ 4,080 $ 648 $ 6,198 100 % (1) 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. (2) 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. December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 427 $ — $ 427 8 % Equity investments Domestic 869 75 — 944 18 % International 395 794 — 1,189 22 % Fixed income Government bonds — 232 — 232 4 % Corporate bonds — 1,115 — 1,115 21 % High yield debt — 438 — 438 8 % Mortgage-backed securities (non-government) — 31 — 31 1 % Alternatives Hedge funds (Absolute return) — 343 — 343 7 % Derivatives — 15 — 15 — % Private equity funds — — 24 24 — % Real estate funds — — 587 587 11 % Total (1) $ 1,264 $ 3,470 $ 611 $ 5,345 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. 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 2016 and 2015 : Private Equity Funds Real Estate Funds (In millions) Balance as of January 1, 2015 $ 25 $ 421 Actual return on plan assets: Unrealized gains — 42 Realized gains (losses) (1 ) 16 Transfers in — 108 Balance as of December 31, 2015 $ 24 $ 587 Actual return on plan assets: Unrealized gains 1 29 Realized gains 1 14 Transfers in (out) 7 (15 ) Balance as of December 31, 2016 $ 33 $ 615 As of December 31, 2016 and 2015 , the OPEB trust investments measured at fair value were as follows: 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 % International — — — — — % Fixed income U.S. treasuries — 40 — 40 9 % Government bonds — 108 — 108 26 % Corporate bonds — 24 — 24 6 % High yield debt — — — — — % Mortgage-backed securities (non-government) — 2 — 2 — % Alternatives Hedge funds — — — — — % Real estate funds — — — — — % 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. December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 25 $ — $ 25 6 % Equity investment Domestic 219 — — 219 50 % International 1 3 — 4 1 % Fixed income U.S. treasuries — 42 — 42 10 % Government bonds — 114 — 114 26 % Corporate bonds — 27 — 27 6 % High yield debt — 1 — 1 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 1 — 1 — % Real estate funds — — 2 2 — % Total (1) $ 220 $ 216 $ 2 $ 438 100 % (1) Excludes $(7) million as of December 31, 2015 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair value hierarchy during 2016 and 2015 : Real Estate Funds (in millions) Balance as of January 1, 2015 $ 3 Transfers out (1 ) Balance as of December 31, 2015 $ 2 Transfers out (2 ) Balance as of December 31, 2016 $ — 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 2016 and 2015 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 $ 23 $ (20 ) 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) 2016 $ 505 $ 52 $ (3 ) 2017 523 52 (3 ) 2018 534 53 (3 ) 2019 552 53 (3 ) 2020 566 53 (3 ) Years 2021-2025 2,999 251 (7 ) FES’ share of the pension and OPEB net (liability) asset as of December 31, 2016 and 2015 , was as follows: Pension OPEB 2016 2015 2016 2015 (In millions) Net (Liability) Asset (1) $ (158 ) $ (303 ) $ 36 $ 25 (1) Excludes $866 million and $785 million as of December 31, 2016 and 2015, respectively, of affiliated non-current liabilities related to pension and OPEB mark-to-market costs allocated to FES of which $570 million and $518 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, 2016 was as follows: Pension OPEB 2016 2015 2014 2016 2015 2014 (In millions) Net Periodic Cost (Credit) $ (5 ) $ 10 $ 150 $ (26 ) $ (22 ) $ (24 ) |
Stock-Based Compensation Plans
Stock-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , approximately 8.0 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. Any shares not issued due to forfeitures or cancellations are 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, less estimated forfeitures. 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, 2016 , 2015 and 2014 were $13 million , $10 million and $13 million , respectively. Currently, the excess of the deductible amount over the recognized compensation cost is recorded as a component of stockholders’ equity and reported as a financing activity on the Consolidated Statements of Cash Flows. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", the income tax effects of awards will be 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 2016 2015 2014 (In millions) Restricted Stock Units $ 62 $ 46 $ 26 Restricted Stock 2 2 5 Performance Shares (3 ) — 5 401(k) Savings Plan 39 38 25 EDCP & DCPD 5 3 8 Total $ 105 $ 89 $ 69 Stock-based compensation costs capitalized $ 38 $ 32 $ 23 FES Years ended December 31 Stock-based Compensation Plan 2016 2015 2014 (In millions) Restricted Stock Units $ 11 $ 6 $ 4 Performance Shares — — 1 401(k) Savings Plan 5 5 4 Total $ 16 $ 11 $ 9 Stock-based compensation costs capitalized $ 2 $ 1 $ 1 Stock option expense was not material for FirstEnergy or FES for the years December 31, 2016, 2015 or 2014 . Income tax benefits associated with stock based compensation plan expense were $14 million , $12 million and $14 million (FES - $2 million , $2 million and $2 million ) for the years ended 2016 , 2015 and 2014 , 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. Prior to 2015, all performance-based restricted stock units were paid in stock. Restricted stock units paid 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 paid in cash provide the participant the right to receive cash based on the numbers 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, 2016 was $14 million . No cash was paid to settle the restricted stock unit obligations in 2016 . 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, 2016 , was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2016 2,436,888 $ 35.26 Granted in 2016 1,581,762 34.77 Forfeited in 2016 (81,618 ) 33.85 Vested in 2016 (1) (873,303 ) 33.54 Nonvested as of December 31, 2016 3,063,729 $ 32.98 (1 ) Excludes dividend equivalents of 132,360 earned during vesting period The weighted average fair value of awards granted in 2016 , 2015 and 2014 were $ 34.77 , $35.27 and $32.17 respectively. For the years ended December 31, 2016 , 2015 , and 2014 , the fair value of restricted stock units vested was $36 million , $22 million , and $28 million , respectively. As of December 31, 2016 , there was $47 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted for restricted stock units; that cost is expected to be recognized over a period of approximately two 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, 2016 , was as follows: Restricted Stock Number of Shares Weighted Average Grant-Date Fair Value Nonvested as of January 1, 2016 190,656 $ 40.65 Granted in 2016 28,756 32.69 Vested in 2016 (1) (82,252 ) 46.83 Nonvested as of December 31, 2016 137,160 $ 35.27 (1 ) Excludes 23,402 shares for dividends earned during vesting period The weighted average vesting period for restricted stock granted in 2016 was 3.49 years. The weighted average fair value of awards granted in 2016 , 2015 , and 2014 were $ 32.69 , $32.98 and $32.71 respectively. For the years ended December 31, 2016 , 2015 , and 2014 , the fair value of restricted stock vested was $5 million , $8 million , and $ 4 million , respectively. As of December 31, 2016 , there was $ 2 million of total unrecognized compensation cost related to non-vested restricted stock, which is expected to be recognized over a period of approximately three years. 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 2016 . Stock option activity during 2016 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2016 (1,211,358 options exercisable) 1,411,971 $ 44.89 Options forfeited (35,150 ) 56.40 Balance, December 31, 2016 (1,376,821 options exercisable) 1,376,821 $ 44.60 There was no cash received from the exercise of stock options in 2016 . Cash received from the exercise of stock options in 2015 and 2014 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2016 was 3.60 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. During 2015 , no cash was paid to settle performance shares because the performance criteria was not met for the 2012-2014 cycle. 401(k) Savings Plan In 2016 and 2015 , 1,159,215 and 1,072,494 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 $ 7 million and $9 million as of December 31, 2016 and December 31, 2015 , respectively, is included in the caption “Retirement benefits” on the Consolidated Balance Sheets. |
Taxes
Taxes | 12 Months Ended |
Dec. 31, 2016 | |
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. INCOME TAXES (BENEFITS) (1) 2016 2015 2014 (In millions) FirstEnergy Currently payable (receivable)- Federal $ (1 ) $ 1 $ (132 ) State 9 30 (72 ) 8 31 (204 ) Deferred, net- Federal (3,114 ) 277 214 State 59 15 (42 ) (3,055 ) 292 172 Investment tax credit amortization (8 ) (8 ) (10 ) Total provision for income taxes (benefits) $ (3,055 ) $ 315 $ (42 ) FES Currently payable (receivable)- Federal $ (67 ) $ (56 ) $ (222 ) State (1 ) 2 (13 ) (68 ) (54 ) (235 ) Deferred, net- Federal (2,861 ) 103 25 State (57 ) 18 (14 ) (2,918 ) 121 11 Investment tax credit amortization (2 ) (2 ) (4 ) Total provision for income taxes (benefits) $ (2,988 ) $ 65 $ (228 ) (1) Provision for Income Taxes (Benefits) on Income from Continuing Operations. Currently payable (receivable) in 2014 excludes $106 million and $12 million of federal and state taxes, respectively, associated with discontinued operations. Deferred, net in 2014 excludes $44 million and $5 million of federal and state tax benefits, respectively, associated with discontinued operations. 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 at the federal statutory rate to the total income taxes on continuing operations for the three years ended December 31: 2016 2015 2014 (In millions) FirstEnergy Income (loss) from Continuing Operations before income taxes (benefits) $ (9,232 ) $ 893 $ 171 Federal income tax expense (benefit) at statutory rate (35%) $ (3,231 ) $ 313 $ 60 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (192 ) 17 (21 ) AFUDC equity and other flow-through (13 ) (16 ) (13 ) Amortization of investment tax credits (8 ) (8 ) (10 ) Change in accounting method — (8 ) (27 ) ESOP dividend (6 ) (6 ) (6 ) Impairment of non-deductible goodwill 157 — — Tax basis balance sheet adjustments — — (25 ) Uncertain tax positions (16 ) 1 (35 ) Valuation allowances 246 18 33 Other, net 8 4 2 Total income taxes (benefits) $ (3,055 ) $ 315 $ (42 ) Effective income tax rate 33.1 % 35.3 % (24.6 )% FES Income (loss) from Continuing Operations before income taxes (benefits) $ (8,444 ) $ 147 $ (588 ) Federal income tax expense (benefit) at statutory rate (35%) $ (2,955 ) $ 51 $ (206 ) Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (188 ) 2 (28 ) Amortization of investment tax credits (2 ) (2 ) (4 ) ESOP dividend (1 ) (1 ) (1 ) Impairment of non-deductible goodwill 9 — — Uncertain tax positions (8 ) 5 — Valuation allowances 151 14 14 Other, net 6 (4 ) (3 ) Total income taxes (benefits) $ (2,988 ) $ 65 $ (228 ) Effective income tax rate 35.4 % 44.2 % 38.8 % In 2016 , FirstEnergy’s effective tax rate was 33.1% compared to 35.3% in 2015 . The change in the effective tax rate year-over-year resulted from the impairment of $800 million of goodwill (as described in Note 2, Asset Impairments), of which $433 million is non-deductible for tax purposes. Additionally, $168 million of valuation allowances were recorded against state and local NOL carryforwards and $78 million of valuation allowances were recorded against state and local property deferred tax assets, that management believes, more likely than not, will not be realized. In 2016 , FES’ effective tax rate on income from continuing operations was 35.4% compared to 44.2% in 2015. The change in the effective tax rate primarily resulted from $73 million of valuation allowances recorded against state and local NOL carryforwards and $78 million of valuation allowances recorded against state and local property 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 is non-deductible for tax purposes. Accumulated deferred income taxes as of December 31, 2016 and 2015 are as follows: 2016 2015 (In millions) FirstEnergy Property basis differences $ 7,088 $ 9,920 Deferred sale and leaseback gain (351 ) (360 ) Pension and OPEB (1,347 ) (1,541 ) Nuclear decommissioning activities 635 480 Asset retirement obligations (669 ) (731 ) Regulatory asset/liability 545 763 Deferred compensation (269 ) (239 ) Loss carryforwards and AMT credits (2,251 ) (1,965 ) Valuation reserve 438 192 All other (54 ) 254 Net deferred income tax liability $ 3,765 $ 6,773 FES Property basis differences $ (1,009 ) $ 1,901 Deferred sale and leaseback gain (328 ) (342 ) Pension and OPEB (366 ) (393 ) Lease market valuation liability 111 95 Nuclear decommissioning activities 540 483 Asset retirement obligations (453 ) (509 ) Loss carryforwards and AMT credits (830 ) (687 ) Valuation reserve 197 46 All other (141 ) 6 Net deferred income tax liability (asset) $ (2,279 ) $ 600 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 2012-2015. In February 2016, the IRS completed its examination of the 2014 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy’s taxable income or effective tax rate. Tax year 2015 is currently under review by the IRS. FirstEnergy has recorded as deferred income tax assets the effect of 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, 2016 , the deferred income tax assets, before any valuation allowances, for loss carryforwards and AMT credits consisted of $1.8 billion of Federal NOL carryforwards that will begin to expire in 2030, Federal AMT credits of $25 million that have an indefinite carryforward period, and $407 million of state and local NOL carryforwards that will begin to expire in 2017 . FES has recorded as deferred income tax assets the effect of 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, 2016, the deferred income tax assets, before any valuation allowances, for loss carryforwards consisted of $706 million of Federal NOL carryforwards that will begin to expire in 2031 and $120 million of state and local NOL carryforwards that will begin to expire in 2017. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $10.1 billion ( $407 million after-tax) for FirstEnergy, of which approximately $2.1 billion ( $87 million after-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 $3.4 billion ( $120 million after-tax), of which none 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 2017-2021 $ 166 $ 2,998 $ 2 $ 1,795 2022-2026 1,327 — — — 2027-2031 2,817 — 410 — 2032-2036 2,752 — 1,172 — $ 7,062 $ 2,998 $ 1,584 $ 1,795 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, 2016 and 2015 , FirstEnergy's total unrecognized income tax benefits were approximately $84 million and $34 million , respectively. If ultimately recognized in future years, approximately $50 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2016 , it is reasonably possible that approximately $51 million of unrecognized tax benefits may be resolved during 2017 as a result of the statute of limitations expiring and expected resolution with respect to certain claims, of which approximately $26 million would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended 2016 , 2015 and 2014 : FirstEnergy FES (In millions) Balance, January 1, 2014 $ 48 $ 3 Current year increases 4 — Prior years increases 5 — Prior years decreases (23 ) — Balance, December 31, 2014 $ 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 $ — 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 2016, 2015, and 2014 was not material. For the years ended December 31, 2016 and 2015, the cumulative net interest payable recorded by FirstEnergy was not material. General Taxes General tax expense for 2016 , 2015 and 2014 , is summarized as follows: 2016 2015 2014 (In millions) FirstEnergy KWH excise $ 196 $ 193 $ 194 State gross receipts 212 224 226 Real and personal property 472 410 393 Social security and unemployment 127 119 112 Other 35 32 37 Total general taxes $ 1,042 $ 978 $ 962 FES State gross receipts $ 28 $ 44 $ 69 Real and personal property 42 36 39 Social security and unemployment 15 16 17 Other 3 2 3 Total general taxes $ 88 $ 98 $ 128 |
Leases
Leases | 12 Months Ended |
Dec. 31, 2016 | |
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 will expire 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 expiring in 2017. OE, CEI and TE had the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes. In 2007, FG completed a sale and leaseback transaction for its 93.825% 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. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Upon the completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's output. In November 2014, NG repurchased 55.3 MWs of lessor equity interests in OE's existing sale and leaseback of Perry Unit 1 for approximately $87 million . 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. Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. The PNBV arrangements effectively reduce lease costs related to those transactions (see "Note 9, Variable Interest Entities"). As of December 31, 2016 , FirstEnergy's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. Operating lease expense for 2016 , 2015 and 2014 , is summarized as follows: (In millions) 2016 2015 2014 FirstEnergy $ 168 $ 174 $ 199 FES $ 94 $ 94 $ 95 The future minimum capital lease payments as of December 31, 2016 are as follows: Capital leases FirstEnergy FES (In millions) 2017 $ 32 $ 6 2018 25 2 2019 19 — 2020 14 — 2021 12 — Years thereafter 15 1 Total minimum lease payments 117 9 Interest portion (13 ) (1 ) Present value of net minimum lease payments 104 8 Less current portion 29 5 Noncurrent portion $ 75 $ 3 FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2016 , are as follows: Operating Leases FirstEnergy (In millions) 2017 (1) $ 125 2018 142 2019 123 2020 97 2021 119 Years thereafter 1,351 Total minimum lease payments $ 1,957 (1) Includes a $3 million payment PNBV Trust will receive associated with certain sale and leaseback transactions. These arrangements, which expire in 2017, effectively reduce lease costs related to those transactions. FES' future minimum operating lease payments as of December 31, 2016 , are as follows: Operating Leases FES (In millions) 2017 $ 82 2018 101 2019 97 2020 68 2021 93 Years thereafter 1,222 Total minimum lease payments $ 1,663 |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
INTANGIBLE ASSETS | INTANGIBLE ASSETS As of December 31, 2016 , intangible assets classified in Customer Intangibles and Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2016 2017 2018 2019 2020 2021 Thereafter NUG contracts (1) $ 124 $ 31 $ 93 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 68 OVEC (2) 54 48 6 2 1 1 — — — 4 Coal contracts (2)(3)(4) 556 544 12 55 — — — — — — FES customer contracts (5) 148 139 9 52 5 3 1 — — — $ 882 $ 762 $ 120 $ 114 $ 11 $ 9 $ 6 $ 5 $ 5 $ 72 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) Amortization expense excludes impairment charges related to intangible assets recognized in 2016, which totaled $92 million and are included in Impairment of Assets. See "Note 2, Asset Impairments" for further discussion. (3) The coal contracts were recorded with a regulatory offset and the amortization does not impact earnings. Accordingly, the amortization expense for these coal contracts is excluded from table above. (4) A gross amount of $40 million of coal contracts is related to FES. In June 2016, FES terminated a coal contract and the write-off is included in amortization expense in the table above. (5) During 2016, FES recorded a pre-tax charge of $37 million associated with the termination of a customer contract, which is included in amortization expense in the table above. FES acquired certain customer contract rights which were capitalized as intangible assets. These rights allow FES to supply electric generation to customers, and the recorded value is being amortized ratably over the term of the related contracts. |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2016 | |
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. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. 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): • PNBV Trust - PNBV , a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties. • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (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, 2016 and December 31, 2015 , $339 million and $362 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. 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 and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of December 31, 2016 and December 31, 2015 , $85 million and $128 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds of which the proceeds were used to construct environmental control facilities. The special purpose limited liability companies 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 special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2016 and December 31, 2015 , $406 million and $429 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. See "Note 1, Organization, Basis of Presentation and Significant Accounting Policies - Investments", for additional information regarding FEV's investment in Global Holding. As discussed in "Note 16, Commitments, Guarantees and Contingencies", FE is the guarantor under Global Holding's $300 million term loan facility. 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 had previously suspended in February 2011, 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. • Purchase Power Agreements - FirstEnergy evaluated its power purchase agreements 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 14 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 $108 million and $116 million , respectively, during the years ended December 31, 2016 and 2015 . • Sale and Leaseback Transactions - OE and FES have obligations that are not included on their Consolidated Balance Sheets related to the Beaver Valley Unit 2 and 2007 Bruce Mansfield Unit 1 sale and leaseback arrangements, respectively, 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. As of December 31, 2016 , OE's leasehold interest was 2.60% of Beaver Valley Unit 2 and FES' leasehold interest was 93.83% of Bruce Mansfield Unit 1. On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Upon the completion of this transaction, NG will have obtained all of the lessor equity interests at Beaver Valley Unit 2. Therefore, upon the expiration of the Beaver Valley Unit 2 leases, NG will be the sole owner of Beaver Valley Unit 2 and entitled to 100% of the unit's output. FES and other FE subsidiaries are exposed to losses under their applicable 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 each company’s net exposure to loss based upon the casualty value provisions as of December 31, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,123 $ 879 $ 244 FES $ 1,098 $ 875 $ 223 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
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 the subsequent 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, 2016 , from those used as of December 31, 2015 . 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, 2016 and 2015 . 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, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,247 $ — $ 1,247 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 10 200 — 210 4 224 — 228 Derivative assets - FTRs — — 7 7 — — 8 8 Derivative assets - NUG contracts (1) — — 1 1 — — 1 1 Equity securities (2) 925 — — 925 576 — — 576 Foreign government debt securities — 78 — 78 — 75 — 75 U.S. government debt securities — 161 — 161 — 180 — 180 U.S. state debt securities — 246 — 246 — 246 — 246 Other (3) 199 123 — 322 105 212 — 317 Total assets $ 1,134 $ 2,055 $ 8 $ 3,197 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (6 ) $ (118 ) $ — $ (124 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (6 ) (6 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (108 ) (108 ) — — (137 ) (137 ) Total liabilities $ (6 ) $ (118 ) $ (114 ) $ (238 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 1,128 $ 1,937 $ (106 ) $ 2,959 $ 676 $ 2,060 $ (141 ) $ 2,595 (1) NUG contracts are subject to regulatory accounting treatment and 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 cash and short-term cash investments. (4) Excludes $(3) million and $7 million as of December 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 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 (1) NUG contracts are subject to regulatory accounting treatment and 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, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 1 Model RTO auction clearing prices ($4.20) to $6.10 $0.80 Dollars/MWH NUG Contracts $ (107 ) Model Generation 400 to 2,984,000 $32.60 to $33.40 754,000 $32.80 MWH FES Recurring Fair Value Measurements December 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 726 $ — $ 726 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 10 200 — 210 4 224 — 228 Derivative assets - FTRs — — 4 4 — — 5 5 Equity securities (1) 634 — — 634 378 — — 378 Foreign government debt securities — 58 — 58 — 59 — 59 U.S. government debt securities — 48 — 48 — 23 — 23 U.S. state debt securities — 3 — 3 — 4 — 4 Other (2) 2 81 — 83 — 184 — 184 Total assets $ 646 $ 1,116 $ 4 $ 1,766 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (6 ) $ (118 ) $ — $ (124 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (5 ) (5 ) — — (11 ) (11 ) Total liabilities $ (6 ) $ (118 ) $ (5 ) $ (129 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 640 $ 998 $ (1 ) $ 1,637 $ 373 $ 1,050 $ (6 ) $ 1,417 (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 $2 million and $1 million as of December 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (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, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (1 ) Model RTO auction clearing prices ($4.20) to $5.30 $0.60 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. 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, 2016 and December 31, 2015 : December 31, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,735 $ 38 $ 1,773 $ 1,778 $ 16 $ 1,794 FES 847 27 874 801 9 810 Equity securities FirstEnergy $ 822 $ 103 $ 925 $ 542 $ 34 $ 576 FES 564 70 634 354 24 378 (1) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 million . (2) Excludes short-term cash investments: FirstEnergy - $157 million ; FES - $139 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, 2016 , 2015 and 2014 were as follows: 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 December 31, 2014 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,133 $ 146 $ (75 ) $ (37 ) $ 96 FES 1,163 113 (54 ) (33 ) 56 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, 2016 and December 31, 2015 are immaterial to FirstEnergy. Investments in employee benefit trusts and equity method investments totaling $266 million as of December 31, 2016 and $255 million as of December 31, 2015 , 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, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,885 $ 19,829 $ 20,244 $ 21,519 FES 3,000 1,555 3,027 3,121 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, 2016 and December 31, 2015 . |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
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 $12 million and $11 million as of December 31, 2016 and December 31, 2015 , respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. 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 $33 million (FES $3 million ) and $42 million (FES $3 million ) as of December 31, 2016 and December 31, 2015 , respectively. Based on current estimates, approximately $8 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months. Refer to "Note 3, Accumulated Other Comprehensive Income", for reclassifications from AOCI during the years ended December 31, 2016 and 2015 . As of December 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 , 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 $10 million and $20 million as of December 31, 2016 and December 31, 2015 , respectively. During the next twelve months, approximately $7 million of unamortized gains are expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $10 million and $12 million during the years ended December 31, 2016 and 2015 , respectively. As of December 31, 2016 and December 31, 2015 , 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, 2016 , FirstEnergy's net asset position under commodity derivative contracts was $86 million , which related to FES positions. Under these commodity derivative contracts, FES posted $52 million of collateral. Based on commodity derivative contracts held as of December 31, 2016 , an increase in commodity prices of 10% would decrease net income by approximately $29 million during the next twelve months. NUGs As of December 31, 2016 , FirstEnergy's net liability position under NUG contracts was $107 million representing contracts held at JCP&L, ME and PN. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of December 31, 2016 , FirstEnergy's net asset associated with FTRs was $1 million and FES' net liability associated with FTRs was $1 million , and FES posted $5 million of collateral. 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 - Derivatives Commodity Contracts $ 133 $ 150 Commodity Contracts $ (72 ) $ (94 ) FTRs 7 7 FTRs (6 ) (12 ) 140 157 (78 ) (106 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (108 ) (137 ) Commodity Contracts 77 78 Noncurrent Liabilities - Other FTRs — 1 Commodity Contracts (52 ) (37 ) NUGs (1) 1 1 FTRs — (1 ) 78 80 (160 ) (175 ) Derivative Assets $ 218 $ 237 Derivative Liabilities $ (238 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and 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 $ 133 $ 150 Commodity Contracts $ (72 ) $ (94 ) FTRs 4 4 FTRs (5 ) (10 ) 137 154 (77 ) (104 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 77 78 Commodity Contracts (52 ) (37 ) FTRs — 1 FTRs — (1 ) 77 79 (52 ) (38 ) Derivative Assets $ 214 $ 233 Derivative Liabilities $ (129 ) $ (142 ) 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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) 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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 5 (5 ) — — $ 233 $ (130 ) $ — $ 103 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (11 ) 5 6 — $ (142 ) $ 130 $ 9 $ (3 ) The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of December 31, 2016 : Purchases Sales Net Units (In millions) Power Contracts 18 47 (29 ) MWH FTRs 28 — 28 MWH NUGs 3 — 3 MWH Natural Gas 29 29 — mmBTU The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2016 : Purchases Sales Net Units (In millions) Power Contracts 18 47 (29 ) MWH FTRs 22 — 22 MWH Natural Gas 29 29 — mmBTU The effect of active derivative instruments not in a hedging relationship on FirstEnergy's Consolidated Statements of Income (Loss) during 2016 , 2015 and 2014 are summarized in the following tables: Year Ended December 31 Commodity Contracts 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 ) Year Ended December 31 Commodity FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (86 ) $ 22 $ — $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ (6 ) $ 68 $ — $ 62 Purchased Power Expense 365 — — 365 Other Operating Expense — (44 ) — (44 ) Fuel Expense (6 ) — — (6 ) Interest Expense — — 14 14 The effect of active derivative instruments not in a hedging relationship on FES' Consolidated Statements of Income (Loss) during 2016 , 2015 and 2014 are summarized in the following tables: Year Ended December 31 Commodity Contracts 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 ) Year Ended December 31 Commodity FTRs Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (86 ) $ 21 $ (65 ) Realized Gain (Loss) Reclassified to: Revenues $ (6 ) $ 67 $ 61 Purchased Power Expense 365 — 365 Other Operating Expense — (43 ) (43 ) The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during 2016 and 2015 . 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, 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 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (47 ) (9 ) (56 ) Purchases — 12 12 Settlements 62 (13 ) 49 Outstanding net asset (liability) as of December 31, 2015 $ (136 ) $ 1 $ (135 ) |
Capitalization
Capitalization | 12 Months Ended |
Dec. 31, 2016 | |
Capitalization, Long-term Debt and Equity [Abstract] | |
Capitalization | CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2016 , FirstEnergy had an accumulated deficit of $4.5 billion . Dividends declared in 2016 and 2015 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 19, 2017 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 2017 . 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 the 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, 2016 . Stock Issuance 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. An independent fiduciary was retained to manage and liquidate the stock over time at its discretion. FE issued approximately 2.7 million shares of common stock in 2016 and 2.5 million shares of common stock in 2015 and 2014 to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2016 , 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, 2016 , and 2015 , there were no preferred or preference shares 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, 2016 and 2015 : As of December 31, 2016 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2016 2015 FirstEnergy: FMBs 2017 - 2056 3.340% - 9.740% $ 3,328 $ 3,269 Secured notes - fixed rate 2017 - 2037 0.679% - 12.000% 2,295 2,096 Secured notes - variable rate 2017 3.500% 10 2 Total secured notes 2,305 2,098 Unsecured notes - fixed rate 2017 - 2045 2.150% - 7.700% 13,058 13,580 Unsecured notes - variable rate 2021 2.430% 1,200 1,292 Total unsecured notes 14,258 14,872 Capital lease obligations 104 132 Unamortized debt discounts (25 ) (18 ) Unamortized debt issuance costs (87 ) (93 ) Unamortized fair value adjustments (6 ) 5 Currently payable long-term debt (1,685 ) (1,166 ) Total long-term debt and other long-term obligations $ 18,192 $ 19,099 FES: Secured notes - fixed rate 2017 - 2022 4.250% - 12.000% $ 617 $ 340 Secured notes - variable rate 2017 3.500% 10 2 Total secured notes 627 342 Unsecured notes - fixed rate 2017 - 2039 2.150% - 6.800% 2,373 2,593 Unsecured notes - variable rate — 92 Total unsecured notes 2,373 2,685 Capital lease obligations 8 13 Unamortized debt discounts (1 ) (1 ) Unamortized debt issuance costs (15 ) (17 ) Currently payable long-term debt (179 ) (512 ) Total long-term debt and other long-term obligations $ 2,813 $ 2,510 On May 1, 2016, JCP&L repaid $300 million of 5.625% senior unsecured notes at maturity. On June 1 and July 1 of 2016, NG repurchased approximately $225 million and $60 million, respectively of PCRBs, which were subject to a mandatory put on such date. On August 15, 2016, NG remarketed the approximately $285 million of PCRBs secured by FMBs with a fixed interest rate of 4.375% and mandatory put dates ranging from June 1, 2022 to July 1, 2022. On July 11, 2016, Penn issued $50 million of 4.24% FMBs due 2056. Proceeds received from the issuance of the FMBs were used: (i) to fund capital expenditures; (ii) for working capital needs and other general business purposes; and (iii) to repay borrowings under the FirstEnergy regulated companies' money pool. On August 15, 2016, WP repaid $145 million of 5.875% FMBs at maturity. Also, on September 23, 2016, WP agreed to sell $475 million of new 3.84% FMBs due 2046 ($100 million), 4.09% FMBs due 2047 ($100 million) and 4.14% FMBs due 2047 ($275 million). On December 15, 2016, WP issued the $100 million of 3.84% FMBs due 2046. The remaining sales are expected to settle on September 15, 2017 and December 15, 2017, respectively. Proceeds to be received from the issuances of the FMBs were or are, as the case may be, expected to be used: (i) for general corporate purposes; and (ii) to repay a portion of WP's $275 million of 5.95% FMBs that mature on December 15, 2017. On August 15, 2016, FG remarketed approximately $86 million of PCRBs secured by FMBs with fixed interest rates ranging from 4.25% to 4.50% and mandatory put dates ranging from May 1, 2021 to June 1, 2021. On September 15, 2016, FG remarketed $100 million of PCRBs secured by FMBs with a fixed interest rate of 4.25% and a mandatory put of September 15, 2021. On September 15 and 30, 2016, respectively, FG retired an aggregate of $12 million of PCRBs with original maturity dates in 2018 and 2029. On October 17, 2016, PE issued $155 million of 3.89% FMBs due 2046. Proceeds received from the issuance were used: (i) to repay short-term borrowings incurred to repay PE's $100 million of 5.80% FMBs that matured on October 15, 2016; and (ii) for general corporate purposes. 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, 2016 and 2015 , $406 million and $429 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, 2016 and 2015 , $85 million and $128 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, 2016 and 2015 , $339 million and $362 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, 2016 , the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. In 2016, FG remarketed $86 million of fixed rate PCRBs and retired $12 million of variable interest rate PCRBs, which resulted in the elimination of LOCs related to $92 million of variable interest rate PCRBs that are no longer outstanding. 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, 2016 . 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) 2017 $ 1,641 $ 163 2018 1,702 516 2019 2,266 478 2020 1,231 667 2021 832 774 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) 2017 $ 130 $ 130 2018 375 375 2019 232 232 2020 490 490 2021 342 342 Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable bank LOCs, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs, FG is entitled to a credit against its obligation to repay those bonds. FG pays annual fees based on the amounts of the LOCs to the issuing bank and is obligated to reimburse the bank for any drawings thereunder. 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, 2016 , 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, 2016 | |
Debt Disclosure [Abstract] | |
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT | SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT On December 6, 2016, FE and certain subsidiaries entered into new five-year syndicated credit facilities available through December 6, 2021, and concurrently terminated existing syndicated credit facilities that were to expire March 31, 2019, as follows: • FE and the Utilities entered into a new $4 billion revolving credit facility, which represents an increase of $500 million over the existing $3.5 billion facility it replaced, • FET and its subsidiaries entered into a $1 billion revolving credit facility, which replaced their existing $1 billion facility, and • FES and AE Supply terminated their unsecured $1.5 billion credit facility (commitments of $900 million and $600 million for FES and AE Supply, respectively) and FES entered into a new, two-year secured credit facility with FE in which FE provided a committed line of credit to FES of up to $500 million and additional credit support of up to $200 million to cover a $169 million surety bond for the benefit of the PA DEP with respect to LBR, and other bonds as designated in writing to FE. In connection with the cancellation of the prior FES/AE Supply facility and entry into the new FES secured facility with FE, certain commitments and amendments associated with shared services and operational matters were made including, without limitation, as follows: (i) FE reaffirmed its obligations under the Intercompany Tax Allocation Agreement, and (ii) amendments to the Service Agreement by and among FESC, FES, FG and NG, to prevent termination until the earlier of December 31, 2018, or a change in control of FES or its subsidiaries. FE, the Utilities and FET and its subsidiaries may use borrowings under their new facilities for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. FES expects to use its new facility with FE to conduct its ordinary course of business in lieu of borrowing under the unregulated money pool. The new facility matures on December 31, 2018, and is secured by FMBs issued by FG ($250 million) and NG ($450 million). Under the terms of the new FE and FET credit facilities, each borrower is required to maintain a consolidated debt to total capitalization ratio, as defined, of no more than 0.65 to 1.00, or in the case of FET, 0.75 to 1.00. For purposes of calculating its ratio, FE is permitted certain adjustments to total capitalization including (i) an exclusion for certain previously incurred after-tax, non-cash write-downs and non-cash charges of approximately $2.75 billion and (ii) a new exclusion for additional after-tax, non-cash write-downs and non-cash charges up to $5.5 billion related to asset impairments attributable to the power generation assets owned by FES, AE Supply and each of their subsidiaries. Additionally, under the new credit facility, FE is now also required to maintain a minimum interest coverage ratio of 1.75 to 1.00 until December 31, 2017, 2.00 to 1.00 beginning January 1, 2018 until December 31, 2018, 2.25 to 1.00 beginning January 1, 2019 until December 31, 2019, and 2.50 to 1.00 beginning January 1, 2020 until December 31, 2021. FE and each of the other borrowers under the new FE and FET credit facilities are currently in compliance with these financial covenants. In the case of FE, the impairment charges recognized in the fourth quarter of 2016 described under Note 2, Asset Impairments, are excluded from FE's calculation of total capitalization pursuant to the new $5.5 billion after-tax exclusion referenced in (ii) above consistent with the terms of the facility. Other terms of the new FE credit facility exclude FES and AE Supply from the definition of “significant subsidiaries,” which removes them from FE’s covenants and defaults resulting from adverse judgments in excess of $100 million and eliminates lender approvals previously required for FES and AE Supply asset sales. Outstanding alternate base rate advances under the new FE and FET facilities will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to the applicable borrower’s then-current senior unsecured non-credit enhanced debt ratings (reference ratings) plus the highest of (i) the “prime rate” published by the Wall Street Journal from time to time, (ii) the sum of 1/2 of 1% per annum plus the federal funds rate in effect from time to time and (iii) the LIBOR for a one-month interest period plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to the applicable borrower’s reference ratings. Swing line loans under the new FE facility will bear interest at a rate per annum equal to the sum of the alternate base rate plus an applicable margin determined by reference to the applicable borrower’s reference ratings. Changes in reference ratings of a borrower would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. FirstEnergy had $2,675 million and $1,708 million of short-term borrowings as of December 31, 2016 and 2015 , respectively. FirstEnergy’s available liquidity from external sources as of January 31, 2017 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2021 $ 4,000 $ 1,341 FET (2) Revolving December 2021 1,000 1,000 Subtotal $ 5,000 $ 2,341 Cash — 308 Total $ 5,000 $ 2,649 (1) FE and the Utilities. (2) Includes FET, ATSI and TrAIL. FES had $101 million (payable to AE Supply) and $8 million of short-term borrowings as of December 31, 2016 and 2015, respectively. FES' available liquidity as of January 31, 2017 was as follows: Type Commitment Available Liquidity (In millions) Two-year secured credit facility with FE $ 500 $ 500 Cash — 2 $ 500 $ 502 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 December 31, 2016 : Borrower 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 500 500 (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)(3) (1) No limitations. (2) Excluding amounts which may be borrowed under the regulated companies' money pool. (3) Pending regulatory approval, as discussed under "FERC Matters" below. 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, 2016, the borrowers were in compliance with the applicable debt to total capitalization ratio covenants as well as in the case of FE, the minimum interest coverage ratio requirement, in each case as defined under the respective facilities. In the case of FE, the impairment charges recognized in the fourth quarter of 2016 disclosed in "Note 2. Asset Impairments" above are excluded from FE's calculation of total capitalization pursuant to the new exclusion referenced in (ii) above consistent with the terms of the facility. Term Loans On December 6, 2016, FE terminated its existing $1 billion and $200 million term loan credit agreements and entered into a new $1.2 billion five-year syndicated term loan credit agreement. The term loan contains covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt to total capitalization ratio and minimum interest coverage ratio requirement. The initial borrowing under the new $1.2 billion FE term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. On February 16, 2017, FE entered into two separate $125 million three-year term loan credit agreements with Bank of America, N.A. and The Bank of Nova Scotia, respectively, the proceeds of which were used to reduce short-term debt. The terms and conditions of these new credit agreements are substantially similar to the December 6, 2016, $1.2 billion five-year syndicated term loan credit agreement. As of December 31, 2016 , FE was in compliance with the applicable consolidated debt to total capitalization ratio covenants as well as the interest coverage ratio requirement, as defined under its term loan. 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. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, 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 2016 was 0.69% per annum for the regulated companies’ money pool and 2.02% per annum for the unregulated companies’ money pool. As discussed above, FES expects to use its new $500 million secured credit facility with FE in lieu of borrowing under the unregulated companies' money pool. In addition, a separate money pool for use by FES, its subsidiaries and FENOC is expected to be established in the first quarter of 2017 at which time those companies will no longer have access to the unregulated companies' money pool. As of January 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, 2016 and 2015 , were as follows: 2016 2015 FirstEnergy 2.47 % 2.16 % |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
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, which total $713 million , as of December 31, 2016 . 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, 2016 and 2015 were as follows: 2016 2015 (In millions) FirstEnergy $ 2,514 $ 2,282 FES $ 1,552 $ 1,327 The following table summarizes the changes to the ARO balances during 2016 and 2015 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2015 $ 1,387 $ 841 Liabilities settled (13 ) (8 ) Accretion 92 55 Revisions in estimated cash flows (56 ) (57 ) Balance, December 31, 2015 $ 1,410 $ 831 Liabilities settled (27 ) (18 ) Accretion 95 56 Liabilities Incurred 4 32 Balance, December 31, 2016 $ 1,482 $ 901 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. During 2015, FE and FES reduced its ARO by $57 million based on the results of decommissioning cost studies for the Davis-Besse and Perry nuclear generating stations. Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, any 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, 2016 | |
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, Illinois, Michigan, New Jersey and Maryland, 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. 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. PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014. 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 set in PE's plan for 2016, and increasing 0.2% per year thereafter to reach 2% . The costs of the 2015-2017 plan are expected to be approximately $70 million , of which $43 million was incurred through December 31, 2016. PE continues to recover 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 yet 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. Initial comments in the proceeding were filed on October 28, 2016, and the MDPSC held an initial hearing on the matter on December 8-9, 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. 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. 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 include 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 (Generic CTA proceeding), 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 New Jersey Superior Court and JCP&L filed to participate as a respondent in that proceeding. Briefing has been completed. The oral argument was held on October 25, 2016. On April 28, 2016, JCP&L filed tariffs with the NJBPU proposing a general rate increase associated with its distribution operations 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. The filing requested approval to increase annual operating revenues by approximately $142.1 million based upon a hybrid test year for the twelve months ending June 30, 2016. On November 30, 2016, JCP&L submitted to the ALJ a Stipulation of Settlement achieved with all the intervening parties providing for an annual $80 million distribution revenue increase, effective January 1, 2017. The ALJ filed an Initial Decision concluding that the Stipulation of Settlement should be approved, and the NJBPU approved the Stipulation of Settlement on December 12, 2016. As part of the Stipulation of Settlement the intervening parties agreed that JCP&L can accelerate the amortization of the 2012 major storm expenses (approximately $19 million annually) that are recovered through the SRC to achieve full recovery by December 31, 2019. On November 23, 2016, JCP&L filed an Amendment to its January 15, 2016 SRC Filing with the NJBPU, requesting that JCP&L be able to accelerate the amortization of the 2012 major storm expenses as agreed to in the Stipulation of Settlement, and a Stipulation of Settlement with NJBPU Staff and the Division of Rate Counsel regarding the SRC Filing was filed on December 27, 2016. The NJBPU approved this Stipulation of Settlement at the January 25, 2017 public meeting. OHIO The Ohio Companies currently operate under an ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinions and Orders issued on March 31, 2016 and 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. The Rider DMR will be grossed up for taxes, resulting in an approved amount of approximately $204 million annually. Revenues from the 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 approximately $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 the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs, an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016), a goal across FirstEnergy to reduce CO2 emissions by 90% below 2005 levels by 2045, and contributions, totaling $51 million , to fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territory, and a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers, and to establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio. On April 29, 2016 and May 2, 2016, several parties, including the Ohio Companies, filed applications for rehearing on the Ohio Companies’ ESP IV with the PUCO. On September 6, 2016, while the applications for rehearing were still pending before the PUCO, the OCC and NOAC filed a notice of appeal with the Ohio Supreme Court appealing various PUCO and Attorney Examiner Entries on the parties’ applications for rehearing. On September 16, 2016, the Ohio Companies intervened and filed a motion to dismiss the appeal. The PUCO resolved such applications for rehearing in the October 12, 2016 Opinion and Order. The OCC and NOAC appeal remains pending before the Ohio Supreme Court. On November 10, 2016 and November 14, 2016, several parties, including the Ohio Companies, filed additional applications for rehearing on 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 December 7, 2016, the PUCO granted the applications for rehearing for further consideration of the matters specified in the applications for rehearing. The matter remains pending before the PUCO. For additional information, see “FERC Matters - Ohio ESP IV PPA,” below. Under ORC 4928.66, the Ohio Companies were required to implement energy efficiency programs that achieved a total annual energy savings of 1,990 GWHs and total peak demand reduction of 486 MWs in 2015. On May 12, 2016, the Ohio Companies filed their Energy Efficiency and Peak Demand Reduction Program Status Report indicating compliance with their 2015 statutory benchmarks. In 2016, the Ohio Companies estimated the annual energy savings target and peak demand reduction target will be comparable to the 2015 targets due to the energy efficiency requirements under SB310, which amended ORC 4928.66 to freeze the energy efficiency and peak demand reduction benchmarks for 2015 and 2016. 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. 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. The hearings were held in January 2017 . 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 2015 and 2016 that remain at the 2014 level. 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. On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order. The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded. The matter is not yet scheduled for oral argument. 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. The matter remains pending before the PUCO. PENNSYLVANIA The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through spot market purchases, quarterly descending clock auctions for 3-, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn. Following the expiration of the current DSPs, the Pennsylvania Companies will operate under new 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 new 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. In addition, the new DSPs include modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase II EE&C Plans were effective through May 31, 2016. Total Phase II costs of these plans were $174 million and are recoverable through the Pennsylvania Companies' reconcilable EE&C riders. 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 October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five -year period of 2016 to 2020 for the following costs: WP- $88.34 million ; PN- $56.74 million ; Penn- $56.35 million ; and ME- $43.44 million . On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. On June 9, 2016, the PPUC approved the Pennsylvania Companies’ DSIC riders to be effective July 1, 2016, subject to hearings and refund or reallocation among customers. The four proceedings were consolidated by the ALJ. On January 19, 2017, in the PPUC’s order approving the Pennsylvania Companies’ general rate cases, discussed below, the PPUC referred the issue of whether ADIT should be included in DSIC calculations to the consolidated DSIC proceeding. On February 2, 2017, the parties to the consolidated DSIC proceeding submitted a Joint Settlement to the ALJ to resolve issues referred to by the ALJ in its June 9, 2016 Order, subject to PPUC approval, and would not result in any refund or reallocation among customers. The ADIT issue will be considered separately from the issues resolved in the Joint Settlement Petition of February 2, 2017, and is the sole issue to be litigated in the consolidated DSIC proceeding through a procedural schedule to be determined by the ALJ. On April 28, 2016, each of the Pennsylvania Companies filed tariffs with the PPUC proposing general rate increases associated with their distribution operations to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. The filings requested approval to increase annual operating revenues by approximately $140.2 million at ME, $158.8 million at PN, $42.0 million at Penn, and $98.2 million at WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. As a result of the enactment of Act 40 of 2016 that terminated the practice of making a CTA when calculating a utility’s federal income taxes for ratemaking purposes, the Pennsylvania Companies submitted supplemental testimony on July 7, 2016, that quantified the value of the elimination of the CTA and outlined their plan for investing 50 percent of that amount in rate base eligible equipment as required by the new law. Formal settlement agreements for each of the Pennsylvania Companies were filed on October 14, 2016, which proposed increases in annual operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP. One item related to the calculation of DSIC rates was reserved for briefing, with briefs filed by two parties. On November 21, 2016, the ALJ issued a Recommended Decision recommending approval of the settlement agreements and dismissal of the one issue reserved for briefing. Exceptions to that Recommended Decision were filed by one party on December 1, 2016, and reply exceptions were filed by the Pennsylvania Companies on December 8, 2016. On January 19, 2017, the PPUC issued an order approving the settlements and referring the reserved issue to the Pennsylvania Companies’ consolidated DSIC proceeding. On February 3, 2017, one party filed a Petition for Reconsideration or Clarification relating to the limited issue of the scope of the record to be transferred to the DSIC proceeding, discussed above. The outcome of this request will not affect the new rates which took effect on January 27, 2017. 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 March 31, 2016, MP and PE filed with the WVPSC seeking approval of their Phase II energy efficiency program including three MP and PE energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of the 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. A unanimous settlement was reached by the parties on all issues and presented to the WVPSC on August 18, 2016. An order approving the settlement in full without modification was issued by the WVPSC on September 23, 2016. The Phase II program began initial implementation in November 2016. The Staff of the WVPSC and the Consumer Advocate Division filed a Show Cause petition on August 5, 2016, requesting that the WVPSC order MP and PE to file and implement RFPs for all future capacity and energy requirements above 100 MWs and that they comply with an RFP settlement provision from the Harrison power station acquisition. MP and PE filed a timely response to the petition arguing for dismissal on September 7, 2016. On October 17, 2016, the WVPSC denied the petition filed by the Staff of the WVPSC and the Consumer Advocate Division and dismissed the case. On August 16, 2016, MP and PE filed their annual ENEC case proposing an annual increase in rates of approximately $65 million effective January 1, 2017, which is a 4.7% increase over existing rates. The increase is comprised of a $119 million under-recovered balance as of June 30, 2016, and a projected $54 million over-recovery for the 2017 rate effective period. The parties reached a unanimous settlement providing for a $25 million increase beginning January 1, 2017 and keeping ENEC rates at the same level for a two year period. The settlement was presented to the WVPSC at a hearing on November 9, 2016. On December 9, 2016, the WVPSC approved the settlement as submitted. On August 22, 2016, MP and PE filed an application for approval of a modernization and improvement plan for coal-fired boilers at electric power plants and cost-recovery surcharge proposing an approximate $6.9 million annual increase in rates to be effective May 1, 2017, which is a 0.5% increase over existing rates. The filing is in response to recent legislation by the West Virginia Legislature permitting accelerated recovery of costs related to modernizing and improving coal-fired boilers, including costs related to meeting environmental requirements and reducing emissions. The filing was supplemented on September 28, 2016, to add two additional projects, resulting in an approximate $7.4 million annual increase in rates. The Staff of the WVPSC filed a motion to dismiss the case arguing the new statute was not meant to recover these types of projects, but the WVPSC set the case for hearing for February 21-23, 2017. As part of the annual ENEC settlement described above, the parties agreed that MP and PE will increase ENEC rates to provide for a return of and on MATS/CSPR capital costs incurred during 2016-2017. Accordingly, MP and PE withdrew this case as part of the ENEC approval . On December 30, 2015, MP 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 finding that IRPs are informational and that it must not approve or disapprove the IRP. MP issued a RFP to address its generation shortfall identified in the IRP on December 16, 2016 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. MP expects to execute definitive agreements with selected respondent(s) and file the appropriate applications with the WVPSC and FERC by March 15, 2017 . RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES and its subsidiaries, AE Supply, FENOC, ATSI and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy, including FES, believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy, including FES, occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy, including FES, develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's, including FES, part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. FERC MATTERS Ohio ESP IV PPA On August 4, 2014, the Ohio Companies filed an application with the PUCO seeking approval of their ESP IV. ESP IV included a proposed Rider RRS, which would flow through to customers either charges or credits representing the net result of the price paid to FES through an eight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, against the revenues received from selling such output into the PJM markets. The Ohio Companies entered into stipulations which modified ESP IV, and on March 31, 2016, the PUCO issued an Opinion and Order adopting and approving the Ohio Companies’ stipulated ESP IV with modifications. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016. On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review the ESP IV PPA under Section 205 of the FPA. On April 27, 2016, FERC issued an order granting the complaint, prohibiting any transactions under the ESP IV PPA pending authorization by FERC, and directing FES to submit the ESP IV PPA for FERC review if the parties desired to transact under the agreement. FES and the Ohio Companies did not file the ESP IV PPA for FERC review but rather agreed to suspend the ESP IV PPA. FES and the Ohio Companies subsequently advised FERC of this course of action. On January 19, 2017, FERC issued an order accepting compliance filings by FES, its subsidiaries, and the Ohio Companies updating their respective market-based rate tariffs to clarify that affiliate sales restrictions under the tariffs apply to the ESP IV PPA, and also that the ESP IV PPA does not affect certain other waivers of its affiliate restrictions rules FERC previously granted these entities. On May 2, 2016, the Ohio Companies filed an Application for Rehearing with the PUCO that included a modified Rider RRS proposal that did not involve a FERC-jurisdictional PPA. Several parties subsequently filed protests and comments with FERC alleging, among other things, that the modified Rider RRS constituted a "virtual PPA". FERC rejected these protests in its January 19, 2017 order accepting the updated market-based rate tariffs of FES, its subsidiaries, and the Ohio Companies discussed below. On March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint requested that FERC direc |
Commitments, Guarantees and Con
Commitments, Guarantees and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
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 $13.3 billion (assuming 102 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million ; and (ii) $13 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 maximum potential assessment under these provisions would be $509 million (NG- $506 million ) per incident but not more than $76 million (NG- $75 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 annually, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.40 billion (NG- $1.39 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, 2016 , outstanding guarantees and other assurances aggregated approximately $3.3 billion , consisting of parental guarantees ( $581 million ), subsidiaries' guarantees ( $1,933 million ), other guarantees ($ 300 million ) and other assurances ( $465 million ). Of this 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 FES' power portfolio exposure as of December 31, 2016 , FES has posted collateral of $190 million and AE Supply has posted collateral of $4 million . The Regulated Distribution Segment has posted collateral of $3 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, 2016 : Potential Additional Collateral Obligations FES AE Supply Regulated Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 7 $ 3 $ — $ 10 Upon Further Downgrade — — 48 48 Surety Bonds (Collateralized Amount) (1) 240 25 102 367 Total Exposure from Contractual Obligations $ 247 $ 28 $ 150 $ 425 (1) Effective January 2017, FE is a guarantor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR. Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment. As of December 31, 2016 , neither FES nor AE Supply had any collateral posted with their affiliates. Moreover, a further downgrade for either FES or AE Supply would not trigger any obligations to post any such collateral. OTHER COMMITMENTS, CONTINGENCIES AND ASSURANCES FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million . In addition to FirstEnergy, 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. 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 U.S. Court of Appeals for 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 EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. 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. Depending on the outcome of the appeals and on how the EPA and the states 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. States will then have roughly three years to develop implementation plans to attain 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. 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. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately $345 million (CES segment of $168 million and Regulated Distribution segment of $177 million ), of which $286 million has been spent through December 31, 2016 ( $125 million at CES and $161 million at Regulated Distribution). On August 3, 2015, FG, a 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 arises 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. In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance. 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 liability hearing from November 28, 2016, through December 9, 2016, and, if necessary, a damages hearing is scheduled to begin on May 8, 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearing proceedings, which are scheduled to conclude February 24, 2017. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused. FG intends to vigorously assert its position in the arbitration proceedings. If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. Refer to the "Strategic Review of Competitive Operations" section of "Note 1, Organization and Basis of Presentation," for possible actions that may be taken by FES in the event of an adverse outcome, including, without limitation, seeking protection under U.S. bankruptcy laws. FirstEnergy and FES are unable to estimate the loss or range of loss. On December 22, 2016, FG, a wholly owned subsidiary of FES, received a demand for arbitration and statement of claim from BNSF and NS who 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 Plant. 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, among other things, damages, including lost profits through 2025, and a declaratory judgment that FG's claim of force majeure is invalid. FG intends to vigorously assert its position in this arbitration proceeding. 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. Refer to the "Strategic Review of Competitive Operations" section of "Note 1, Organization and Basis of Presentation," for possible actions that may be taken by FES in the event of an adverse outcome, including, without limitation, seeking protection under U.S. bankruptcy laws. FirstEnergy and FES are unable to estimate the loss or range of loss. As to both coal transportation agreements referenced in the above arbitration proceedings, FG paid approximately $70 million in the aggregate in liquidated damages to settle delivery shortfalls in 2014 related to its deactivated plants, which approximated full liquidated damages under the agreements for such year related to the plant deactivations. Liquidated damages for the period 2015-2025 remain in dispute under both coal transportation agreements. As to a specific coal supply agreement, AE Supply asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, the coal supplier commenced litigation alleging AE Supply does not have sufficient justification to terminate the agreement. AE Supply has filed an answer denying any liability related to the termination. This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 million tons remaining under the contract for delivery. At this time, AE Supply cannot estimate the loss or range of loss regarding the ongoing litigation with respect to this agreement. 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, 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, 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 United States 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 regulations in August 2015 (which have been stayed by the U.S. Supreme Court), to reduce CO 2 emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO 2 emission rate goals. The EPA’s CPP allows states to request a two -year extension to finalize SIPs by September 6, 2018. If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs. The EPA also finalized separate regulations imposing CO 2 emission limits for new, modified, and reconstructed fossil fuel fired electric generating units. Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for 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 . Depending on the outcome 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 greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and 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 are effective on November 4, 2016. It remains unclear whether and how the results of the 2016 United States election could impact the regulation of GHG emissions at the federal and state level. 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. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system. Depending on the results of such studies and any final action taken by the states based on those studies, 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 will 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. 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 coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding 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. Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs. Although not currently expected, any 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. On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility. 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 parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2016 based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $137 million have been accrued through December 31, 2016. Included in the total are accrued liabilities of approximately $89 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of loss cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2016 , FirstEnergy had approximately $2.5 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. The values of FirstEnergy's NDTs fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FE and FES have also entered into a total of $24.5 million in parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities. As FES no longer maintains investment grade credit ratings from either S&P or Moody’s, NG funded a $10 million supplemental trust in 2016 in lieu of the FES parental guarantee that would be required to support the decommissioning of the spent fuel storage facilities. The termination of the FES parental guarantee is subject to NRC review. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate. As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. These inspections revealed that the cracking condition had propagated a small amount in select areas. FENOC's analysis |
Transactions With Affiliated Co
Transactions With Affiliated Companies | 12 Months Ended |
Dec. 31, 2016 | |
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. The primary affiliated company transactions for FES during the three years ended December 31, 2016 are as follows: FES 2016 2015 2014 (In millions) Revenues: Electric sales to affiliates $ 457 $ 664 $ 861 Other 11 14 15 Expenses: Purchased power from affiliates 622 353 271 Fuel 4 1 1 Support services 748 705 619 Investment Income: Interest income from FE 2 2 3 Interest Expense: Interest expense to affiliates 5 4 3 Interest expense to FE 2 3 4 FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated 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, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are 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 are evaluating the possible termination of the PSA. 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 2016 , 2015 and 2014 , AE Supply sold 1.5 million , 1.2 million , and 1.7 million tons of coal to FES, respectively, at its cost of $80.4 million , $62.8 million , and $96.3 million , respectively. 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, 2016 | |
Supplemental Guarantor Information [Abstract] | |
SUPPLEMENTAL GUARANTOR INFORMATION | SUPPLEMENTAL GUARANTOR INFORMATION In 2007, FG completed a sale and leaseback transaction for its undivided interest in Bruce Mansfield Unit 1. 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 FES or FG, 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, 2016 , 2015 , and 2014 , Condensed Consolidating Balance Sheets as of December 31, 2016 and December 31, 2015 , and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2016 , 2015 , and 2014 , 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, 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 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 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 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 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 STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 5,990 $ 1,902 $ 2,172 $ (3,920 ) $ 6,144 OPERATING EXPENSES: Fuel — 1,055 198 — 1,253 Purchased power from affiliates 3,920 — 271 (3,920 ) 271 Purchased power from non-affiliates 2,767 4 — — 2,771 Other operating expenses 790 269 527 49 1,635 Pension and OPEB mark-to-market adjustment 19 90 188 — 297 Provision for depreciation 10 119 193 (3 ) 319 General taxes 72 31 25 — 128 Total operating expenses 7,578 1,568 1,402 (3,874 ) 6,674 OPERATING INCOME (LOSS) (1,588 ) 334 770 (46 ) (530 ) OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 791 8 61 (799 ) 61 Miscellaneous income 2 4 — — 6 Interest expense — affiliates (12 ) (6 ) (4 ) 15 (7 ) Interest expense — other (56 ) (102 ) (54 ) 60 (152 ) Capitalized interest — 4 30 — 34 Total other income (expense) 725 (92 ) 33 (724 ) (58 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (863 ) 242 803 (770 ) (588 ) INCOME TAXES (BENEFITS) (619 ) 87 298 6 (228 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (244 ) 155 505 (776 ) (360 ) Discontinued operations (net of income taxes of $8) — 116 — — 116 NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (10 ) — — — (10 ) Change in unrealized gain on available-for-sale securities 21 — 21 (21 ) 21 Other comprehensive income (loss) 5 (5 ) 21 (16 ) 5 Income taxes (benefits) on other comprehensive income (loss ) 2 (2 ) 8 (6 ) 2 Other comprehensive income (loss), net of tax 3 (3 ) 13 (10 ) 3 COMPREHENSIVE INCOME (LOSS) $ (241 ) $ 268 $ 518 $ (786 ) $ (241 ) 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 Prepayments 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 Customer intangibles 9 — — — 9 Property taxes — 12 28 — 40 Derivatives 77 — — — 77 Other 24 327 — 21 372 505 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 Other — — — — — 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 Accumulated deferred income taxes 4 3 — (7 ) — Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Derivatives 52 — — — 52 Other 42 85 860 — 987 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 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 ) $ 549 $ 1,103 $ (25 ) $ 785 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 — (6 ) (2 ) — (8 ) Net cash provided from (used for) financing activities 948 50 (25 ) (916 ) 57 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 ) $ 551 $ 1,261 $ (24 ) $ 1,151 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 — (5 ) (1 ) — (6 ) Net cash provided from (used for) financing activities 709 37 (81 ) (937 ) (272 ) 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 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 408 $ 785 $ (22 ) $ 571 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 431 447 — 878 Short-term borrowings, net 247 114 — (361 ) — Equity contribution from parent 500 — — — 500 Redemptions and Repayments- Long-term debt (1 ) (269 ) (568 ) 22 (816 ) Short-term borrowings, net — — (123 ) (178 ) (301 ) Other (1 ) (12 ) (2 ) — (15 ) Net cash provided from (used for) financing activities 745 264 (246 ) (517 ) 246 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (8 ) (169 ) (662 ) — (839 ) Nuclear fuel — — (233 ) — (233 ) Proceeds from asset sales — 307 — — 307 Sales of investment securities held in trusts — — 1,163 — 1,163 Purchases of investment securities held in trusts — — (1,219 ) — (1,219 ) Loans to affiliated companies, net (136 ) (815 ) 412 539 — Other (1 ) 5 — — 4 Net cash used for investing activities (145 ) (672 ) (539 ) 539 (817 ) 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, 2016 | |
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. During the fourth quarter of 2016, FirstEnergy modified its segment reporting to reclassify the results of operations from certain transmission assets of ME, PN and JCP&L, from the Regulated Distribution segment to the Regulated Transmission segment. Costs associated with these transmission assets, which are currently included in ME, PN, and JCP&L's stated rates, will be recovered through MAIT's and JCP&L’s formula rates prospectively, once approved by FERC. The external segment reporting is consistent with the internal financial reports used by FirstEnergy's Chief Executive Officer (its chief operating decision maker) to regularly assess performance of the business and allocate resources. Disclosures for FirstEnergy's reportable operating segments for 2015 and 2014 have been revised to conform to the current presentation reflecting the operating activity of the identified transmission assets within Regulated Transmission. 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 and TrAIL and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). This segment also includes the regulatory asset associated with the abandoned PATH project. 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 "FERC Matters" below, effective January 31, 2017, MAIT includes the transmission assets of ME and PN, and JCP&L submitted applications to FERC requesting authorization to implement forward-looking formula transmission rates. Those applications are pending before FERC. Both the forward-looking and stated rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL's revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. 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, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. As of December 31, 2016, this business segment controlled 13,162 MWs of electric generating capacity, including , as discussed in "Note 15, Regulatory Matters", 1,572 MWs of natural gas and hydroelectric generating capacity subject to an asset purchase agreement with Aspen and the 1,300 MW Pleasants power station which was offered into MP's RFP process by AE Supply. 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. Corporate support not charged to FE's subsidiaries, 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, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.7 billion was borrowed by FE under its revolving credit facility. Segment Financial Information For the Years Ended December 31 Regulated Distribution Regulated Transmission Competitive Energy Services Corporate/ Other Reconciling Adjustments Consolidated (In millions) 2016 External revenues $ 9,629 $ 1,151 $ 4,070 $ — $ (288 ) $ 14,562 Internal revenues — — 479 — (479 ) — Total revenues 9,629 1,151 4,549 — (767 ) 14,562 Depreciation 676 187 387 63 — 1,313 Amortization of regulatory assets, net 313 7 — — — 320 Impairment of assets — — 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 ) (121 ) 2 (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 $ 1,054 $ 4,698 $ — $ (308 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,582 1,054 5,384 — (994 ) 15,026 Depreciation 664 164 394 60 — 1,282 Amortization of regulatory assets, net 261 7 — — — 268 Impairment of assets 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 (262 ) 11 315 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 2014 External revenues $ 9,054 $ 817 $ 5,470 $ — $ (292 ) $ 15,049 Internal revenues — — 819 — (819 ) — Total revenues 9,054 817 6,289 — (1,111 ) 15,049 Depreciation 651 134 387 48 — 1,220 Amortization of regulatory assets, net 1 11 — — — 12 Investment income 56 — 54 2 (40 ) 72 Interest expense 603 117 197 168 (4 ) 1,081 Income taxes (benefits) 209 139 (223 ) (178 ) 11 (42 ) Income (loss) from continuing operations 433 255 (417 ) (58 ) — 213 Discontinued operations, net of tax — — 86 — — 86 Net income (loss) 433 255 (331 ) (58 ) — 299 Total assets 27,332 6,864 16,180 1,176 — 51,552 Total goodwill 5,092 526 800 — — 6,418 Property additions 855 1,446 939 72 — 3,312 |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Discontinued Operations | DISCONTINUED OPERATIONS On February 12, 2014, certain of FirstEnergy's subsidiaries sold eleven hydroelectric power stations to a subsidiary of LS Power Equity Partners II, LP for approximately $ 394 million (FES - $ 307 million ). The carrying value of the assets sold was $ 235 million (FES - $ 122 million ), including goodwill of $29 million (FES - $1 million ). Pre-tax income for the hydroelectric facilities of $ 155 million (FES - $ 186 million ) for the year ended December 31, 2014, was included in discontinued operations in the Consolidated Statement of Income (Loss). Included in income for discontinued operations in the year ended December 31, 2014, was a pre-tax gain on the sale of assets of $ 142 million (FES - $ 177 million ). Revenues for the hydroelectric facilities of $ 5 million (FES - $5 million ) for year ended December 31, 2014, were included in discontinued operations in the Consolidated Statement of Income (Loss). |
Summary of Quarterly Financial
Summary of Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 and 2015 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2016 2015 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,375 $ 3,917 $ 3,401 $ 3,869 $ 3,541 $ 4,123 $ 3,465 $ 3,897 Other operating expense 1,023 953 964 918 950 842 900 1,057 Pension and OPEB mark-to-market adjustment 147 — — — 242 — — — Provision for depreciation 339 311 334 329 313 328 322 319 Impairment of assets 9,218 — 1,447 — 18 8 16 — Operating Income (Loss) (8,924 ) 861 (975 ) 776 236 908 554 594 Income (loss) before income taxes (benefits) (9,185 ) 631 (1,219 ) 541 (396 ) 621 302 366 Income taxes (benefits) (3,389 ) 251 (130 ) 213 (170 ) 226 115 144 Net Income (Loss) (5,796 ) 380 (1,089 ) 328 (226 ) 395 187 222 Earnings (loss) per share of common stock- (1) Basic - Earnings (losses) Available to FirstEnergy Corp. (13.44 ) 0.89 (2.56 ) 0.78 (0.53 ) 0.94 0.44 0.53 Diluted - Earnings (losses) Available to FirstEnergy Corp. (13.44 ) 0.89 (2.56 ) 0.77 (0.53 ) 0.93 0.44 0.53 (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 and the $500 million equity issuance in December 2016. See FirstEnergy's Consolidated Statements of Stockholders' Equity, "Note 5, Stock-Based Compensation Plans" and "Note 12, Capitalization" for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) 2016 2015 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 997 $ 1,100 $ 1,102 $ 1,199 $ 1,171 $ 1,338 $ 1,119 $ 1,377 Other operating expense 352 316 369 240 312 246 337 413 Pension and OPEB mark-to-market adjustment 48 — — — 57 — — — Provision for depreciation 86 83 84 83 84 79 81 80 Impairment of assets 8,082 — 540 — 17 — 16 — Operating Income (Loss) (8,153 ) 101 (571 ) 226 25 240 — 12 Income (loss) from continuing operations before income taxes (benefits) (8,171 ) 96 (581 ) 213 (13 ) 190 (25 ) (5 ) Income taxes (benefits) (2,983 ) 56 (143 ) 82 1 70 (4 ) (2 ) Net Income (Loss) (5,188 ) 40 (438 ) 131 (14 ) 120 (21 ) (3 ) |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS On January 18, 2017, AE Supply and AGC entered into an asset purchase agreement to sell four of AE Supply’s natural gas generating plants in Pennsylvania and approximately 59% of AGC’s interests in a Virginia hydroelectric power station to Aspen. The power stations included in the sale have a total capacity of 1,572 MWs: • Bath County Hydro ( 713 MWs pumped-storage hydro) in Warm Springs, Va. (represents AE Supply’s indirect interest) • Springdale Generating Facility Units 1-5 ( 638 MWs natural gas) in Springdale Township, Pa. • Chambersburg Generating Facility Units 12-13 ( 88 MWs natural gas) in Guildford Township, Pa. • Gans Generating Facility Units 8-9 ( 88 MWs natural gas) in Springhill Township, Pa. • Hunlock Creek ( 45 MWs natural gas) in Hunlock Creek, Pa. Under the terms of the agreement, the facilities would be purchased for an all cash purchase price of approximately $925 million . The transaction is expected to close in the third quarter of 2017 subject to satisfaction of various customary and other closing conditions, including, without limitation, receipt of regulatory approvals, third party consents and the satisfaction and discharge of AE Supply’s senior note indenture, under which there is approximately $305 million aggregate principal amount of indebtedness outstanding. There can be no assurance that any such approvals will be obtained and/or any such conditions will be satisfied or that such sale will be consummated. Further, the satisfaction and discharge of AE Supply’s senior note indenture in connection with the closing is expected to require the payment of a “make-whole” premium calculated just prior to the redemption, which based on current interest rates is approximately $100 million . It is expected that proceeds from the sale will be invested in the unregulated money pool and may be used for the repayment of debt and general corporate purposes. As a further condition to closing, FE will provide Aspen two limited guaranties of certain obligations of AE Supply and AGC arising under the purchase agreement. The guaranties vary in amount and scope and expire in one and three years, respectively. On February 16, 2017, FE entered into two separate $125 million three-year term loan credit agreements with Bank of America, N.A. and The Bank of Nova Scotia, respectively, the proceeds of which were used to reduce short-term debt. The terms and conditions of these new credit agreements are substantially similar to the December 6, 2016, $1.2 billion five-year syndicated term loan credit agreement. |
Consolidated Valuation and Qual
Consolidated Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , 2015 AND 2014 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) 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 Year Ended December 31, 2014: Accumulated provision for uncollectible accounts — customers $ 51,630 $ 90,144 $ 36,373 $ 118,881 $ 59,266 — other $ 2,976 $ 3,469 $ 8,264 $ 9,512 $ 5,197 Valuation allowance on state and local DTAs $ 125,360 $ 48,644 $ — $ — $ 174,004 (1) Represents recoveries and reinstatements of accounts previously written off. (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, 2016 , 2015 AND 2014 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) 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 Year Ended December 31, 2014: Accumulated provision for uncollectible accounts — customers $ 11,073 $ 21,942 $ — $ 15,153 $ 17,862 — other $ 2,523 $ 9 $ — $ 32 $ 2,500 Valuation allowance on state and local DTAs $ 26,875 $ 5,251 $ — $ — $ 32,126 (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, 2016 | |
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 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 the 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, PATH 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 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 The Utilities' principal business is providing electric service to customers in Ohio, Pennsylvania, West Virginia, New Jersey and Maryland. FES' principal business is supplying electric power to end-use customers through retail and wholesale arrangements, including affiliated company power sales to meet a portion of the POLR and default service requirements, and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. Retail customers are metered on a cycle basis. 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 (loss) 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. |
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. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant's current license, settlement based on an extended license term and expected remediation dates. 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 Long-Lived Assets 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 the changes in the carrying value of goodwill for the year ended December 31, 2016 : |
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, 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. In 2016 , 2015 and 2014 , FirstEnergy recognized $21 million , $102 million and $37 million , respectively, of OTTI. During the same periods, FES recognized OTTI of $19 million , $90 million and $33 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. |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers". Subsequent accounting standards updates have been issued which amend and/or clarify the application of ASU 2014-09. The core principle of the new guidance is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. More detailed disclosures will also be required to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, the new revenue recognition guidance will be effective for annual and interim reporting periods beginning after December 15, 2017. Earlier adoption is permitted for annual and interim reporting periods beginning after December 15, 2016. FirstEnergy will not early adopt the standards. The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy has evaluated a significant portion of its revenues and preliminarily expects limited impacts to current revenue recognition practices, dependent on the resolution of industry issues including accounting for contributions in aid of construction and the ability to recognize revenue for contracts where collectibility is in question. FirstEnergy continues to assess the remainder of its revenue streams and the impact on its financial statements and disclosures as well as which transition method it will select to adopt the guidance. On August 27, 2014, the FASB issued ASU 2014-15, "Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern." In connection with preparing financial statements for each annual and interim reporting period, the ASU requires an entity's management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures are required when management identifies conditions or events that raise substantial doubt. The new requirements were effective for the annual period ended December 31, 2016. In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption for certain provisions can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than twelve 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. 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 is currently evaluating the impact on its financial statements of adopting this standard. In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. Upon adoption, January 1, 2017, FirstEnergy elected to account for forfeitures as they occur. The adoption of the ASU did not have a material impact on FirstEnergy’s financial statements. In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”, which 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. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard. In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments". The standard is intended to eliminate diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows, including the presentation of debt prepayment or debt extinguishment costs, all of which will be classified as financing activities. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted for all entities. FirstEnergy expects to adopt this ASU in 2017 and does not expect this ASU to have a material effect on its financial statements. In October 2016, the FASB issued ASU 2016-16, " Accounting for Income Taxes: Intra-Entity Asset Transfers of Assets Other than Inventory". 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 is currently evaluating the impact on its financial statements of adopting this standard. In November 2016, the FASB issued ASU 2016-18, "Restricted Cash" that will require entities to show the changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents in the statement of cash flows. As a result, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. When cash, cash equivalents, restricted cash and restricted cash equivalents are presented in more than one line item on the balance sheet, the new guidance requires a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet. The guidance is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2019. Early adoption in an interim period is permitted, but any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. FirstEnergy does not expect this ASU to have a material effect on its financial statements. Additionally, during 2016, the FASB issued the following ASUs: • ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships,” • ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)," • ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting," and • ASU 2016-17, “Consolidation (Topic 810): Interests Held through Related Parties That Are under Common Control.” FirstEnergy does not expect these ASUs to have a material effect on its financial statements. |
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. In 2014, the qualified pension plan was amended authorizing a voluntary cashout window program for certain eligible terminated participants with vested benefits. Payment of benefits for participants that elected an immediate lump sum cash payment or an annuity resulted in a $40 million reduction to the underfunded status of the pension plan. Additionally, during 2016 and 2015, certain unions ratified their labor agreements that ended subsidized retiree health care resulting in a reduction to the OPEB benefit obligation by approximately $13 million and $10 million , respectively. 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, 2016, 2015, and 2014 were $194 million ( $147 million net of amounts capitalized), $369 million ( $242 million net of amounts capitalized), and $1,243 million ( $835 million net of amounts capitalized), respectively. In 2016, the pension and OPEB mark-to-market adjustment primarily reflects a 25 basis point decline in the discount rate, partially offset by changes in actuarial assumptions, including mortality assumptions and 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 funding obligations for future years 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. |
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. The caption "noncontrolling interest" within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. 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. |
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. |
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 the subsequent 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. |
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. |
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, less estimated forfeitures. 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 |
Organization and Basis of Pre41
Organization and Basis of Presentation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Regulatory assets on the Balance Sheets | The following table provides information about the composition of net regulatory assets as of December 31, 2016 and December 31, 2015 , and the changes during the year ended December 31, 2016 : Regulatory Assets by Source December 31, December 31, Increase (Decrease) (In millions) Regulatory transition costs $ 90 $ 185 $ (95 ) Customer receivables for future income taxes 444 355 89 Nuclear decommissioning and spent fuel disposal costs (304 ) (272 ) (32 ) Asset removal costs (470 ) (372 ) (98 ) Deferred transmission costs 127 115 12 Deferred generation costs 215 243 (28 ) Deferred distribution costs 296 335 (39 ) Contract valuations 153 186 (33 ) Storm-related costs 353 403 (50 ) Other 110 170 (60 ) Net Regulatory Assets included on the Consolidated Balance Sheets $ 1,014 $ 1,348 $ (334 ) |
Receivables from customers | Billed and unbilled customer receivables as of December 31, 2016 and 2015 are included below. Customer Receivables FirstEnergy FES (In millions) December 31, 2016 Billed $ 833 $ 123 Unbilled 607 90 Total $ 1,440 $ 213 December 31, 2015 Billed $ 836 $ 165 Unbilled 579 110 Total $ 1,415 $ 275 |
Reconciliation of basic and diluted earnings per share | The following table reconciles basic and diluted earnings (loss) per share of common stock: Reconciliation of Basic and Diluted Earnings (Loss) per Share of Common Stock 2016 2015 2014 (In millions, except per share amounts) Income (loss) from continuing operations available to common shareholders $ (6,177 ) $ 578 $ 213 Discontinued operations (Note 20) — — 86 Net income (loss) $ (6,177 ) $ 578 $ 299 Weighted average number of basic shares outstanding 426 422 420 Assumed exercise of dilutive stock options and awards (1) — 2 1 Weighted average number of diluted shares outstanding 426 424 421 Earnings (loss) per share: Basic earnings (loss) per share: Continuing operations $ (14.49 ) $ 1.37 $ 0.51 Discontinued operations (Note 20) — — 0.20 Earnings (loss) per basic share $ (14.49 ) $ 1.37 $ 0.71 Diluted earnings (loss) per share: Continuing operations $ (14.49 ) $ 1.37 $ 0.51 Discontinued operations (Note 20) — — 0.20 Earnings (loss) per diluted share $ (14.49 ) $ 1.37 $ 0.71 (1) For the year ended December 31, 2016 , approximately three million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive as a result of the net loss for the period. For the years ended December 31, 2015 and 2014, approximately one million and two million shares were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive. |
Property, plant and equipment balances | balances by segment as of December 31, 2016 and 2015 were as follows: December 31, 2016 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution (2) $ 24,979 $ (7,169 ) $ 17,810 $ 472 $ 18,282 Regulated Transmission (2) 9,342 (1,948 ) 7,394 383 7,777 Competitive Energy Services (3) 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 December 31, 2015 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total PP&E (In millions) Regulated Distribution (2) $ 24,034 $ (6,865 ) $ 17,169 $ 530 $ 17,699 Regulated Transmission (2) 8,222 (1,840 ) 6,382 484 6,866 Competitive Energy Services (3) 17,214 (6,213 ) 11,001 1,304 12,305 Corporate/Other 482 (242 ) 240 104 344 Total $ 49,952 $ (15,160 ) $ 34,792 $ 2,422 $ 37,214 (1) Includes capital leases of $244 million and $253 million at December 31, 2016 and 2015, respectively. (2) Net plant in service of $326 million as of December 31, 2015 was reclassified to conform to the current presentation reflecting the transfer of certain transmission assets from Regulated Distribution to Regulated Transmission during the fourth quarter of 2016. See "Note 19, Segment Information", for more information. (3) Primarily consists of generating assets and nuclear fuel as discussed above. Property, plant and equipment balances for FES as of December 31, 2016 and 2015 were as follows: 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 December 31, 2015 Property, Plant and Equipment In Service Accum. Depr. Net Plant CWIP Total PP&E (In millions) Fossil Generation $ 5,911 $ (1,937 ) $ 3,974 $ 218 $ 4,192 Nuclear Generation 5,617 (1,574 ) 4,043 512 4,555 Nuclear Fuel 2,616 (2,198 ) 418 283 701 Other 167 (56 ) 111 144 255 Total $ 14,311 $ (5,765 ) $ 8,546 $ 1,157 $ 9,703 |
Annual composite rates | The respective annual composite rates for FirstEnergy's and FES' electric plant in 2016 , 2015 and 2014 are shown in the following table: Annual Composite Depreciation Rate 2016 2015 2014 FirstEnergy 2.5 % 2.5 % 2.5 % FES 3.3 % 3.2 % 3.1 % |
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 the changes in the carrying value of goodwill for the year ended December 31, 2016 : Goodwill Regulated Distribution Regulated Transmission Competitive Energy Services Consolidated (In millions) Balance as of December 31, 2015 $ 5,092 $ 526 $ 800 $ 6,418 Impairment — — (800 ) (800 ) Transmission Segment (1) (88 ) 88 — — Balance as of December 31, 2016 $ 5,004 $ 614 $ — $ 5,618 (1) See Note 19, Segment Information for discussion of transfer of certain transmission assets from the Regulated Distribution segment to the Regulated Transmission segment during the fourth quarter of 2016, resulting in the transfer of $88 million of goodwill between the segments based on the relative fair value of the transmission assets to fair value of the Regulated Distribution segment. |
Asset Impairments (Tables)
Asset Impairments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Impairment Assets | 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. FE Consolidated FES Consolidated Impaired Asset Net Book Value Fair Value Impairment Net Book Value Fair Value Impairment (In millions) Coal generation assets $ 4,672 $ 614 $ 4,058 $ 3,699 $ 435 $ 3,264 Nuclear generation assets 4,842 460 4,382 4,825 460 4,365 Gas/Hydro generation assets 1,187 921 266 — — — Nuclear Fuel 703 460 243 703 460 243 Other assets (1) 382 113 269 314 104 210 Totals $ 11,786 $ 2,568 $ 9,218 $ 9,541 $ 1,459 $ 8,082 (1) Includes the impairment of materials and supplies ( $142 million ), AE Supply coal contracts ( $55 million ) and AE Supply's investment in OVEC ( $37 million ). |
Accumulated Other Comprehensi43
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Statement of Comprehensive Income [Abstract] | |
Schedule of Accumulated Other Comprehensive Income | The changes in AOCI for the years ended December 31, 2016 , 2015 and 2014 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, 2014 $ (1 ) $ 8 $ 47 $ 54 Other comprehensive income before reclassifications — 80 13 93 Amounts reclassified from AOCI (10 ) (59 ) (19 ) (88 ) Other comprehensive income (loss) (10 ) 21 (6 ) 5 Income tax (benefits) on other comprehensive income (loss) (4 ) 8 (2 ) 2 Other comprehensive income (loss), net of tax (6 ) 13 (4 ) 3 AOCI Balance, December 31, 2014 $ (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 The changes in AOCI for the years ended December 31, 2016 , 2015 and 2014 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, 2014 $ (36 ) $ 9 $ 311 $ 284 Other comprehensive income before reclassifications — 89 92 181 Amounts reclassified from AOCI (2 ) (63 ) (168 ) (233 ) Other comprehensive income (loss) (2 ) 26 (76 ) (52 ) Income tax (benefits) on other comprehensive income (loss) (1 ) 10 (23 ) (14 ) Other comprehensive income (loss), net of tax (1 ) 16 (53 ) (38 ) AOCI Balance, December 31, 2014 $ (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 |
Reclassification out of Accumulated Other Comprehensive Income | The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2016 , 2015 and 2014 : FirstEnergy Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (3 ) $ (10 ) Other operating expenses Long-term debt 8 8 8 Interest expense 8 5 (2 ) Total before taxes (3 ) (1 ) 1 Income taxes (benefits) $ 5 $ 4 $ (1 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (51 ) $ (25 ) $ (63 ) Investment income (loss) 19 9 24 Income taxes (benefits) $ (32 ) $ (16 ) $ (39 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (72 ) $ (126 ) $ (168 ) (1) 27 49 65 Income taxes (benefits) $ (45 ) $ (77 ) $ (103 ) 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 FES in the years ended December 31, 2016 , 2015 and 2014 : FES Year Ended December 31 Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (2) 2016 2015 2014 (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ (3 ) $ (10 ) Other operating expenses — 1 4 Income taxes (benefits) $ — $ (2 ) $ (6 ) Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (48 ) $ (24 ) $ (59 ) Investment income (loss) 18 9 22 Income taxes (benefits) $ (30 ) $ (15 ) $ (37 ) Net of tax Defined benefit pension and OPEB plans Prior-service costs $ (14 ) $ (16 ) $ (19 ) (1) 5 6 7 Income taxes (benefits) $ (9 ) $ (10 ) $ (12 ) 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 Postemploym44
Pension and Other Postemployment Benefits (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2016 2015 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 9,079 $ 9,249 $ 724 $ 757 Service cost 191 193 5 5 Interest cost 398 383 30 29 Plan participants’ contributions — — 5 6 Plan amendments — — (13 ) (10 ) Medicare retiree drug subsidy — — 1 1 Actuarial (gain) loss 224 (277 ) 14 (2 ) Benefits paid (466 ) (469 ) (55 ) (62 ) Benefit obligation as of December 31 $ 9,426 $ 9,079 $ 711 $ 724 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 5,338 $ 5,824 $ 431 $ 464 Actual return (losses) on plan assets 442 (178 ) 30 6 Company contributions 899 161 9 17 Plan participants’ contributions — — 5 6 Benefits paid (466 ) (469 ) (55 ) (62 ) Fair value of plan assets as of December 31 $ 6,213 $ 5,338 $ 420 $ 431 Funded Status: Qualified plan $ (2,821 ) $ (3,366 ) Non-qualified plans (392 ) (375 ) Funded Status $ (3,213 ) $ (3,741 ) $ (291 ) $ (293 ) Accumulated benefit obligation $ 8,913 $ 8,579 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ 9 $ — $ — $ — Current liabilities (19 ) (18 ) — — Noncurrent liabilities (3,203 ) (3,723 ) (291 ) (293 ) Net liability as of December 31 $ (3,213 ) $ (3,741 ) $ (291 ) $ (293 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 28 $ 37 $ (288 ) $ (355 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.25 % 4.50 % 4.00 % 4.25 % 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 2027 2026 Allocation of Plan Assets (as of December 31) Equity securities 44 % 40 % 53 % 51 % Bonds 30 % 34 % 41 % 43 % Absolute return strategies 8 % 7 % — % — % Real estate 10 % 11 % — % — % Cash and short-term securities 8 % 8 % 6 % 6 % Total 100 % 100 % 100 % 100 % |
Components of Net Periodic Benefit Costs | Pension OPEB Components of Net Periodic Benefit Costs 2016 2015 2014 2016 2015 2014 (In millions) Service cost $ 191 $ 193 $ 167 $ 5 $ 5 $ 9 Interest cost 398 383 402 30 29 39 Expected return on plan assets (399 ) (443 ) (462 ) (30 ) (33 ) (34 ) Amortization of prior service cost (credit) 8 8 8 (80 ) (134 ) (176 ) Pension & OPEB mark-to-market adjustment 179 344 1,235 15 25 8 Net periodic benefit cost (credit) $ 377 $ 485 $ 1,350 $ (60 ) $ (108 ) $ (154 ) |
Assumptions Used to Determine Net Periodic Benefit Cost | Assumptions Used to Determine Net Periodic Benefit Cost * for Years Ended December 31 Pension OPEB 2016 2015 2014 2016 2015 2014 Weighted-average discount rate 4.50 % 4.25 % 5.00 % 4.25 % 4.00 % 4.75 % Expected long-term return on plan assets 7.50 % 7.75 % 7.75 % 7.50 % 7.75 % 7.75 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A N/A |
Target asset allocations for pension and OPEB portfolio | FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2016 and 2015 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 $ 23 $ (20 ) |
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) 2016 $ 505 $ 52 $ (3 ) 2017 523 52 (3 ) 2018 534 53 (3 ) 2019 552 53 (3 ) 2020 566 53 (3 ) Years 2021-2025 2,999 251 (7 ) |
Net Pension and OPEB Asset (Liability) | FES’ share of the pension and OPEB net (liability) asset as of December 31, 2016 and 2015 , was as follows: Pension OPEB 2016 2015 2016 2015 (In millions) Net (Liability) Asset (1) $ (158 ) $ (303 ) $ 36 $ 25 |
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, 2016 was as follows: Pension OPEB 2016 2015 2014 2016 2015 2014 (In millions) Net Periodic Cost (Credit) $ (5 ) $ 10 $ 150 $ (26 ) $ (22 ) $ (24 ) |
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 2016 and 2015 . 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 (2) 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 ) — % Private equity funds — — 33 33 — % Real estate funds — — 615 615 10 % Total (1) $ 1,470 $ 4,080 $ 648 $ 6,198 100 % (1) 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. (2) 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. December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 427 $ — $ 427 8 % Equity investments Domestic 869 75 — 944 18 % International 395 794 — 1,189 22 % Fixed income Government bonds — 232 — 232 4 % Corporate bonds — 1,115 — 1,115 21 % High yield debt — 438 — 438 8 % Mortgage-backed securities (non-government) — 31 — 31 1 % Alternatives Hedge funds (Absolute return) — 343 — 343 7 % Derivatives — 15 — 15 — % Private equity funds — — 24 24 — % Real estate funds — — 587 587 11 % Total (1) $ 1,264 $ 3,470 $ 611 $ 5,345 100 % (1) Excludes $(7) million as of December 31, 2015 of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
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 2016 and 2015 : Private Equity Funds Real Estate Funds (In millions) Balance as of January 1, 2015 $ 25 $ 421 Actual return on plan assets: Unrealized gains — 42 Realized gains (losses) (1 ) 16 Transfers in — 108 Balance as of December 31, 2015 $ 24 $ 587 Actual return on plan assets: Unrealized gains 1 29 Realized gains 1 14 Transfers in (out) 7 (15 ) Balance as of December 31, 2016 $ 33 $ 615 |
OPEB | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Pension investments measured at fair value | As of December 31, 2016 and 2015 , the OPEB trust investments measured at fair value were as follows: 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 % International — — — — — % Fixed income U.S. treasuries — 40 — 40 9 % Government bonds — 108 — 108 26 % Corporate bonds — 24 — 24 6 % High yield debt — — — — — % Mortgage-backed securities (non-government) — 2 — 2 — % Alternatives Hedge funds — — — — — % Real estate funds — — — — — % 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. December 31, 2015 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 25 $ — $ 25 6 % Equity investment Domestic 219 — — 219 50 % International 1 3 — 4 1 % Fixed income U.S. treasuries — 42 — 42 10 % Government bonds — 114 — 114 26 % Corporate bonds — 27 — 27 6 % High yield debt — 1 — 1 — % Mortgage-backed securities (non-government) — 3 — 3 1 % Alternatives Hedge funds — 1 — 1 — % Real estate funds — — 2 2 — % Total (1) $ 220 $ 216 $ 2 $ 438 100 % (1) Excludes $(7) million as of December 31, 2015 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Reconciliation of changes in the fair value of pension investments | The following table provides a reconciliation of changes in the fair value of OPEB trust investments classified as Level 3 in the fair value hierarchy during 2016 and 2015 : Real Estate Funds (in millions) Balance as of January 1, 2015 $ 3 Transfers out (1 ) Balance as of December 31, 2015 $ 2 Transfers out (2 ) Balance as of December 31, 2016 $ — |
Stock-Based Compensation Plans
Stock-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 2016 2015 2014 (In millions) Restricted Stock Units $ 62 $ 46 $ 26 Restricted Stock 2 2 5 Performance Shares (3 ) — 5 401(k) Savings Plan 39 38 25 EDCP & DCPD 5 3 8 Total $ 105 $ 89 $ 69 Stock-based compensation costs capitalized $ 38 $ 32 $ 23 FES Years ended December 31 Stock-based Compensation Plan 2016 2015 2014 (In millions) Restricted Stock Units $ 11 $ 6 $ 4 Performance Shares — — 1 401(k) Savings Plan 5 5 4 Total $ 16 $ 11 $ 9 Stock-based compensation costs capitalized $ 2 $ 1 $ 1 |
Schedule of Nonvested Restricted Stock Units Activity | Restricted stock unit activity for the year ended December 31, 2016 , was as follows: Restricted Stock Unit Activity Shares Weighted-Average Grant Date Fair Value Nonvested as of January 1, 2016 2,436,888 $ 35.26 Granted in 2016 1,581,762 34.77 Forfeited in 2016 (81,618 ) 33.85 Vested in 2016 (1) (873,303 ) 33.54 Nonvested as of December 31, 2016 3,063,729 $ 32.98 (1 ) Excludes dividend equivalents of 132,360 earned during vesting period |
Restricted Stock | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Stock Option Activity | Restricted common stock (restricted stock) activity for the year ended December 31, 2016 , was as follows: Restricted Stock Number of Shares Weighted Average Grant-Date Fair Value Nonvested as of January 1, 2016 190,656 $ 40.65 Granted in 2016 28,756 32.69 Vested in 2016 (1) (82,252 ) 46.83 Nonvested as of December 31, 2016 137,160 $ 35.27 (1 ) Excludes 23,402 shares for dividends 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 2016 . Stock option activity during 2016 was as follows: Stock Option Activity Number of Shares Weighted Average Exercise Price Balance, January 1, 2016 (1,211,358 options exercisable) 1,411,971 $ 44.89 Options forfeited (35,150 ) 56.40 Balance, December 31, 2016 (1,376,821 options exercisable) 1,376,821 $ 44.60 |
Taxes (Tables)
Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Provision for income taxes (benefits) | INCOME TAXES (BENEFITS) (1) 2016 2015 2014 (In millions) FirstEnergy Currently payable (receivable)- Federal $ (1 ) $ 1 $ (132 ) State 9 30 (72 ) 8 31 (204 ) Deferred, net- Federal (3,114 ) 277 214 State 59 15 (42 ) (3,055 ) 292 172 Investment tax credit amortization (8 ) (8 ) (10 ) Total provision for income taxes (benefits) $ (3,055 ) $ 315 $ (42 ) FES Currently payable (receivable)- Federal $ (67 ) $ (56 ) $ (222 ) State (1 ) 2 (13 ) (68 ) (54 ) (235 ) Deferred, net- Federal (2,861 ) 103 25 State (57 ) 18 (14 ) (2,918 ) 121 11 Investment tax credit amortization (2 ) (2 ) (4 ) Total provision for income taxes (benefits) $ (2,988 ) $ 65 $ (228 ) (1) Provision for Income Taxes (Benefits) on Income from Continuing Operations. Currently payable (receivable) in 2014 excludes $106 million and $12 million of federal and state taxes, respectively, associated with discontinued operations. Deferred, net in 2014 excludes $44 million and $5 million of federal and state tax benefits, respectively, associated with discontinued operations. |
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 at the federal statutory rate to the total income taxes on continuing operations for the three years ended December 31: 2016 2015 2014 (In millions) FirstEnergy Income (loss) from Continuing Operations before income taxes (benefits) $ (9,232 ) $ 893 $ 171 Federal income tax expense (benefit) at statutory rate (35%) $ (3,231 ) $ 313 $ 60 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (192 ) 17 (21 ) AFUDC equity and other flow-through (13 ) (16 ) (13 ) Amortization of investment tax credits (8 ) (8 ) (10 ) Change in accounting method — (8 ) (27 ) ESOP dividend (6 ) (6 ) (6 ) Impairment of non-deductible goodwill 157 — — Tax basis balance sheet adjustments — — (25 ) Uncertain tax positions (16 ) 1 (35 ) Valuation allowances 246 18 33 Other, net 8 4 2 Total income taxes (benefits) $ (3,055 ) $ 315 $ (42 ) Effective income tax rate 33.1 % 35.3 % (24.6 )% FES Income (loss) from Continuing Operations before income taxes (benefits) $ (8,444 ) $ 147 $ (588 ) Federal income tax expense (benefit) at statutory rate (35%) $ (2,955 ) $ 51 $ (206 ) Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit (188 ) 2 (28 ) Amortization of investment tax credits (2 ) (2 ) (4 ) ESOP dividend (1 ) (1 ) (1 ) Impairment of non-deductible goodwill 9 — — Uncertain tax positions (8 ) 5 — Valuation allowances 151 14 14 Other, net 6 (4 ) (3 ) Total income taxes (benefits) $ (2,988 ) $ 65 $ (228 ) Effective income tax rate 35.4 % 44.2 % 38.8 % |
Accumulated deferred income taxes | Accumulated deferred income taxes as of December 31, 2016 and 2015 are as follows: 2016 2015 (In millions) FirstEnergy Property basis differences $ 7,088 $ 9,920 Deferred sale and leaseback gain (351 ) (360 ) Pension and OPEB (1,347 ) (1,541 ) Nuclear decommissioning activities 635 480 Asset retirement obligations (669 ) (731 ) Regulatory asset/liability 545 763 Deferred compensation (269 ) (239 ) Loss carryforwards and AMT credits (2,251 ) (1,965 ) Valuation reserve 438 192 All other (54 ) 254 Net deferred income tax liability $ 3,765 $ 6,773 FES Property basis differences $ (1,009 ) $ 1,901 Deferred sale and leaseback gain (328 ) (342 ) Pension and OPEB (366 ) (393 ) Lease market valuation liability 111 95 Nuclear decommissioning activities 540 483 Asset retirement obligations (453 ) (509 ) Loss carryforwards and AMT credits (830 ) (687 ) Valuation reserve 197 46 All other (141 ) 6 Net deferred income tax liability (asset) $ (2,279 ) $ 600 |
Pre-tax net operating loss expiration period | Expiration Period FirstEnergy FES (In millions) State Local State Local 2017-2021 $ 166 $ 2,998 $ 2 $ 1,795 2022-2026 1,327 — — — 2027-2031 2,817 — 410 — 2032-2036 2,752 — 1,172 — $ 7,062 $ 2,998 $ 1,584 $ 1,795 |
Changes in unrecognized tax benefits | The following table summarizes the changes in unrecognized tax positions for the years ended 2016 , 2015 and 2014 : FirstEnergy FES (In millions) Balance, January 1, 2014 $ 48 $ 3 Current year increases 4 — Prior years increases 5 — Prior years decreases (23 ) — Balance, December 31, 2014 $ 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 $ — |
Details of general taxes | General Taxes General tax expense for 2016 , 2015 and 2014 , is summarized as follows: 2016 2015 2014 (In millions) FirstEnergy KWH excise $ 196 $ 193 $ 194 State gross receipts 212 224 226 Real and personal property 472 410 393 Social security and unemployment 127 119 112 Other 35 32 37 Total general taxes $ 1,042 $ 978 $ 962 FES State gross receipts $ 28 $ 44 $ 69 Real and personal property 42 36 39 Social security and unemployment 15 16 17 Other 3 2 3 Total general taxes $ 88 $ 98 $ 128 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Leases [Abstract] | |
Rentals for capital and operating leases | Operating lease expense for 2016 , 2015 and 2014 , is summarized as follows: (In millions) 2016 2015 2014 FirstEnergy $ 168 $ 174 $ 199 FES $ 94 $ 94 $ 95 |
Future minimum capital lease payments | The future minimum capital lease payments as of December 31, 2016 are as follows: Capital leases FirstEnergy FES (In millions) 2017 $ 32 $ 6 2018 25 2 2019 19 — 2020 14 — 2021 12 — Years thereafter 15 1 Total minimum lease payments 117 9 Interest portion (13 ) (1 ) Present value of net minimum lease payments 104 8 Less current portion 29 5 Noncurrent portion $ 75 $ 3 |
Future minimum operating lease payments | FirstEnergy's future minimum consolidated operating lease payments as of December 31, 2016 , are as follows: Operating Leases FirstEnergy (In millions) 2017 (1) $ 125 2018 142 2019 123 2020 97 2021 119 Years thereafter 1,351 Total minimum lease payments $ 1,957 (1) Includes a $3 million payment PNBV Trust will receive associated with certain sale and leaseback transactions. These arrangements, which expire in 2017, effectively reduce lease costs related to those transactions. FES' future minimum operating lease payments as of December 31, 2016 , are as follows: Operating Leases FES (In millions) 2017 $ 82 2018 101 2019 97 2020 68 2021 93 Years thereafter 1,222 Total minimum lease payments $ 1,663 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Future Amortization | As of December 31, 2016 , intangible assets classified in Customer Intangibles and Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheet, include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2016 2017 2018 2019 2020 2021 Thereafter NUG contracts (1) $ 124 $ 31 $ 93 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 68 OVEC (2) 54 48 6 2 1 1 — — — 4 Coal contracts (2)(3)(4) 556 544 12 55 — — — — — — FES customer contracts (5) 148 139 9 52 5 3 1 — — — $ 882 $ 762 $ 120 $ 114 $ 11 $ 9 $ 6 $ 5 $ 5 $ 72 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) Amortization expense excludes impairment charges related to intangible assets recognized in 2016, which totaled $92 million and are included in Impairment of Assets. See "Note 2, Asset Impairments" for further discussion. (3) The coal contracts were recorded with a regulatory offset and the amortization does not impact earnings. Accordingly, the amortization expense for these coal contracts is excluded from table above. (4) A gross amount of $40 million of coal contracts is related to FES. In June 2016, FES terminated a coal contract and the write-off is included in amortization expense in the table above. (5) During 2016, FES recorded a pre-tax charge of $37 million associated with the termination of a customer contract, which is included in amortization expense in the table above. |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Variable Interest Entities [Abstract] | |
Net exposure to loss based upon the casualty value provisions | The following table discloses each company’s net exposure to loss based upon the casualty value provisions as of December 31, 2016 : Maximum Exposure Discounted Lease Payments, net Net Exposure (In millions) FirstEnergy $ 1,123 $ 879 $ 244 FES $ 1,098 $ 875 $ 223 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 1,247 $ — $ 1,247 $ — $ 1,245 $ — $ 1,245 Derivative assets - commodity contracts 10 200 — 210 4 224 — 228 Derivative assets - FTRs — — 7 7 — — 8 8 Derivative assets - NUG contracts (1) — — 1 1 — — 1 1 Equity securities (2) 925 — — 925 576 — — 576 Foreign government debt securities — 78 — 78 — 75 — 75 U.S. government debt securities — 161 — 161 — 180 — 180 U.S. state debt securities — 246 — 246 — 246 — 246 Other (3) 199 123 — 322 105 212 — 317 Total assets $ 1,134 $ 2,055 $ 8 $ 3,197 $ 685 $ 2,182 $ 9 $ 2,876 Liabilities Derivative liabilities - commodity contracts $ (6 ) $ (118 ) $ — $ (124 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (6 ) (6 ) — — (13 ) (13 ) Derivative liabilities - NUG contracts (1) — — (108 ) (108 ) — — (137 ) (137 ) Total liabilities $ (6 ) $ (118 ) $ (114 ) $ (238 ) $ (9 ) $ (122 ) $ (150 ) $ (281 ) Net assets (liabilities) (4) $ 1,128 $ 1,937 $ (106 ) $ 2,959 $ 676 $ 2,060 $ (141 ) $ 2,595 (1) NUG contracts are subject to regulatory accounting treatment and 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 cash and short-term cash investments. (4) Excludes $(3) million and $7 million as of December 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : NUG Contracts (1) FTRs Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2015 Balance $ 2 $ (153 ) $ (151 ) $ 39 $ (14 ) $ 25 Unrealized gain (loss) 2 (49 ) (47 ) (5 ) (7 ) (12 ) Purchases — — — 22 (11 ) 11 Settlements (3 ) 65 62 (48 ) 19 (29 ) December 31, 2015 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 (1) NUG contracts are subject to regulatory accounting treatment and 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, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 1 Model RTO auction clearing prices ($4.20) to $6.10 $0.80 Dollars/MWH NUG Contracts $ (107 ) Model Generation 400 to 2,984,000 $32.60 to $33.40 754,000 $32.80 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, 2016 and December 31, 2015 : December 31, 2016 (1) December 31, 2015 (2) Cost Basis Unrealized Gains Fair Value Cost Basis Unrealized Gains Fair Value (In millions) Debt securities FirstEnergy $ 1,735 $ 38 $ 1,773 $ 1,778 $ 16 $ 1,794 FES 847 27 874 801 9 810 Equity securities FirstEnergy $ 822 $ 103 $ 925 $ 542 $ 34 $ 576 FES 564 70 634 354 24 378 (1) Excludes short-term cash investments: FirstEnergy - $61 million ; FES - $44 million . (2) Excludes short-term cash investments: FirstEnergy - $157 million ; FES - $139 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, 2016 , 2015 and 2014 were as follows: 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 December 31, 2014 Sale Proceeds Realized Gains Realized Losses OTTI Interest and Dividend Income (In millions) FirstEnergy $ 2,133 $ 146 $ (75 ) $ (37 ) $ 96 FES 1,163 113 (54 ) (33 ) 56 |
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, 2016 December 31, 2015 Carrying Value Fair Value Carrying Value Fair Value (In millions) FirstEnergy $ 19,885 $ 19,829 $ 20,244 $ 21,519 FES 3,000 1,555 3,027 3,121 |
FES | |
Fair Value of Financial Instruments [Line Items] | |
Assets and liabilities measured on recurring basis | FES Recurring Fair Value Measurements December 31, 2016 December 31, 2015 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 726 $ — $ 726 $ — $ 678 $ — $ 678 Derivative assets - commodity contracts 10 200 — 210 4 224 — 228 Derivative assets - FTRs — — 4 4 — — 5 5 Equity securities (1) 634 — — 634 378 — — 378 Foreign government debt securities — 58 — 58 — 59 — 59 U.S. government debt securities — 48 — 48 — 23 — 23 U.S. state debt securities — 3 — 3 — 4 — 4 Other (2) 2 81 — 83 — 184 — 184 Total assets $ 646 $ 1,116 $ 4 $ 1,766 $ 382 $ 1,172 $ 5 $ 1,559 Liabilities Derivative liabilities - commodity contracts $ (6 ) $ (118 ) $ — $ (124 ) $ (9 ) $ (122 ) $ — $ (131 ) Derivative liabilities - FTRs — — (5 ) (5 ) — — (11 ) (11 ) Total liabilities $ (6 ) $ (118 ) $ (5 ) $ (129 ) $ (9 ) $ (122 ) $ (11 ) $ (142 ) Net assets (liabilities) (3) $ 640 $ 998 $ (1 ) $ 1,637 $ 373 $ 1,050 $ (6 ) $ 1,417 (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 $2 million and $1 million as of December 31, 2016 and December 31, 2015 , 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, 2016 and December 31, 2015 : Derivative Asset Derivative Liability Net Asset/(Liability) (In millions) January 1, 2015 Balance $ 27 $ (13 ) $ 14 Unrealized gain (loss) 2 (5 ) (3 ) Purchases 9 (10 ) (1 ) Settlements (33 ) 17 (16 ) December 31, 2015 Balance $ 5 $ (11 ) $ (6 ) Unrealized loss (4 ) (3 ) (7 ) Purchases 10 (5 ) 5 Settlements (7 ) 14 7 December 31, 2016 Balance $ 4 $ (5 ) $ (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, 2016 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ (1 ) Model RTO auction clearing prices ($4.20) to $5.30 $0.60 Dollars/MWH |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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 - Derivatives Commodity Contracts $ 133 $ 150 Commodity Contracts $ (72 ) $ (94 ) FTRs 7 7 FTRs (6 ) (12 ) 140 157 (78 ) (106 ) Noncurrent Liabilities - Adverse Power Contract Liability Deferred Charges and Other Assets - Other NUGs (1) (108 ) (137 ) Commodity Contracts 77 78 Noncurrent Liabilities - Other FTRs — 1 Commodity Contracts (52 ) (37 ) NUGs (1) 1 1 FTRs — (1 ) 78 80 (160 ) (175 ) Derivative Assets $ 218 $ 237 Derivative Liabilities $ (238 ) $ (281 ) (1) NUG contracts are subject to regulatory accounting treatment and 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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) |
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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 8 (8 ) — — NUG contracts 1 — — 1 $ 237 $ (133 ) $ — $ 104 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (13 ) 8 5 — NUG contracts (137 ) — — (137 ) $ (281 ) $ 133 $ 8 $ (140 ) |
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, 2016 : Purchases Sales Net Units (In millions) Power Contracts 18 47 (29 ) MWH FTRs 28 — 28 MWH NUGs 3 — 3 MWH Natural Gas 29 29 — mmBTU The following table summarizes the volumes associated with FES' outstanding derivative transactions as of December 31, 2016 : Purchases Sales Net Units (In millions) Power Contracts 18 47 (29 ) MWH FTRs 22 — 22 MWH Natural Gas 29 29 — mmBTU |
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 2016 , 2015 and 2014 are summarized in the following tables: Year Ended December 31 Commodity Contracts 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 ) Year Ended December 31 Commodity FTRs Interest Rate Swaps Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (86 ) $ 22 $ — $ (64 ) Realized Gain (Loss) Reclassified to: Revenues $ (6 ) $ 68 $ — $ 62 Purchased Power Expense 365 — — 365 Other Operating Expense — (44 ) — (44 ) Fuel Expense (6 ) — — (6 ) Interest Expense — — 14 14 |
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 2016 and 2015 . 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, 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 ) Outstanding net asset (liability) as of January 1, 2015 $ (151 ) $ 11 $ (140 ) Unrealized loss (47 ) (9 ) (56 ) Purchases — 12 12 Settlements 62 (13 ) 49 Outstanding net asset (liability) as of December 31, 2015 $ (136 ) $ 1 $ (135 ) |
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 $ 133 $ 150 Commodity Contracts $ (72 ) $ (94 ) FTRs 4 4 FTRs (5 ) (10 ) 137 154 (77 ) (104 ) Deferred Charges and Other Assets - Other Noncurrent Liabilities - Other Commodity Contracts 77 78 Commodity Contracts (52 ) (37 ) FTRs — 1 FTRs — (1 ) 77 79 (52 ) (38 ) Derivative Assets $ 214 $ 233 Derivative Liabilities $ (129 ) $ (142 ) |
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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 5 (5 ) — — $ 233 $ (130 ) $ — $ 103 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (11 ) 5 6 — $ (142 ) $ 130 $ 9 $ (3 ) |
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, 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 ) Amounts Not Offset in Consolidated Balance Sheet December 31, 2015 Fair Value Derivative Instruments Cash Collateral (Received)/Pledged Net Fair Value (In millions) Derivative Assets Commodity contracts $ 228 $ (125 ) $ — $ 103 FTRs 5 (5 ) — — $ 233 $ (130 ) $ — $ 103 Derivative Liabilities Commodity contracts $ (131 ) $ 125 $ 3 $ (3 ) FTRs (11 ) 5 6 — $ (142 ) $ 130 $ 9 $ (3 ) |
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 2016 , 2015 and 2014 are summarized in the following tables: Year Ended December 31 Commodity Contracts 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 ) Year Ended December 31 Commodity FTRs Total (In millions) 2014 Unrealized Gain (Loss) Recognized in: Other Operating Expense $ (86 ) $ 21 $ (65 ) Realized Gain (Loss) Reclassified to: Revenues $ (6 ) $ 67 $ 61 Purchased Power Expense 365 — 365 Other Operating Expense — (43 ) (43 ) |
Capitalization (Tables)
Capitalization (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 , 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, 2016 and 2015 : As of December 31, 2016 As of December 31 (Dollar amounts in millions) Maturity Date Interest Rate 2016 2015 FirstEnergy: FMBs 2017 - 2056 3.340% - 9.740% $ 3,328 $ 3,269 Secured notes - fixed rate 2017 - 2037 0.679% - 12.000% 2,295 2,096 Secured notes - variable rate 2017 3.500% 10 2 Total secured notes 2,305 2,098 Unsecured notes - fixed rate 2017 - 2045 2.150% - 7.700% 13,058 13,580 Unsecured notes - variable rate 2021 2.430% 1,200 1,292 Total unsecured notes 14,258 14,872 Capital lease obligations 104 132 Unamortized debt discounts (25 ) (18 ) Unamortized debt issuance costs (87 ) (93 ) Unamortized fair value adjustments (6 ) 5 Currently payable long-term debt (1,685 ) (1,166 ) Total long-term debt and other long-term obligations $ 18,192 $ 19,099 FES: Secured notes - fixed rate 2017 - 2022 4.250% - 12.000% $ 617 $ 340 Secured notes - variable rate 2017 3.500% 10 2 Total secured notes 627 342 Unsecured notes - fixed rate 2017 - 2039 2.150% - 6.800% 2,373 2,593 Unsecured notes - variable rate — 92 Total unsecured notes 2,373 2,685 Capital lease obligations 8 13 Unamortized debt discounts (1 ) (1 ) Unamortized debt issuance costs (15 ) (17 ) Currently payable long-term debt (179 ) (512 ) Total long-term debt and other long-term obligations $ 2,813 $ 2,510 |
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, 2016 . 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) 2017 $ 1,641 $ 163 2018 1,702 516 2019 2,266 478 2020 1,231 667 2021 832 774 |
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) 2017 $ 130 $ 130 2018 375 375 2019 232 232 2020 490 490 2021 342 342 |
Short-Term Borrowings and Ban53
Short-Term Borrowings and Bank Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Short-term Debt [Line Items] | |
Liquidity | FirstEnergy’s available liquidity from external sources as of January 31, 2017 was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2021 $ 4,000 $ 1,341 FET (2) Revolving December 2021 1,000 1,000 Subtotal $ 5,000 $ 2,341 Cash — 308 Total $ 5,000 $ 2,649 (1) FE and the Utilities. (2) Includes FET, ATSI 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 December 31, 2016 : Borrower 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 500 500 (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)(3) (1) No limitations. (2) Excluding 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, 2016 and 2015 , were as follows: 2016 2015 FirstEnergy 2.47 % 2.16 % |
FES | |
Short-term Debt [Line Items] | |
Liquidity | FES had $101 million (payable to AE Supply) and $8 million of short-term borrowings as of December 31, 2016 and 2015, respectively. FES' available liquidity as of January 31, 2017 was as follows: Type Commitment Available Liquidity (In millions) Two-year secured credit facility with FE $ 500 $ 500 Cash — 2 $ 500 $ 502 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | |
Fair values of the decommissioning trust assets | The fair values of the decommissioning trust assets as of December 31, 2016 and 2015 were as follows: 2016 2015 (In millions) FirstEnergy $ 2,514 $ 2,282 FES $ 1,552 $ 1,327 |
Changes to the asset retirement obligations | The following table summarizes the changes to the ARO balances during 2016 and 2015 : ARO Reconciliation FirstEnergy FES (In millions) Balance, January 1, 2015 $ 1,387 $ 841 Liabilities settled (13 ) (8 ) Accretion 92 55 Revisions in estimated cash flows (56 ) (57 ) Balance, December 31, 2015 $ 1,410 $ 831 Liabilities settled (27 ) (18 ) Accretion 95 56 Liabilities Incurred 4 32 Balance, December 31, 2016 $ 1,482 $ 901 |
Commitments, Guarantees and C55
Commitments, Guarantees and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 : Potential Additional Collateral Obligations FES AE Supply Regulated Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 7 $ 3 $ — $ 10 Upon Further Downgrade — — 48 48 Surety Bonds (Collateralized Amount) (1) 240 25 102 367 Total Exposure from Contractual Obligations $ 247 $ 28 $ 150 $ 425 (1) Effective January 2017, FE is a guarantor for $169 million of FG surety bonds for the benefit of the PA DEP with respect to LBR. |
Transactions With Affiliated 56
Transactions With Affiliated Companies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Transactions With Affiliated Companies [Abstract] | |
Affiliated Company Transactions | The primary affiliated company transactions for FES during the three years ended December 31, 2016 are as follows: FES 2016 2015 2014 (In millions) Revenues: Electric sales to affiliates $ 457 $ 664 $ 861 Other 11 14 15 Expenses: Purchased power from affiliates 622 353 271 Fuel 4 1 1 Support services 748 705 619 Investment Income: Interest income from FE 2 2 3 Interest Expense: Interest expense to affiliates 5 4 3 Interest expense to FE 2 3 4 |
Supplemental Guarantor Inform57
Supplemental Guarantor Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Guarantor Information [Abstract] | |
Condensed Consolidating Statements of Income (Loss) and Comprehensive Income (Loss) | 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 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 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 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 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 STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) STATEMENTS OF INCOME (LOSS) REVENUES $ 5,990 $ 1,902 $ 2,172 $ (3,920 ) $ 6,144 OPERATING EXPENSES: Fuel — 1,055 198 — 1,253 Purchased power from affiliates 3,920 — 271 (3,920 ) 271 Purchased power from non-affiliates 2,767 4 — — 2,771 Other operating expenses 790 269 527 49 1,635 Pension and OPEB mark-to-market adjustment 19 90 188 — 297 Provision for depreciation 10 119 193 (3 ) 319 General taxes 72 31 25 — 128 Total operating expenses 7,578 1,568 1,402 (3,874 ) 6,674 OPERATING INCOME (LOSS) (1,588 ) 334 770 (46 ) (530 ) OTHER INCOME (EXPENSE): Investment income, including net income from equity investees 791 8 61 (799 ) 61 Miscellaneous income 2 4 — — 6 Interest expense — affiliates (12 ) (6 ) (4 ) 15 (7 ) Interest expense — other (56 ) (102 ) (54 ) 60 (152 ) Capitalized interest — 4 30 — 34 Total other income (expense) 725 (92 ) 33 (724 ) (58 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) (863 ) 242 803 (770 ) (588 ) INCOME TAXES (BENEFITS) (619 ) 87 298 6 (228 ) INCOME (LOSS) FROM CONTINUING OPERATIONS (244 ) 155 505 (776 ) (360 ) Discontinued operations (net of income taxes of $8) — 116 — — 116 NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) STATEMENTS OF COMPREHENSIVE INCOME (LOSS) NET INCOME (LOSS) $ (244 ) $ 271 $ 505 $ (776 ) $ (244 ) OTHER COMPREHENSIVE INCOME (LOSS): Pension and OPEB prior service costs (6 ) (5 ) — 5 (6 ) Amortized gain on derivative hedges (10 ) — — — (10 ) Change in unrealized gain on available-for-sale securities 21 — 21 (21 ) 21 Other comprehensive income (loss) 5 (5 ) 21 (16 ) 5 Income taxes (benefits) on other comprehensive income (loss ) 2 (2 ) 8 (6 ) 2 Other comprehensive income (loss), net of tax 3 (3 ) 13 (10 ) 3 COMPREHENSIVE INCOME (LOSS) $ (241 ) $ 268 $ 518 $ (786 ) $ (241 ) |
Condensed Consolidating Balance Sheets | 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 Prepayments 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 Customer intangibles 9 — — — 9 Property taxes — 12 28 — 40 Derivatives 77 — — — 77 Other 24 327 — 21 372 505 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 Other — — — — — 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 Accumulated deferred income taxes 4 3 — (7 ) — Retirement benefits 25 172 — — 197 Asset retirement obligations — 188 713 — 901 Derivatives 52 — — — 52 Other 42 85 860 — 987 123 448 1,573 750 2,894 $ 4,938 $ 4,360 $ 5,181 $ (7,238 ) $ 7,241 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING BALANCE SHEETS As of December 31, 2015 FES FG NG Eliminations Consolidated (In millions) ASSETS CURRENT ASSETS: Cash and cash equivalents $ — $ 2 $ — $ — $ 2 Receivables- Customers 275 — — — 275 Affiliated companies 433 403 461 (846 ) 451 Other 36 4 19 — 59 Notes receivable from affiliated companies 406 1,210 805 (2,410 ) 11 Materials and supplies 53 204 213 — 470 Derivatives 154 — — — 154 Collateral 70 — — — 70 Prepayments and other 48 18 — — 66 1,475 1,841 1,498 (3,256 ) 1,558 PROPERTY, PLANT AND EQUIPMENT: In service 93 6,367 8,233 (382 ) 14,311 Less — Accumulated provision for depreciation 40 2,144 3,775 (194 ) 5,765 53 4,223 4,458 (188 ) 8,546 Construction work in progress 30 249 878 — 1,157 83 4,472 5,336 (188 ) 9,703 INVESTMENTS: Nuclear plant decommissioning trusts — — 1,327 — 1,327 Investment in affiliated companies 7,452 — — (7,452 ) — Other — 10 — — 10 7,452 10 1,327 (7,452 ) 1,337 DEFERRED CHARGES AND OTHER ASSETS: Accumulated deferred income tax benefits 300 16 — (316 ) — Customer intangibles 61 — — — 61 Goodwill 23 — — — 23 Property taxes — 12 28 — 40 Derivatives 79 — — — 79 Other 29 312 14 12 367 492 340 42 (304 ) 570 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES: Currently payable long-term debt $ — $ 229 $ 308 $ (25 ) $ 512 Short-term borrowings- Affiliated companies 2,021 389 — (2,410 ) — Other — 8 — — 8 Accounts payable- Affiliated companies 884 146 368 (856 ) 542 Other 21 118 — — 139 Accrued taxes 7 93 62 (86 ) 76 Derivatives 103 1 — — 104 Other 66 61 9 45 181 3,102 1,045 747 (3,332 ) 1,562 CAPITALIZATION: Total equity 5,605 2,944 4,476 (7,420 ) 5,605 Long-term debt and other long-term obligations 690 2,116 840 (1,136 ) 2,510 6,295 5,060 5,316 (8,556 ) 8,115 NONCURRENT LIABILITIES: Deferred gain on sale and leaseback transaction — — — 791 791 Accumulated deferred income taxes 6 — 697 (103 ) 600 Retirement benefits 27 305 — — 332 Asset retirement obligations — 191 640 — 831 Derivatives 37 1 — — 38 Other 35 61 803 — 899 105 558 2,140 688 3,491 $ 9,502 $ 6,663 $ 8,203 $ (11,200 ) $ 13,168 |
Condensed Consolidating Statements of Cash Flows | 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 ) $ 549 $ 1,103 $ (25 ) $ 785 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 — (6 ) (2 ) — (8 ) Net cash provided from (used for) financing activities 948 50 (25 ) (916 ) 57 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 ) $ 551 $ 1,261 $ (24 ) $ 1,151 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 — (5 ) (1 ) — (6 ) Net cash provided from (used for) financing activities 709 37 (81 ) (937 ) (272 ) 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 FIRSTENERGY SOLUTIONS CORP. CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2014 FES FG NG Eliminations Consolidated (In millions) NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES $ (600 ) $ 408 $ 785 $ (22 ) $ 571 CASH FLOWS FROM FINANCING ACTIVITIES: New Financing- Long-term debt — 431 447 — 878 Short-term borrowings, net 247 114 — (361 ) — Equity contribution from parent 500 — — — 500 Redemptions and Repayments- Long-term debt (1 ) (269 ) (568 ) 22 (816 ) Short-term borrowings, net — — (123 ) (178 ) (301 ) Other (1 ) (12 ) (2 ) — (15 ) Net cash provided from (used for) financing activities 745 264 (246 ) (517 ) 246 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (8 ) (169 ) (662 ) — (839 ) Nuclear fuel — — (233 ) — (233 ) Proceeds from asset sales — 307 — — 307 Sales of investment securities held in trusts — — 1,163 — 1,163 Purchases of investment securities held in trusts — — (1,219 ) — (1,219 ) Loans to affiliated companies, net (136 ) (815 ) 412 539 — Other (1 ) 5 — — 4 Net cash used for investing activities (145 ) (672 ) (539 ) 539 (817 ) 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, 2016 | |
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) 2016 External revenues $ 9,629 $ 1,151 $ 4,070 $ — $ (288 ) $ 14,562 Internal revenues — — 479 — (479 ) — Total revenues 9,629 1,151 4,549 — (767 ) 14,562 Depreciation 676 187 387 63 — 1,313 Amortization of regulatory assets, net 313 7 — — — 320 Impairment of assets — — 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 ) (121 ) 2 (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 $ 1,054 $ 4,698 $ — $ (308 ) $ 15,026 Internal revenues — — 686 — (686 ) — Total revenues 9,582 1,054 5,384 — (994 ) 15,026 Depreciation 664 164 394 60 — 1,282 Amortization of regulatory assets, net 261 7 — — — 268 Impairment of assets 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 (262 ) 11 315 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 2014 External revenues $ 9,054 $ 817 $ 5,470 $ — $ (292 ) $ 15,049 Internal revenues — — 819 — (819 ) — Total revenues 9,054 817 6,289 — (1,111 ) 15,049 Depreciation 651 134 387 48 — 1,220 Amortization of regulatory assets, net 1 11 — — — 12 Investment income 56 — 54 2 (40 ) 72 Interest expense 603 117 197 168 (4 ) 1,081 Income taxes (benefits) 209 139 (223 ) (178 ) 11 (42 ) Income (loss) from continuing operations 433 255 (417 ) (58 ) — 213 Discontinued operations, net of tax — — 86 — — 86 Net income (loss) 433 255 (331 ) (58 ) — 299 Total assets 27,332 6,864 16,180 1,176 — 51,552 Total goodwill 5,092 526 800 — — 6,418 Property additions 855 1,446 939 72 — 3,312 |
Summary of Quarterly Financia59
Summary of Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Data [Abstract] | |
Schedule of Quarterly Financial Information | The following summarizes certain consolidated operating results by quarter for 2016 and 2015 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2016 2015 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 3,375 $ 3,917 $ 3,401 $ 3,869 $ 3,541 $ 4,123 $ 3,465 $ 3,897 Other operating expense 1,023 953 964 918 950 842 900 1,057 Pension and OPEB mark-to-market adjustment 147 — — — 242 — — — Provision for depreciation 339 311 334 329 313 328 322 319 Impairment of assets 9,218 — 1,447 — 18 8 16 — Operating Income (Loss) (8,924 ) 861 (975 ) 776 236 908 554 594 Income (loss) before income taxes (benefits) (9,185 ) 631 (1,219 ) 541 (396 ) 621 302 366 Income taxes (benefits) (3,389 ) 251 (130 ) 213 (170 ) 226 115 144 Net Income (Loss) (5,796 ) 380 (1,089 ) 328 (226 ) 395 187 222 Earnings (loss) per share of common stock- (1) Basic - Earnings (losses) Available to FirstEnergy Corp. (13.44 ) 0.89 (2.56 ) 0.78 (0.53 ) 0.94 0.44 0.53 Diluted - Earnings (losses) Available to FirstEnergy Corp. (13.44 ) 0.89 (2.56 ) 0.77 (0.53 ) 0.93 0.44 0.53 (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 and the $500 million equity issuance in December 2016. See FirstEnergy's Consolidated Statements of Stockholders' Equity, "Note 5, Stock-Based Compensation Plans" and "Note 12, Capitalization" for additional information. FES CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions) 2016 2015 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Revenues $ 997 $ 1,100 $ 1,102 $ 1,199 $ 1,171 $ 1,338 $ 1,119 $ 1,377 Other operating expense 352 316 369 240 312 246 337 413 Pension and OPEB mark-to-market adjustment 48 — — — 57 — — — Provision for depreciation 86 83 84 83 84 79 81 80 Impairment of assets 8,082 — 540 — 17 — 16 — Operating Income (Loss) (8,153 ) 101 (571 ) 226 25 240 — 12 Income (loss) from continuing operations before income taxes (benefits) (8,171 ) 96 (581 ) 213 (13 ) 190 (25 ) (5 ) Income taxes (benefits) (2,983 ) 56 (143 ) 82 1 70 (4 ) (2 ) Net Income (Loss) (5,188 ) 40 (438 ) 131 (14 ) 120 (21 ) (3 ) |
Organization and Basis of Pre60
Organization and Basis of Presentation (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | $ 1,014 | $ 1,348 |
Regulatory Liability | (157) | (116) |
Increase (Decrease) | (334) | |
Regulatory transition costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 90 | 185 |
Increase (Decrease) | (95) | |
Customer receivables for future income taxes | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 444 | 355 |
Increase (Decrease) | 89 | |
Nuclear decommissioning and spent fuel disposal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (304) | (272) |
Increase (Decrease) | (32) | |
Asset removal costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Liability | (470) | (372) |
Increase (Decrease) | (98) | |
Deferred transmission costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 127 | 115 |
Increase (Decrease) | 12 | |
Deferred generation costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 215 | 243 |
Increase (Decrease) | (28) | |
Deferred distribution costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 296 | 335 |
Increase (Decrease) | (39) | |
Contract valuations | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 153 | 186 |
Increase (Decrease) | (33) | |
Storm-related costs | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 353 | 403 |
Increase (Decrease) | (50) | |
Other | ||
Regulatory assets on the Balance Sheets | ||
Regulatory Assets | 110 | $ 170 |
Increase (Decrease) | $ (60) |
Organization and Basis of Pre61
Organization and Basis of Presentation (Details 1) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Receivables from customers | ||
Customers | $ 1,440 | $ 1,415 |
FES | ||
Receivables from customers | ||
Customers | 213 | 275 |
Billed | ||
Receivables from customers | ||
Customers | 833 | 836 |
Billed | FES | ||
Receivables from customers | ||
Customers | 123 | 165 |
Unbilled | ||
Receivables from customers | ||
Customers | 607 | 579 |
Unbilled | FES | ||
Receivables from customers | ||
Customers | $ 90 | $ 110 |
Organization and Basis of Pre62
Organization and Basis of Presentation (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of Basic and Diluted Earnings per Share of Common Stock | |||||||||||
Income (loss) from continuing operations | $ (6,177) | $ 578 | $ 213 | ||||||||
Discontinued operations, net of tax | 0 | 0 | 86 | ||||||||
Net income (loss) | $ (6,177) | $ 578 | $ 299 | ||||||||
Weighted average number of basic shares outstanding | 426 | 422 | 420 | ||||||||
Assumed exercise of dilutive stock options and awards (in shares) | 0 | 2 | 1 | ||||||||
Weighted average number of diluted shares outstanding | 426 | 424 | 421 | ||||||||
Earnings (loss) per share: | |||||||||||
Basic - Continuing Operations, in dollars per share | $ (14.49) | $ 1.37 | $ 0.51 | ||||||||
Basic - Discontinued Operations, in dollars per share | 0 | 0 | 0.20 | ||||||||
Basic - Net Income (Loss), in dollars per share | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.78 | $ (0.53) | $ 0.94 | $ 0.44 | $ 0.53 | (14.49) | 1.37 | 0.71 |
Diluted earnings (loss) per share: | |||||||||||
Diluted - Continuing Operations, in dollars per share | (14.49) | 1.37 | 0.51 | ||||||||
Diluted - Discontinued Operations, in dollars per share | 0 | 0 | 0.20 | ||||||||
Diluted - Net Income (Loss), in dollars per share | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.77 | $ (0.53) | $ 0.93 | $ 0.44 | $ 0.53 | $ (14.49) | $ 1.37 | $ 0.71 |
Shares excluded from the calculation of diluted shares outstanding, in shares | 3 | 1 | 2 |
Organization and Basis of Pre63
Organization and Basis of Presentation (Details 3) - USD ($) $ in Millions | 3 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Property, Plant and Equipment | ||
In Service | $ 43,767 | $ 49,952 |
Accumulated Depreciation | (15,731) | (15,160) |
Property, plant and equipment in service net of accumulated provision for depreciation | 28,036 | 34,792 |
Construction Work in Progress | 1,351 | 2,422 |
Total net property, plant and equipment | 29,387 | 37,214 |
Capital leased assets | 244 | 253 |
Regulated Distribution | ||
Property, Plant and Equipment | ||
In Service | 24,979 | 24,034 |
Accumulated Depreciation | (7,169) | (6,865) |
Property, plant and equipment in service net of accumulated provision for depreciation | 17,810 | 17,169 |
Construction Work in Progress | 472 | 530 |
Total net property, plant and equipment | 18,282 | 17,699 |
Regulated Transmission | ||
Property, Plant and Equipment | ||
In Service | 9,342 | 8,222 |
Accumulated Depreciation | (1,948) | (1,840) |
Property, plant and equipment in service net of accumulated provision for depreciation | 7,394 | 6,382 |
Construction Work in Progress | 383 | 484 |
Total net property, plant and equipment | 7,777 | 6,866 |
Net plant in service reclassified | 326 | |
Competitive Energy Services | ||
Property, Plant and Equipment | ||
In Service | 8,680 | 17,214 |
Accumulated Depreciation | (6,267) | (6,213) |
Property, plant and equipment in service net of accumulated provision for depreciation | 2,413 | 11,001 |
Construction Work in Progress | 453 | 1,304 |
Total net property, plant and equipment | 2,866 | 12,305 |
Corporate/Other | ||
Property, Plant and Equipment | ||
In Service | 766 | 482 |
Accumulated Depreciation | (347) | (242) |
Property, plant and equipment in service net of accumulated provision for depreciation | 419 | 240 |
Construction Work in Progress | 43 | 104 |
Total net property, plant and equipment | 462 | 344 |
FES | ||
Property, Plant and Equipment | ||
In Service | 7,057 | 14,311 |
Accumulated Depreciation | (5,929) | (5,765) |
Property, plant and equipment in service net of accumulated provision for depreciation | 1,128 | 8,546 |
Construction Work in Progress | 427 | 1,157 |
Total net property, plant and equipment | 1,555 | 9,703 |
FES | Fossil Generation | ||
Property, Plant and Equipment | ||
In Service | 2,212 | 5,911 |
Accumulated Depreciation | (1,720) | (1,937) |
Property, plant and equipment in service net of accumulated provision for depreciation | 492 | 3,974 |
Construction Work in Progress | 63 | 218 |
Total net property, plant and equipment | 555 | 4,192 |
FES | Nuclear Generation | ||
Property, Plant and Equipment | ||
In Service | 2,065 | 5,617 |
Accumulated Depreciation | (1,723) | (1,574) |
Property, plant and equipment in service net of accumulated provision for depreciation | 342 | 4,043 |
Construction Work in Progress | 118 | 512 |
Total net property, plant and equipment | 460 | 4,555 |
FES | Nuclear Fuel | ||
Property, Plant and Equipment | ||
In Service | 2,637 | 2,616 |
Accumulated Depreciation | (2,418) | (2,198) |
Property, plant and equipment in service net of accumulated provision for depreciation | 219 | 418 |
Construction Work in Progress | 241 | 283 |
Total net property, plant and equipment | 460 | 701 |
FES | Other | ||
Property, Plant and Equipment | ||
In Service | 143 | 167 |
Accumulated Depreciation | (68) | (56) |
Property, plant and equipment in service net of accumulated provision for depreciation | 75 | 111 |
Construction Work in Progress | 5 | 144 |
Total net property, plant and equipment | $ 80 | $ 255 |
Organization and Basis of Pre64
Organization and Basis of Presentation (Details 4) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Annual Composite Depreciation Rate | |||
Annual Composite Depreciation Rate (percent) | 2.50% | 2.50% | 2.50% |
FES | |||
Annual Composite Depreciation Rate | |||
Annual Composite Depreciation Rate (percent) | 3.30% | 3.20% | 3.10% |
Organization and Basis of Pre65
Organization and Basis of Presentation (Details 5) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2016 | |
Summary of changes in goodwill | |||
Beginning balance | $ 6,418 | ||
Impairment | $ (800) | (800) | |
Transmission Segment | 0 | ||
Ending balance | $ 5,618 | 5,618 | |
Regulated Distribution | |||
Summary of changes in goodwill | |||
Beginning balance | 5,092 | ||
Impairment | 0 | ||
Transmission Segment | (88) | ||
Ending balance | 5,004 | 5,004 | |
Regulated Transmission | |||
Summary of changes in goodwill | |||
Beginning balance | 526 | ||
Impairment | 0 | ||
Transmission Segment | 88 | 88 | |
Ending balance | 614 | 614 | |
Competitive Energy Services | |||
Summary of changes in goodwill | |||
Beginning balance | 800 | ||
Impairment | (800) | ||
Transmission Segment | 0 | ||
Ending balance | $ 0 | $ 0 |
Organization and Basis of Pre66
Organization and Basis of Presentation (Details Textuals) mi in Thousands, customer in Millions, MWh in Millions | Feb. 17, 2017USD ($)Natural_gas_plant | Jan. 18, 2017USD ($)Natural_gas_plantMW | Jul. 19, 2016MW | Feb. 21, 2017MWhMW | Dec. 31, 2016USD ($)transmission_centerMW | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2018USD ($)MWh | Dec. 31, 2017USD ($)MWh | Dec. 31, 2016USD ($)MWhcustomertransmission_centercompanymiMW | Dec. 31, 2015USD ($)MW | Dec. 31, 2014USD ($) | Jan. 31, 2017USD ($)MW | Dec. 06, 2016USD ($) | Dec. 05, 2016USD ($) | Oct. 09, 2013MW |
Regulatory Assets [Line Items] | ||||||||||||||||
Aggregate amount of capacity (in MWs) | MW | 17,000 | |||||||||||||||
Length of transmission lines | mi | 24 | |||||||||||||||
Number of regional transmission centers | transmission_center | 2 | 2 | ||||||||||||||
Impairment | $ 800,000,000 | $ 800,000,000 | ||||||||||||||
Regulatory assets that do not earn a current return | $ 153,000,000 | 153,000,000 | $ 148,000,000 | |||||||||||||
Net regulatory liabilities | 157,000,000 | 157,000,000 | 116,000,000 | |||||||||||||
Capitalized financing costs | 37,000,000 | 49,000,000 | $ 49,000,000 | |||||||||||||
Interest costs capitalized | 66,000,000 | 68,000,000 | 69,000,000 | |||||||||||||
Net plant in progress | 28,036,000,000 | 28,036,000,000 | 34,792,000,000 | |||||||||||||
Other than temporary impairments | 21,000,000 | 102,000,000 | 37,000,000 | |||||||||||||
Impairments of long-lived assets | $ (10,665,000,000) | (42,000,000) | 0 | |||||||||||||
Regulated Distribution | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Number of existing utility operating companies | company | 10 | |||||||||||||||
Number of customers served by utility operating companies | customer | 6 | |||||||||||||||
Impairment | $ 0 | |||||||||||||||
Plant generation capacity (in MW's) | MW | 3,790 | |||||||||||||||
Property, plant and equipment, net | 2,100,000,000 | 2,100,000,000 | ||||||||||||||
Net plant in progress | 17,810,000,000 | 17,810,000,000 | $ 17,169,000,000 | |||||||||||||
Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Deactivated power plants (in MW) | MW | 6,770 | |||||||||||||||
Impairment | $ 800,000,000 | |||||||||||||||
Impairment of assets | $ 9,218,000,000 | 647,000,000 | ||||||||||||||
Plant generation capacity (in MW's) | MW | 13,162 | 13,162 | ||||||||||||||
Purchase power agreements additional capacity (in MWh) | MWh | 5 | |||||||||||||||
Contract sales (in MWh) | MWh | 53 | |||||||||||||||
Net plant in progress | $ 2,413,000,000 | $ 2,413,000,000 | $ 11,001,000,000 | |||||||||||||
Bath County, Virginia | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 3,003 | 3,003 | ||||||||||||||
MP | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | $ 500,000,000 | ||||||||||||||
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 | 23,000,000 | $ 23,000,000 | ||||||||||||||
Interest costs capitalized | 34,000,000 | 35,000,000 | 34,000,000 | |||||||||||||
Net plant in progress | $ 1,128,000,000 | 1,128,000,000 | 8,546,000,000 | |||||||||||||
Other than temporary impairments | 19,000,000 | 90,000,000 | 33,000,000 | |||||||||||||
Impairments of long-lived assets | (8,622,000,000) | (33,000,000) | $ 0 | |||||||||||||
FES | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Impairment of assets | 8,082,000,000 | $ 517,000,000 | ||||||||||||||
AGC | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Net plant in progress | $ 458,000,000 | $ 458,000,000 | ||||||||||||||
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% | ||||||||||||||
Net plant in progress | $ 639,000,000 | $ 639,000,000 | ||||||||||||||
Signal Peak | Global Holding | FEV | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
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 | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,300 | 1,300 | ||||||||||||||
Forecast | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 10,000 | |||||||||||||||
Forecast | FES | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Debt that needs to be refinanced | $ 515,000,000 | $ 130,000,000 | ||||||||||||||
Purchase Agreement with Aspen Generating, LLC | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,572 | 1,572 | ||||||||||||||
Purchase Agreement with Aspen Generating, LLC | AE Supply | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Ownership interest (percent) | 59.00% | |||||||||||||||
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 | |||||||||||||||
Subsequent Event | Pleasants Power Station | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,300 | |||||||||||||||
Subsequent Event | Held-for-sale | Pleasants Power Station | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Assets held for sale | $ 195,000,000 | |||||||||||||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Plant generation capacity (in MW's) | MW | 1,572 | |||||||||||||||
Cash purchase price | $ 925,000,000 | $ 925,000,000 | ||||||||||||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | 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 | $ 100,000,000 | |||||||||||||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | AE Supply | Bath County, Virginia | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Proportionate ownership share (percent) | 23.75% | |||||||||||||||
Line of Credit | Revolving Credit Facility | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 500,000,000 | $ 500,000,000 | $ 4,000,000,000 | $ 3,500,000,000 | ||||||||||||
Line of Credit | Revolving Credit Facility | AE Supply | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Maximum amount borrowed under revolving credit facility | 600,000,000 | |||||||||||||||
Line of Credit | Revolving Credit Facility | FES | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Maximum amount borrowed under revolving credit facility | $ 900,000,000 | |||||||||||||||
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 | |||||||||||||||
Minimum | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Annual generation capacity (in MW) | MWh | 70 | |||||||||||||||
Minimum | Forecast | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Annual generation capacity (in MW) | MWh | 60 | |||||||||||||||
Expected contract sales (in MWh) | MWh | 35 | 40 | ||||||||||||||
Maximum | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Annual generation capacity (in MW) | MWh | 75 | |||||||||||||||
Maximum | Forecast | Competitive Energy Services | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Annual generation capacity (in MW) | MWh | 65 | |||||||||||||||
Expected contract sales (in MWh) | MWh | 40 | 45 | ||||||||||||||
Utilization of Accelerated Useful Life | ||||||||||||||||
Regulatory Assets [Line Items] | ||||||||||||||||
Out-of period adjustment | $ 21,000,000 | $ 19,000,000 |
Asset Impairments (Details 1)
Asset Impairments (Details 1) $ in Millions | Jul. 19, 2016MW | Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment of assets | $ 9,218 | $ 42 | |||
Impairment | $ 800 | $ 800 | |||
Contract Termination | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Restructuring charges | 58 | ||||
CES | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment of assets | 9,218 | 647 | |||
Impairment of assets | 34 | ||||
Impairment | $ 800 | ||||
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 | ||||
Impairment | $ 0 | ||||
FES | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment of assets | 8,082 | $ 33 | |||
Impairment | 23 | $ 23 | |||
FES | CES | |||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||||
Impairment of assets | $ 8,082 | $ 517 | |||
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 |
Asset Impairments (Details 2)
Asset Impairments (Details 2) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2016 | Dec. 31, 2015 | |
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | $ 9,218 | $ 42 |
Total | 29,387 | 37,214 |
FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 8,082 | 33 |
Total | 1,555 | $ 9,703 |
OVEC | AE Supply | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 37 | |
Coal generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 4,058 | |
Coal generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 3,264 | |
Nuclear generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 4,382 | |
Nuclear generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 4,365 | |
Gas/Hydro generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 266 | |
Gas/Hydro generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 0 | |
Nuclear Fuel | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 243 | |
Nuclear Fuel | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 243 | |
Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 269 | |
Other | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 210 | |
Materials and Supplies | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 142 | |
Coal contracts | AE Supply | ||
Finite-Lived Intangible Assets [Line Items] | ||
Impairment | 55 | |
Net Book Value | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 11,786 | |
Net Book Value | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 9,541 | |
Net Book Value | Coal generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 4,672 | |
Net Book Value | Coal generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 3,699 | |
Net Book Value | Nuclear generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 4,842 | |
Net Book Value | Nuclear generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 4,825 | |
Net Book Value | Gas/Hydro generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 1,187 | |
Net Book Value | Gas/Hydro generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 0 | |
Net Book Value | Nuclear Fuel | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 703 | |
Net Book Value | Nuclear Fuel | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 703 | |
Net Book Value | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 382 | |
Net Book Value | Other | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 314 | |
Fair Value | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 2,568 | |
Fair Value | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 1,459 | |
Fair Value | Coal generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 614 | |
Fair Value | Coal generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 435 | |
Fair Value | Nuclear generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 460 | |
Fair Value | Nuclear generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 460 | |
Fair Value | Gas/Hydro generation assets | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 921 | |
Fair Value | Gas/Hydro generation assets | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 0 | |
Fair Value | Nuclear Fuel | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 460 | |
Fair Value | Nuclear Fuel | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 460 | |
Fair Value | Other | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | 113 | |
Fair Value | Other | FES | ||
Finite-Lived Intangible Assets [Line Items] | ||
Total | $ 104 |
Accumulated Other Comprehensi69
Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | $ 171 | $ 246 | $ 284 |
Other comprehensive income before reclassifications | 119 | 24 | 181 |
Amounts reclassified from AOCI | (115) | (146) | (233) |
Other comprehensive income (loss) | 4 | (122) | (52) |
Income taxes (benefits) on other comprehensive income (loss) | 1 | (47) | (14) |
Other comprehensive income (loss), net of tax | 3 | (75) | (38) |
AOCI Ending Balance | 174 | 171 | 246 |
FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | 46 | 57 | 54 |
Other comprehensive income before reclassifications | 100 | 25 | 93 |
Amounts reclassified from AOCI | (62) | (43) | (88) |
Other comprehensive income (loss) | 38 | (18) | 5 |
Income taxes (benefits) on other comprehensive income (loss) | 15 | (7) | 2 |
Other comprehensive income (loss), net of tax | 23 | (11) | 3 |
AOCI Ending Balance | 69 | 46 | 57 |
Gains & Losses on Cash Flow Hedges | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | (33) | (37) | (36) |
Other comprehensive income before reclassifications | 0 | 0 | 0 |
Amounts reclassified from AOCI | 8 | 5 | (2) |
Other comprehensive income (loss) | 8 | 5 | (2) |
Income taxes (benefits) on other comprehensive income (loss) | 3 | 1 | (1) |
Other comprehensive income (loss), net of tax | 5 | 4 | (1) |
AOCI Ending Balance | (28) | (33) | (37) |
Gains & Losses on Cash Flow Hedges | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | (9) | (7) | (1) |
Other comprehensive income before reclassifications | 0 | 0 | 0 |
Amounts reclassified from AOCI | 0 | (3) | (10) |
Other comprehensive income (loss) | 0 | (3) | (10) |
Income taxes (benefits) on other comprehensive income (loss) | 0 | (1) | (4) |
Other comprehensive income (loss), net of tax | 0 | (2) | (6) |
AOCI Ending Balance | (9) | (9) | (7) |
Unrealized Gains on AFS Securities | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | 18 | 25 | 9 |
Other comprehensive income before reclassifications | 106 | 14 | 89 |
Amounts reclassified from AOCI | (51) | (25) | (63) |
Other comprehensive income (loss) | 55 | (11) | 26 |
Income taxes (benefits) on other comprehensive income (loss) | 21 | (4) | 10 |
Other comprehensive income (loss), net of tax | 34 | (7) | 16 |
AOCI Ending Balance | 52 | 18 | 25 |
Unrealized Gains on AFS Securities | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | 16 | 21 | 8 |
Other comprehensive income before reclassifications | 100 | 15 | 80 |
Amounts reclassified from AOCI | (48) | (24) | (59) |
Other comprehensive income (loss) | 52 | (9) | 21 |
Income taxes (benefits) on other comprehensive income (loss) | 20 | (4) | 8 |
Other comprehensive income (loss), net of tax | 32 | (5) | 13 |
AOCI Ending Balance | 48 | 16 | 21 |
Defined Benefit Pension & OPEB Plans | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | 186 | 258 | 311 |
Other comprehensive income before reclassifications | 13 | 10 | 92 |
Amounts reclassified from AOCI | (72) | (126) | (168) |
Other comprehensive income (loss) | (59) | (116) | (76) |
Income taxes (benefits) on other comprehensive income (loss) | (23) | (44) | (23) |
Other comprehensive income (loss), net of tax | (36) | (72) | (53) |
AOCI Ending Balance | 150 | 186 | 258 |
Defined Benefit Pension & OPEB Plans | FES | |||
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward] | |||
AOCI Beginning Balance | 39 | 43 | 47 |
Other comprehensive income before reclassifications | 0 | 10 | 13 |
Amounts reclassified from AOCI | (14) | (16) | (19) |
Other comprehensive income (loss) | (14) | (6) | (6) |
Income taxes (benefits) on other comprehensive income (loss) | (5) | (2) | (2) |
Other comprehensive income (loss), net of tax | (9) | (4) | (4) |
AOCI Ending Balance | $ 30 | $ 39 | $ 43 |
Pension and Other Postemploym70
Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent liabilities | $ (3,719) | $ (4,245) | |
Pension | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 9,079 | 9,249 | |
Service cost | 191 | 193 | $ 167 |
Interest cost | 398 | 383 | 402 |
Plan participants' contributions | 0 | 0 | |
Plan amendments | 0 | 0 | |
Medicare retiree drug subsidy | 0 | 0 | |
Actuarial (gain) loss | 224 | (277) | |
Benefits paid | (466) | (469) | |
Benefit obligation as of December 31 | 9,426 | 9,079 | 9,249 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 5,338 | 5,824 | |
Actual return (losses) on plan assets | 442 | (178) | |
Company contributions | 899 | 161 | |
Plan participants' contributions | 0 | 0 | |
Benefits paid | (466) | (469) | |
Fair value of plan assets as of December 31 | 6,213 | 5,338 | 5,824 |
Funded Status: | |||
Funded Status | (3,213) | (3,741) | |
Accumulated benefit obligation | 8,913 | 8,579 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent assets | 9 | 0 | |
Current liabilities | (19) | (18) | |
Noncurrent liabilities | (3,203) | (3,723) | |
Net liability as of December 31 | (3,213) | (3,741) | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ 28 | $ 37 | |
Assumptions Used to Determine Benefit Obligations | |||
Discount rate | 4.25% | 4.50% | |
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 | 44.00% | 40.00% | |
Pension | Bonds | |||
Allocation of Plan Assets | |||
Asset Allocation | 30.00% | 34.00% | |
Pension | Absolute return strategies | |||
Allocation of Plan Assets | |||
Asset Allocation | 8.00% | 7.00% | |
Pension | Real estate | |||
Allocation of Plan Assets | |||
Asset Allocation | 10.00% | 11.00% | |
Pension | Private equity funds | |||
Allocation of Plan Assets | |||
Asset Allocation | 0.00% | 0.00% | |
Pension | Cash | |||
Allocation of Plan Assets | |||
Asset Allocation | 8.00% | 8.00% | |
Pension | Qualified plan | |||
Funded Status: | |||
Funded Status | $ (2,821) | $ (3,366) | |
Pension | Non-qualified plans | |||
Funded Status: | |||
Funded Status | (392) | (375) | |
OPEB | |||
Change in benefit obligation: | |||
Benefit obligation as of January 1 | 724 | 757 | |
Service cost | 5 | 5 | 9 |
Interest cost | 30 | 29 | 39 |
Plan participants' contributions | 5 | 6 | |
Plan amendments | (13) | (10) | |
Medicare retiree drug subsidy | 1 | 1 | |
Actuarial (gain) loss | 14 | (2) | |
Benefits paid | (55) | (62) | |
Benefit obligation as of December 31 | 711 | 724 | 757 |
Change in fair value of plan assets: | |||
Fair value of plan assets as of January 1 | 431 | 464 | |
Actual return (losses) on plan assets | 30 | 6 | |
Company contributions | 9 | 17 | |
Plan participants' contributions | 5 | 6 | |
Benefits paid | (55) | (62) | |
Fair value of plan assets as of December 31 | 420 | 431 | $ 464 |
Funded Status: | |||
Funded Status | (291) | (293) | |
Accumulated benefit obligation | 0 | 0 | |
Amounts Recognized on the Balance Sheet: | |||
Noncurrent assets | 0 | 0 | |
Current liabilities | 0 | 0 | |
Noncurrent liabilities | (291) | (293) | |
Net liability as of December 31 | (291) | (293) | |
Amounts Recognized in AOCI: | |||
Prior service cost (credit) | $ (288) | $ (355) | |
Assumptions Used to Determine Benefit Obligations | |||
Discount rate | 4.00% | 4.25% | |
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 | 53.00% | 51.00% | |
OPEB | Bonds | |||
Allocation of Plan Assets | |||
Asset Allocation | 41.00% | 43.00% | |
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 | |||
Allocation of Plan Assets | |||
Asset Allocation | 6.00% | 6.00% | |
OPEB | Pre Medicare | |||
Assumptions Used to Determine Benefit Obligations | |||
Health care cost trend rate assumed | 6.00% | 6.00% | |
OPEB | Post Medicare | |||
Assumptions Used to Determine Benefit Obligations | |||
Health care cost trend rate assumed | 5.50% | 5.50% |
Accumulated Other Comprehensi71
Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | $ (1,023) | $ (953) | $ (964) | $ (918) | $ (950) | $ (842) | $ (900) | $ (1,057) | $ (3,858) | $ (3,749) | $ (3,962) |
Interest expense - other | (1,157) | (1,132) | (1,081) | ||||||||
Total before taxes | (9,232) | 893 | 171 | ||||||||
Income taxes (benefits) | 3,389 | (251) | 130 | (213) | 170 | (226) | (115) | (144) | 3,055 | (315) | 42 |
NET INCOME (LOSS) | (5,796) | 380 | (1,089) | 328 | (226) | 395 | 187 | 222 | (6,177) | 578 | 299 |
FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | (352) | (316) | (369) | (240) | (312) | (246) | (337) | (413) | (1,277) | (1,308) | (1,635) |
Total before taxes | (8,443) | 147 | (588) | ||||||||
Income taxes (benefits) | 2,983 | (56) | 143 | (82) | (1) | (70) | 4 | 2 | 2,988 | (65) | 228 |
NET INCOME (LOSS) | $ (5,188) | $ 40 | $ (438) | $ 131 | $ (14) | $ 120 | $ (21) | $ (3) | (5,455) | 82 | (244) |
Reclassifications from AOCI | Gains & losses on cash flow hedges | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Total before taxes | 8 | 5 | (2) | ||||||||
Income taxes (benefits) | (3) | (1) | 1 | ||||||||
NET INCOME (LOSS) | 5 | 4 | (1) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Income taxes (benefits) | 0 | 1 | 4 | ||||||||
NET INCOME (LOSS) | 0 | (2) | (6) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | 0 | (3) | (10) | ||||||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Other operating expenses | 0 | (3) | (10) | ||||||||
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 | (51) | (25) | (63) | ||||||||
Income taxes (benefits) | 19 | 9 | 24 | ||||||||
NET INCOME (LOSS) | (32) | (16) | (39) | ||||||||
Reclassifications from AOCI | Unrealized gains on AFS securities | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Investment income | (48) | (24) | (59) | ||||||||
Income taxes (benefits) | 18 | 9 | 22 | ||||||||
NET INCOME (LOSS) | (30) | (15) | (37) | ||||||||
Reclassifications from AOCI | Defined benefit pension and OPEB plans | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Prior-service costs | (72) | (126) | (168) | ||||||||
Income taxes (benefits) | 27 | 49 | 65 | ||||||||
NET INCOME (LOSS) | (45) | (77) | (103) | ||||||||
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES | |||||||||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | |||||||||||
Prior-service costs | (14) | (16) | (19) | ||||||||
Income taxes (benefits) | 5 | 6 | 7 | ||||||||
NET INCOME (LOSS) | $ (9) | $ (10) | $ (12) |
Pension and Other Postemploym72
Pension and Other Postemployment Benefits (Details 1) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service cost | $ 191 | $ 193 | $ 167 |
Interest cost | 398 | 383 | 402 |
Expected return on plan assets | (399) | (443) | (462) |
Amortization of prior service cost (credit) | 8 | 8 | 8 |
Pension & OPEB mark-to-market adjustment | 179 | 344 | 1,235 |
Net periodic cost (credit) | 377 | 485 | 1,350 |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Service cost | 5 | 5 | 9 |
Interest cost | 30 | 29 | 39 |
Expected return on plan assets | (30) | (33) | (34) |
Amortization of prior service cost (credit) | (80) | (134) | (176) |
Pension & OPEB mark-to-market adjustment | 15 | 25 | 8 |
Net periodic cost (credit) | $ (60) | $ (108) | $ (154) |
Pension and Other Postemploym73
Pension and Other Postemployment Benefits (Details 2) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Weighted-average discount rate | 4.50% | 4.25% | 5.00% |
Expected long-term return on plan assets | 7.50% | 7.75% | 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 | 4.25% | 4.00% | 4.75% |
Expected long-term return on plan assets | 7.50% | 7.75% | 7.75% |
Pension and Other Postemploym74
Pension and Other Postemployment Benefits (Details 3) - Pension - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 6,198 | $ 5,345 | |
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 | $ 464 | $ 427 | |
Asset Allocation | 8.00% | 8.00% | |
Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,061 | $ 944 | |
Asset Allocation | 17.00% | 18.00% | |
International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,691 | $ 1,189 | |
Asset Allocation | 27.00% | 22.00% | |
Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 106 | $ 232 | |
Asset Allocation | 2.00% | 4.00% | |
Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,245 | $ 1,115 | |
Asset Allocation | 20.00% | 21.00% | |
High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 372 | $ 438 | |
Asset Allocation | 6.00% | 8.00% | |
Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 112 | $ 31 | |
Asset Allocation | 2.00% | 1.00% | |
Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 500 | $ 343 | |
Asset Allocation | 8.00% | 7.00% | |
Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ (1) | $ 15 | |
Asset Allocation | 0.00% | 0.00% | |
Private Equity Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 33 | $ 24 | |
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 | $ 615 | $ 587 | |
Asset Allocation | 10.00% | 11.00% | |
Level 1 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 1,470 | $ 1,264 | |
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 | 1,048 | 869 | |
Level 1 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 422 | 395 | |
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 | Private Equity Funds | |||
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 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 4,080 | 3,470 | |
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 | 464 | 427 | |
Level 2 | Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 13 | 75 | |
Level 2 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 1,269 | 794 | |
Level 2 | Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 106 | 232 | |
Level 2 | Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 1,245 | 1,115 | |
Level 2 | High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 372 | 438 | |
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 | 112 | 31 | |
Level 2 | Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 500 | 343 | |
Level 2 | Derivatives | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | (1) | 15 | |
Level 2 | Private Equity Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 0 | |
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 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 648 | 611 | |
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 | Private Equity Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 33 | 24 | $ 25 |
Level 3 | Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 615 | $ 587 | $ 421 |
Pension and Other Postemploym75
Pension and Other Postemployment Benefits (Details 4) - Pension - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | $ 5,345 | |
Actual return on plan assets: | ||
Ending balance | 6,198 | $ 5,345 |
Private Equity Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 24 | |
Actual return on plan assets: | ||
Ending balance | 33 | 24 |
Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 587 | |
Actual return on plan assets: | ||
Ending balance | 615 | 587 |
Level 3 | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 611 | |
Actual return on plan assets: | ||
Ending balance | 648 | 611 |
Level 3 | Private Equity Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 24 | 25 |
Actual return on plan assets: | ||
Unrealized gains | 1 | 0 |
Realized gains (losses) | 1 | (1) |
Transfers in (out) | 7 | 0 |
Ending balance | 33 | 24 |
Level 3 | Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 587 | 421 |
Actual return on plan assets: | ||
Unrealized gains | 29 | 42 |
Realized gains (losses) | 14 | 16 |
Transfers in (out) | (15) | 108 |
Ending balance | $ 615 | $ 587 |
Pension and Other Postemploym76
Pension and Other Postemployment Benefits (Details 5) - OPEB - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 424 | $ 438 | |
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 | $ 27 | $ 25 | |
Asset Allocation | 6.00% | 6.00% | |
Domestic | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 223 | $ 219 | |
Asset Allocation | 53.00% | 50.00% | |
International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 0 | $ 4 | |
Asset Allocation | 0.00% | 1.00% | |
U.S. treasuries | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 40 | $ 42 | |
Asset Allocation | 9.00% | 10.00% | |
Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 108 | $ 114 | |
Asset Allocation | 26.00% | 26.00% | |
Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 24 | $ 27 | |
Asset Allocation | 6.00% | 6.00% | |
High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 0 | $ 1 | |
Asset Allocation | 0.00% | 0.00% | |
Mortgaged-backed securities (non-government) | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 2 | $ 3 | |
Asset Allocation | 0.00% | 1.00% | |
Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 0 | $ 1 | |
Asset Allocation | 0.00% | 0.00% | |
Private Equity Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
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 | $ 0 | $ 2 | |
Asset Allocation | 0.00% | 0.00% | |
Level 1 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 223 | $ 220 | |
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 | 223 | 219 | |
Level 1 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 1 | |
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 | 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 | 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 | 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 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 201 | 216 | |
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 | 27 | 25 | |
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 | International | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 3 | |
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 | 42 | |
Level 2 | Government bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 108 | 114 | |
Level 2 | Corporate bonds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 24 | 27 | |
Level 2 | High yield debt | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 1 | |
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 | 2 | 3 | |
Level 2 | Hedge funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 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 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | 0 | 2 | |
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 | U.S. treasuries | |||
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 | Real Estate Funds | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Pension investments measured at fair value | $ 0 | $ 2 | $ 3 |
Pension and Other Postemploym77
Pension and Other Postemployment Benefits (Details 6) - OPEB - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | $ 438 | |
Actual return on plan assets: | ||
Ending balance | 424 | $ 438 |
Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 2 | |
Actual return on plan assets: | ||
Ending balance | 0 | 2 |
Level 3 | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 2 | |
Actual return on plan assets: | ||
Ending balance | 0 | 2 |
Level 3 | Real Estate Funds | ||
Reconciliation of changes in the fair value of pension investments | ||
Beginning balance | 2 | 3 |
Actual return on plan assets: | ||
Transfers in (out) | (2) | (1) |
Ending balance | $ 0 | $ 2 |
Pension and Other Postemploym78
Pension and Other Postemployment Benefits (Details 7) | 12 Months Ended |
Dec. 31, 2016 | |
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 Postemploym79
Pension and Other Postemployment Benefits (Details 8) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Compensation and Retirement Disclosure [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 | 23 |
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 | $ (20) |
Pension and Other Postemploym80
Pension and Other Postemployment Benefits (Details 9) $ in Millions | Dec. 31, 2016USD ($) |
Pension | |
Estimated Future Benefit Payments | |
2,017 | $ 505 |
2,018 | 523 |
2,019 | 534 |
2,020 | 552 |
2,021 | 566 |
2022-2026 | 2,999 |
OPEB | |
Estimated Future Benefit Payments | |
2,017 | 52 |
2,018 | 52 |
2,019 | 53 |
2,020 | 53 |
2,021 | 53 |
2022-2026 | 251 |
Subsidy Receipts | |
2,017 | (3) |
2,018 | (3) |
2,019 | (3) |
2,020 | (3) |
2,021 | (3) |
Years 2022-2026 | $ (7) |
Pension and Other Postemploym81
Pension and Other Postemployment Benefits (Details 10) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-current liabilities | $ 866 | $ 785 |
FENOC | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Non-current liabilities | 570 | 518 |
Pension | FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net (Liability) Asset | (158) | (303) |
OPEB | FES | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Net (Liability) Asset | $ 36 | $ 25 |
Pension and Other Postemploym82
Pension and Other Postemployment Benefits (Details 11) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | $ 377 | $ 485 | $ 1,350 |
Pension | FES | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | (5) | 10 | 150 |
OPEB | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | (60) | (108) | (154) |
OPEB | FES | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Net Periodic Cost (Credit) | $ (26) | $ (22) | $ (24) |
Pension and Other Postemploym83
Pension and Other Postemployment Benefits (Details Textuals) - USD ($) $ in Millions | Dec. 13, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 01, 2014 |
Defined Benefit Plan Disclosure [Line Items] | ||||||
Mark-to-market adjustment | $ 194 | $ 194 | $ 369 | $ 1,243 | ||
Mark-to-market adjustment, net of capitalized amounts | 147 | $ 147 | 242 | 835 | ||
Decrease in mortality rate (percent) | 0.25% | |||||
Funding contributions made for current and future years | $ 882 | |||||
Pension contributions | $ 500 | 382 | 143 | 0 | ||
Equity contribution from parent | $ 500 | 500 | ||||
Non-cash transaction: stock contribution to pension plan | 500 | 0 | 0 | |||
Pensions and OPEB | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Actual return (losses) on plan assets | $ 472 | $ (172) | $ 387 | |||
Actual return on plan assets (percent) | 8.20% | (2.70%) | 6.20% | |||
Expected return on plan assets | $ 429 | $ 476 | $ 496 | |||
Pension | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Decrease in underfunded status | $ 40 | |||||
Company contributions | 899 | 161 | ||||
Actual return (losses) on plan assets | $ 442 | $ (178) | ||||
Expected long-term return on plan assets | 7.50% | 7.75% | 7.75% | |||
Expected return on plan assets | $ 399 | $ 443 | $ 462 | |||
Increase in benefit obligation due to RP2014 mortality table | 141 | |||||
Estimated amortization of prior service costs (credits) from AOCI in next fiscal year | 8 | |||||
Excluded from total investments | 16 | 16 | (7) | |||
OPEB | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Effect of plan amendment on accumulated benefit obligation | 13 | 13 | 10 | |||
Company contributions | 9 | 17 | ||||
Actual return (losses) on plan assets | $ 30 | $ 6 | ||||
Expected long-term return on plan assets | 7.50% | 7.75% | 7.75% | |||
Expected return on plan assets | $ 30 | $ 33 | $ 34 | |||
Increase in benefit obligation due to RP2014 mortality table | 8 | |||||
Estimated amortization of prior service costs (credits) from AOCI in next fiscal year | (81) | |||||
Excluded from total investments | $ (4) | (4) | (7) | |||
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 | 138 | $ 0 | 0 | |||
Equity contribution from parent | $ 0 | $ 500 |
Stock-Based Compensation Plan84
Stock-Based Compensation Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 105 | $ 89 | $ 69 |
Stock-based compensation costs capitalized | 38 | 32 | 23 |
Incentive Plans | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 62 | 46 | 26 |
Incentive Plans | Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 2 | 2 | 5 |
Incentive Plans | Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | (3) | 0 | 5 |
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 39 | 38 | 25 |
EDCP & DCPD | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 5 | 3 | 8 |
FES | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 16 | 11 | 9 |
Stock-based compensation costs capitalized | 2 | 1 | 1 |
FES | Incentive Plans | Restricted Stock Units (RSUs) | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 11 | 6 | 4 |
FES | Incentive Plans | Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | 0 | 0 | 1 |
FES | 401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs | $ 5 | $ 5 | $ 4 |
Stock-Based Compensation Plan85
Stock-Based Compensation Plans (Details 1) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Weighted-Average Grant Date Fair Value | |||
Dividend shares earned during period, number of shares | 132,360 | ||
Restricted Stock Units (RSUs) | |||
Shares | |||
Nonvested, Beginning balance (shares) | 2,436,888 | ||
Granted (shares) | 1,581,762 | ||
Forfeited (shares) | (81,618) | ||
Vested (shares) | (873,303) | ||
Nonvested, Ending balance (shares) | 3,063,729 | 2,436,888 | |
Weighted-Average Grant Date Fair Value | |||
Beginning balance (in dollars per share) | $ 35.26 | ||
Granted (in dollars per share) | 34.77 | $ 35.27 | $ 32.17 |
Forfeited (in dollars per share) | 33.85 | ||
Vested (in dollars per share) | 33.54 | ||
Ending balance (in dollars per share) | $ 32.98 | $ 35.26 | |
Restricted Stock | |||
Shares | |||
Nonvested, Beginning balance (shares) | 190,656 | ||
Granted (shares) | 28,756 | ||
Vested (shares) | (82,252) | ||
Nonvested, Ending balance (shares) | 137,160 | 190,656 | |
Weighted-Average Grant Date Fair Value | |||
Beginning balance (in dollars per share) | $ 40.65 | ||
Granted (in dollars per share) | 32.69 | $ 32.98 | $ 32.71 |
Vested (in dollars per share) | 46.83 | ||
Ending balance (in dollars per share) | $ 35.27 | $ 40.65 | |
Dividend shares earned during period, number of shares | 23,402 |
Stock-Based Compensation Plan86
Stock-Based Compensation Plans (Details 2) - $ / shares | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | ||
Options exercisable (in shares) | 1,376,821 | 1,211,358 |
Number of Shares | ||
Beginning option balance (shares) | 1,411,971 | |
Options forfeited (in shares) | (35,150) | |
Ending option balance (shares) | 1,376,821 | |
Weighted Average Exercise Price | ||
Beginning balance (in dollars per share) | $ 44.89 | |
Options forfeited (in dollars per share) | 56.40 | |
Ending balance (in dollars per share) | $ 44.60 |
Stock-Based Compensation Plan87
Stock-Based Compensation Plans (Details Textuals) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award number of shares available for future | 8,000,000 | ||
Stock-based compensation award vesting period | 3 years | ||
Realized tax benefits | $ 13 | $ 10 | $ 13 |
Tax benefit associated with stock-based compensation expense | $ 14 | 12 | 14 |
Stock option expiration period | 10 years | ||
Stock options granted in period (shares) | 0 | ||
Share-based liabilities paid | $ 2 | $ 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 | $ 7 | $ 9 | |
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 | $ 14 | ||
Granted (in dollars per share) | $ 34.77 | $ 35.27 | $ 32.17 |
Fair value of restricted stock units vested | $ 36 | $ 22 | $ 28 |
Unrecognized cost | $ 47 | ||
Unrecognized cost, period for recognition | 2 years | ||
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Remaining contractual life | 3 years 7 months 6 days | ||
Performance Shares | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation award vesting period | 3 years | ||
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted (in dollars per share) | $ 32.69 | $ 32.98 | $ 32.71 |
Fair value of restricted stock units vested | $ 5 | $ 8 | $ 4 |
Unrecognized cost | $ 2 | ||
Unrecognized cost, period for recognition | 3 years | ||
Weighted average vesting period (years) | 3 years 5 months 27 days | ||
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 | $ 2 | $ 2 | $ 2 |
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 | ||
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 | ||
401(k) Savings Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares authorized for issuance | 1,159,215 | 1,072,494 |
Taxes (Details)
Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Currently payable (receivable)- | |||||||||||
Federal | $ (1) | $ 1 | $ (132) | ||||||||
State | 9 | 30 | (72) | ||||||||
Currently payable (receivable) Total | 8 | 31 | (204) | ||||||||
Deferred, net- | |||||||||||
Federal | (3,114) | 277 | 214 | ||||||||
State | 59 | 15 | (42) | ||||||||
Deferred Tax Total | (3,055) | 292 | 172 | ||||||||
Investment tax credit amortization | (8) | (8) | (10) | ||||||||
Total provision for income taxes (benefits) | $ (3,389) | $ 251 | $ (130) | $ 213 | $ (170) | $ 226 | $ 115 | $ 144 | (3,055) | 315 | (42) |
Internal Revenue Service (IRS) | |||||||||||
Deferred, net- | |||||||||||
Current tax effect of discontinued operation | 106 | ||||||||||
Deferred tax effect of discontinued operation | 44 | ||||||||||
State and Local | |||||||||||
Deferred, net- | |||||||||||
Current tax effect of discontinued operation | 12 | ||||||||||
Deferred tax effect of discontinued operation | 5 | ||||||||||
FES | |||||||||||
Currently payable (receivable)- | |||||||||||
Federal | (67) | (56) | (222) | ||||||||
State | (1) | 2 | (13) | ||||||||
Currently payable (receivable) Total | (68) | (54) | (235) | ||||||||
Deferred, net- | |||||||||||
Federal | (2,861) | 103 | 25 | ||||||||
State | (57) | 18 | (14) | ||||||||
Deferred Tax Total | (2,918) | 121 | 11 | ||||||||
Investment tax credit amortization | (2) | (2) | (4) | ||||||||
Total provision for income taxes (benefits) | $ (2,983) | $ 56 | $ (143) | $ 82 | $ 1 | $ 70 | $ (4) | $ (2) | $ (2,988) | $ 65 | $ (228) |
Taxes (Details 1)
Taxes (Details 1) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | |||||||||||
Income (loss) from Continuing Operations before income taxes (benefits) | $ (9,232) | $ 893 | $ 171 | ||||||||
Federal income tax expense (benefit) at statutory rate (35%) | (3,231) | 313 | 60 | ||||||||
Increases (reductions) in taxes resulting from- | |||||||||||
State income taxes, net of federal tax benefit | (192) | 17 | (21) | ||||||||
AFUDC equity and other flow-through | (13) | (16) | (13) | ||||||||
Amortization of investment tax credits | (8) | (8) | (10) | ||||||||
Change in accounting method | 0 | (8) | (27) | ||||||||
ESOP dividend | (6) | (6) | (6) | ||||||||
Impairment of non-deductible goodwill | 157 | 0 | 0 | ||||||||
Tax basis balance sheet adjustments | 0 | 0 | (25) | ||||||||
Uncertain tax positions | (16) | 1 | (35) | ||||||||
Valuation allowances | 246 | 18 | 33 | ||||||||
Other, net | 8 | 4 | 2 | ||||||||
Total provision for income taxes (benefits) | $ (3,389) | $ 251 | $ (130) | $ 213 | $ (170) | $ 226 | $ 115 | $ 144 | $ (3,055) | $ 315 | $ (42) |
Effective income tax rate (percent) | 33.10% | 35.30% | (24.60%) | ||||||||
FES | |||||||||||
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes | |||||||||||
Income (loss) from Continuing Operations before income taxes (benefits) | $ (8,444) | $ 147 | $ (588) | ||||||||
Federal income tax expense (benefit) at statutory rate (35%) | (2,955) | 51 | (206) | ||||||||
Increases (reductions) in taxes resulting from- | |||||||||||
State income taxes, net of federal tax benefit | (188) | 2 | (28) | ||||||||
Amortization of investment tax credits | (2) | (2) | (4) | ||||||||
ESOP dividend | (1) | (1) | (1) | ||||||||
Impairment of non-deductible goodwill | 9 | 0 | 0 | ||||||||
Uncertain tax positions | (8) | 5 | 0 | ||||||||
Valuation allowances | 151 | 14 | 14 | ||||||||
Other, net | 6 | (4) | (3) | ||||||||
Total provision for income taxes (benefits) | $ (2,983) | $ 56 | $ (143) | $ 82 | $ 1 | $ 70 | $ (4) | $ (2) | $ (2,988) | $ 65 | $ (228) |
Effective income tax rate (percent) | 35.40% | 44.20% | 38.80% |
Taxes (Details 2)
Taxes (Details 2) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Accumulated deferred income taxes | ||
Property basis differences | $ 7,088 | $ 9,920 |
Deferred sale and leaseback gain | (351) | (360) |
Pension and OPEB | (1,347) | (1,541) |
Nuclear decommissioning activities | 635 | 480 |
Asset retirement obligations | (669) | (731) |
Regulatory asset/liability | 545 | 763 |
Deferred compensation | (269) | (239) |
Loss carryforwards and AMT credits | (2,251) | (1,965) |
Valuation reserve | 438 | 192 |
All other | (54) | 254 |
Net deferred income tax liability | 3,765 | 6,773 |
FES | ||
Accumulated deferred income taxes | ||
Property basis differences | (1,009) | 1,901 |
Deferred sale and leaseback gain | (328) | (342) |
Pension and OPEB | (366) | (393) |
Lease market valuation liability | 111 | 95 |
Nuclear decommissioning activities | 540 | 483 |
Asset retirement obligations | (453) | (509) |
Loss carryforwards and AMT credits | (830) | (687) |
Valuation reserve | 197 | 46 |
All other | (141) | 6 |
Net deferred income tax liability | $ 600 | |
Net deferred income tax liability (asset) | $ (2,279) |
Taxes (Details 3)
Taxes (Details 3) $ in Millions | Dec. 31, 2016USD ($) |
State | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | $ 7,062 |
State | 2017-2021 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 166 |
State | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,327 |
State | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,817 |
State | 2032-2036 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,752 |
Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,998 |
Local | 2017-2021 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2,998 |
Local | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
Local | 2032-2036 | |
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 | 1,584 |
FES | State | 2017-2021 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 2 |
FES | State | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | State | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 410 |
FES | State | 2032-2036 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,172 |
FES | Local | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,795 |
FES | Local | 2017-2021 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 1,795 |
FES | Local | 2022-2026 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | Local | 2027-2031 | |
Pre-tax net operating loss expiration period | |
Pre-tax net operating loss carryforwards for state and local income tax purposes | 0 |
FES | Local | 2032-2036 | |
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, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Changes in unrecognized tax benefits | |||
Beginning balance | $ 34 | $ 34 | $ 48 |
Current year increases | 2 | 3 | 4 |
Prior years increases | 69 | 7 | 5 |
Prior years decreases | (21) | (10) | (23) |
Ending balance | 84 | 34 | 34 |
FES | |||
Changes in unrecognized tax benefits | |||
Beginning balance | 8 | 3 | 3 |
Current year increases | 0 | 0 | 0 |
Prior years increases | 0 | 5 | 0 |
Prior years decreases | (8) | 0 | 0 |
Ending balance | $ 0 | $ 8 | $ 3 |
Taxes (Details 5)
Taxes (Details 5) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
General Taxes | |||
KWH excise | $ 196 | $ 193 | $ 194 |
State gross receipts | 212 | 224 | 226 |
Real and personal property | 472 | 410 | 393 |
Social security and unemployment | 127 | 119 | 112 |
Other | 35 | 32 | 37 |
Total general taxes | 1,042 | 978 | 962 |
FES | |||
General Taxes | |||
State gross receipts | 28 | 44 | 69 |
Real and personal property | 42 | 36 | 39 |
Social security and unemployment | 15 | 16 | 17 |
Other | 3 | 2 | 3 |
Total general taxes | $ 88 | $ 98 | $ 128 |
Taxes (Details Textuals)
Taxes (Details Textuals) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Taxes (Textuals) [Abstract] | |||||
Effective income tax rate (percent) | 33.10% | 35.30% | (24.60%) | ||
Impairment | $ 800 | $ 800 | |||
Impairment of non-deductible goodwill | 433 | ||||
Valuation allowances | 246 | $ 18 | $ 33 | ||
Change in accounting method | 0 | (8) | (27) | ||
Unrecognized tax benefits | 84 | $ 34 | $ 34 | $ 48 | |
Unrecognized tax benefits that would impact future tax rates | 50 | ||||
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year | 51 | ||||
Unrecognized tax benefits that would impact effective tax rate | 26 | ||||
Federal | |||||
Income Taxes (Textuals) [Abstract] | |||||
Operating loss carryforwards, not subject to expiration | 25 | ||||
Operating loss carryforwards, subject to expiration | 1,800 | ||||
State and Local | |||||
Income Taxes (Textuals) [Abstract] | |||||
Operating loss carryforwards valuation allowance | 168 | ||||
Operating loss carryforwards, subject to expiration | 407 | ||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 10,100 | ||||
Pre-tax net operating loss carryforwards expected to utilized | 2,100 | ||||
Operating loss carryforwards expected to utilized, net of tax | 87 | ||||
State and Local | Property [Member] | |||||
Income Taxes (Textuals) [Abstract] | |||||
Deferred tax assets valuation allowance | $ 78 | ||||
FES | |||||
Income Taxes (Textuals) [Abstract] | |||||
Effective income tax rate (percent) | 35.40% | 44.20% | 38.80% | ||
Impairment | $ 23 | $ 23 | |||
Valuation allowances | 151 | $ 14 | $ 14 | ||
Unrecognized tax benefits | 0 | $ 8 | $ 3 | $ 3 | |
FES | Federal | |||||
Income Taxes (Textuals) [Abstract] | |||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 706 | ||||
FES | State and Local | |||||
Income Taxes (Textuals) [Abstract] | |||||
Operating loss carryforwards valuation allowance | 73 | ||||
Operating loss carryforwards, subject to expiration | 120 | ||||
Pre-tax net operating loss carryforwards for state and local income tax purposes | 3,400 | ||||
FES | State and Local | Property [Member] | |||||
Income Taxes (Textuals) [Abstract] | |||||
Deferred tax assets valuation allowance | $ 78 |
Leases (Details)
Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Rentals for capital and operating leases | |||
Operating leases | $ 168 | $ 174 | $ 199 |
FES | |||
Rentals for capital and operating leases | |||
Operating leases | $ 94 | $ 94 | $ 95 |
Leases (Details 1)
Leases (Details 1) $ in Millions | Dec. 31, 2016USD ($) |
Future minimum capital lease payments | |
2,017 | $ 32 |
2,018 | 25 |
2,019 | 19 |
2,020 | 14 |
2,021 | 12 |
Years thereafter | 15 |
Total minimum lease payments | 117 |
Interest portion | (13) |
Present value of net minimum lease payments | 104 |
Less current portion | 29 |
Noncurrent portion | 75 |
FES | |
Future minimum capital lease payments | |
2,017 | 6 |
2,018 | 2 |
2,019 | 0 |
2,020 | 0 |
2,021 | 0 |
Years thereafter | 1 |
Total minimum lease payments | 9 |
Interest portion | (1) |
Present value of net minimum lease payments | 8 |
Less current portion | 5 |
Noncurrent portion | $ 3 |
Leases (Details 2)
Leases (Details 2) $ in Millions | Dec. 31, 2016USD ($) |
Lease Payments | |
Future minimum operating lease payments | |
2,017 | $ 125 |
2,018 | 142 |
2,019 | 123 |
2,020 | 97 |
2,021 | 119 |
Years thereafter | 1,351 |
Total minimum lease payments | 1,957 |
PNBV Capital Trust | |
Future minimum operating lease payments | |
2,017 | 3 |
FES | |
Future minimum operating lease payments | |
2,017 | 82 |
2,018 | 101 |
2,019 | 97 |
2,020 | 68 |
2,021 | 93 |
Years thereafter | 1,222 |
Total minimum lease payments | $ 1,663 |
Leases (Details Textuals)
Leases (Details Textuals) $ in Millions | Jun. 30, 2017 | Jun. 30, 2016 | May 30, 2016 | May 23, 2016USD ($) | Nov. 30, 2014USD ($)MW | Dec. 31, 2007 | Dec. 30, 1987 | Dec. 31, 2016 |
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 | |||||||
Beaver Valley Unit 2 | ||||||||
Leases (Textuals) [Abstract] | ||||||||
Percentage leased | 2.60% | |||||||
Bruce Mansfield Unit 1 | ||||||||
Leases (Textuals) [Abstract] | ||||||||
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 | Perry Power Plant Unit 1 | ||||||||
Leases (Textuals) [Abstract] | ||||||||
Payments to acquire interest in subsidiaries | $ 50 | |||||||
Plant ownership percentage | 100.00% | 100.00% | ||||||
NG | Perry Power Plant Unit 1 | ||||||||
Leases (Textuals) [Abstract] | ||||||||
Purchase of lessor equity interests in sale and leaseback (in MW) | MW | 55.3 | |||||||
Purchase of lessor equity interests in sale and leaseback, value | $ 87 | |||||||
Forecast | NG | Perry Power Plant Unit 1 | ||||||||
Leases (Textuals) [Abstract] | ||||||||
Plant ownership percentage | 100.00% |
Intangible Assets (Details)
Intangible Assets (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | $ 882 | |
Intangible Assets, Accumulated Amortization | 762 | |
Intangible Assets, Net | 120 | |
Amortization Expense | ||
Actual, 2016 | 114 | |
Estimated, 2017 | 11 | |
Estimated, 2018 | 9 | |
Estimated, 2019 | 6 | |
Estimated, 2020 | 5 | |
Estimated, 2021 | 5 | |
Estimated, Thereafter | 72 | |
Impairment charges | 92 | |
NUG contracts | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | 124 | |
Intangible Assets, Accumulated Amortization | 31 | |
Intangible Assets, Net | 93 | |
Amortization Expense | ||
Actual, 2016 | 5 | |
Estimated, 2017 | 5 | |
Estimated, 2018 | 5 | |
Estimated, 2019 | 5 | |
Estimated, 2020 | 5 | |
Estimated, 2021 | 5 | |
Estimated, Thereafter | 68 | |
OVEC | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | 54 | |
Intangible Assets, Accumulated Amortization | 48 | |
Intangible Assets, Net | 6 | |
Amortization Expense | ||
Actual, 2016 | 2 | |
Estimated, 2017 | 1 | |
Estimated, 2018 | 1 | |
Estimated, 2019 | 0 | |
Estimated, 2020 | 0 | |
Estimated, 2021 | 0 | |
Estimated, Thereafter | 4 | |
Coal contracts | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | 556 | |
Intangible Assets, Accumulated Amortization | 544 | |
Intangible Assets, Net | 12 | |
Amortization Expense | ||
Actual, 2016 | 55 | |
Estimated, 2017 | 0 | |
Estimated, 2018 | 0 | |
Estimated, 2019 | 0 | |
Estimated, 2020 | 0 | |
Estimated, 2021 | 0 | |
Estimated, Thereafter | 0 | |
FES customer contracts | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | 148 | |
Intangible Assets, Accumulated Amortization | 139 | |
Intangible Assets, Net | 9 | |
Amortization Expense | ||
Actual, 2016 | 52 | |
Estimated, 2017 | 5 | |
Estimated, 2018 | 3 | |
Estimated, 2019 | 1 | |
Estimated, 2020 | 0 | |
Estimated, 2021 | 0 | |
Estimated, Thereafter | 0 | |
Loss on termination of contract | 37 | |
FES | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Net | 9 | $ 61 |
FES | Coal contracts | ||
Intangible Assets (Textuals) [Abstract] | ||
Intangible Assets, Gross | $ 40 |
Variable Interest Entities (Det
Variable Interest Entities (Details) $ in Millions | Dec. 31, 2016USD ($) |
Net exposure to loss based upon the casualty value provisions | |
Maximum Exposure | $ 1,123 |
Discounted Lease Payments, net | 879 |
Net Exposure | 244 |
FES | |
Net exposure to loss based upon the casualty value provisions | |
Maximum Exposure | 1,098 |
Discounted Lease Payments, net | 875 |
Net Exposure | $ 223 |
Variable Interest Entities (101
Variable Interest Entities (Details Textuals) | Jun. 30, 2016 | May 30, 2016 | Dec. 31, 2016USD ($)agreemententity | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Variable Interest Entities (Textuals) [Abstract] | |||||
Transition bond outstanding | $ 85,000,000 | $ 128,000,000 | |||
Environmental control bonds outstanding | $ 406,000,000 | 429,000,000 | |||
Number of contracts that may contain variable interest | entity | 1 | ||||
Ownership interest (percent) | 3.00% | ||||
Purchased power | $ 3,813,000,000 | 4,318,000,000 | $ 4,716,000,000 | ||
Power Purchase Agreements | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement | 14 | ||||
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% | ||||
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 | $ 108,000,000 | 116,000,000 | |||
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 | $ 339,000,000 | $ 362,000,000 | |||
Senior Loans | Senior Secured Term Loan | Global Holding | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||
Long-term debt and other long-term obligations | $ 300,000,000 | ||||
Perry Power Plant Unit 1 | NG | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||
Plant ownership percentage | 100.00% | 100.00% | |||
Bruce Mansfield Unit 1 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||
Percentage leased | 93.83% | ||||
Beaver Valley Unit 2 | |||||
Variable Interest Entities (Textuals) [Abstract] | |||||
Percentage leased | 2.60% |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Assets | ||
Fair value, assets | $ 3,197 | $ 2,876 |
Liabilities | ||
Fair value, liabilities | (238) | (281) |
Net assets (liabilities) | 2,959 | 2,595 |
FES | ||
Assets | ||
Fair value, assets | 1,766 | 1,559 |
Liabilities | ||
Fair value, liabilities | (129) | (142) |
Net assets (liabilities) | 1,637 | 1,417 |
Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (124) | (131) |
Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (124) | (131) |
FTRs | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (6) | (13) |
FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (5) | (11) |
NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (108) | (137) |
Corporate debt securities | ||
Assets | ||
Fair value, assets | 1,247 | 1,245 |
Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 726 | 678 |
Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 210 | 228 |
Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 210 | 228 |
FTRs | Derivative Assets | ||
Assets | ||
Fair value, assets | 7 | 8 |
FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 4 | 5 |
NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 1 | 1 |
Equity securities | ||
Assets | ||
Fair value, assets | 925 | 576 |
Equity securities | FES | ||
Assets | ||
Fair value, assets | 634 | 378 |
Foreign government debt securities | ||
Assets | ||
Fair value, assets | 78 | 75 |
Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 58 | 59 |
U.S. government debt securities | ||
Assets | ||
Fair value, assets | 161 | 180 |
U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 48 | 23 |
U.S. state debt securities | ||
Assets | ||
Fair value, assets | 246 | 246 |
U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 3 | 4 |
Other | ||
Assets | ||
Fair value, assets | 322 | 317 |
Other | FES | ||
Assets | ||
Fair value, assets | 83 | 184 |
Level 1 | ||
Assets | ||
Fair value, assets | 1,134 | 685 |
Liabilities | ||
Fair value, liabilities | (6) | (9) |
Net assets (liabilities) | 1,128 | 676 |
Level 1 | FES | ||
Assets | ||
Fair value, assets | 646 | 382 |
Liabilities | ||
Fair value, liabilities | (6) | (9) |
Net assets (liabilities) | 640 | 373 |
Level 1 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (6) | (9) |
Level 1 | Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (6) | (9) |
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 | 10 | 4 |
Level 1 | Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 10 | 4 |
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 | 925 | 576 |
Level 1 | Equity securities | FES | ||
Assets | ||
Fair value, assets | 634 | 378 |
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 | 199 | 105 |
Level 1 | Other | FES | ||
Assets | ||
Fair value, assets | 2 | 0 |
Level 2 | ||
Assets | ||
Fair value, assets | 2,055 | 2,182 |
Liabilities | ||
Fair value, liabilities | (118) | (122) |
Net assets (liabilities) | 1,937 | 2,060 |
Level 2 | FES | ||
Assets | ||
Fair value, assets | 1,116 | 1,172 |
Liabilities | ||
Fair value, liabilities | (118) | (122) |
Net assets (liabilities) | 998 | 1,050 |
Level 2 | Commodity contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (118) | (122) |
Level 2 | Commodity contracts | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (118) | (122) |
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 | 1,247 | 1,245 |
Level 2 | Corporate debt securities | FES | ||
Assets | ||
Fair value, assets | 726 | 678 |
Level 2 | Commodity contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 200 | 224 |
Level 2 | Commodity contracts | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 200 | 224 |
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 | 78 | 75 |
Level 2 | Foreign government debt securities | FES | ||
Assets | ||
Fair value, assets | 58 | 59 |
Level 2 | U.S. government debt securities | ||
Assets | ||
Fair value, assets | 161 | 180 |
Level 2 | U.S. government debt securities | FES | ||
Assets | ||
Fair value, assets | 48 | 23 |
Level 2 | U.S. state debt securities | ||
Assets | ||
Fair value, assets | 246 | 246 |
Level 2 | U.S. state debt securities | FES | ||
Assets | ||
Fair value, assets | 3 | 4 |
Level 2 | Other | ||
Assets | ||
Fair value, assets | 123 | 212 |
Level 2 | Other | FES | ||
Assets | ||
Fair value, assets | 81 | 184 |
Level 3 | ||
Assets | ||
Fair value, assets | 8 | 9 |
Liabilities | ||
Fair value, liabilities | (114) | (150) |
Net assets (liabilities) | (106) | (141) |
Level 3 | FES | ||
Assets | ||
Fair value, assets | 4 | 5 |
Liabilities | ||
Fair value, liabilities | (5) | (11) |
Net assets (liabilities) | (1) | (6) |
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 | (6) | (13) |
Level 3 | FTRs | Derivative Liabilities | FES | ||
Liabilities | ||
Fair value, liabilities | (5) | (11) |
Level 3 | NUG contracts | Derivative Liabilities | ||
Liabilities | ||
Fair value, liabilities | (108) | (137) |
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 | 7 | 8 |
Level 3 | FTRs | Derivative Assets | FES | ||
Assets | ||
Fair value, assets | 4 | 5 |
Level 3 | NUG contracts | Derivative Assets | ||
Assets | ||
Fair value, assets | 1 | 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 (Det103
Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
NUG contracts | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | $ 1 | $ 2 |
Beginning Balance, Derivative Liabilities | (137) | (153) |
Beginning Balance, Net | (136) | (151) |
Unrealized gain (loss), Derivative Assets | 2 | 2 |
Unrealized gain (loss), Derivative Liabilities | (17) | (49) |
Unrealized gain (loss), Net | (15) | (47) |
Purchases, Derivative Assets | 0 | 0 |
Purchases, Derivative Liabilities | 0 | 0 |
Purchases, Net | 0 | 0 |
Settlements, Derivative Assets | (2) | (3) |
Settlements, Derivative Liabilities | 46 | 65 |
Settlements, Net | 44 | 62 |
Ending Balance, Derivative Assets | 1 | 1 |
Ending Balance, Derivative Liabilities | (108) | (137) |
Ending Balance, Net | (107) | (136) |
FTRs | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | 8 | 39 |
Beginning Balance, Derivative Liabilities | (13) | (14) |
Beginning Balance, Net | (5) | 25 |
Unrealized gain (loss), Derivative Assets | (6) | (5) |
Unrealized gain (loss), Derivative Liabilities | (4) | (7) |
Unrealized gain (loss), Net | (10) | (12) |
Purchases, Derivative Assets | 16 | 22 |
Purchases, Derivative Liabilities | (7) | (11) |
Purchases, Net | 9 | 11 |
Settlements, Derivative Assets | (11) | (48) |
Settlements, Derivative Liabilities | 18 | 19 |
Settlements, Net | 7 | (29) |
Ending Balance, Derivative Assets | 7 | 8 |
Ending Balance, Derivative Liabilities | (6) | (13) |
Ending Balance, Net | 1 | (5) |
FES | FTRs | ||
Reconciliation of changes in the fair value of NUG contracts | ||
Beginning Balance, Derivative Assets | 5 | 27 |
Beginning Balance, Derivative Liabilities | (11) | (13) |
Beginning Balance, Net | (6) | 14 |
Unrealized gain (loss), Derivative Assets | (4) | 2 |
Unrealized gain (loss), Derivative Liabilities | (3) | (5) |
Unrealized gain (loss), Net | (7) | (3) |
Purchases, Derivative Assets | 10 | 9 |
Purchases, Derivative Liabilities | (5) | (10) |
Purchases, Net | 5 | (1) |
Settlements, Derivative Assets | (7) | (33) |
Settlements, Derivative Liabilities | 14 | 17 |
Settlements, Net | 7 | (16) |
Ending Balance, Derivative Assets | 4 | 5 |
Ending Balance, Derivative Liabilities | (5) | (11) |
Ending Balance, Net | $ (1) | $ (6) |
Fair Value Measurements (Det104
Fair Value Measurements (Details 2) - Level 3 $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)MWh$ / MWh | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ 1 | $ (5) | $ 25 |
FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | (1) | (6) | 14 |
NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | (107) | $ (136) | $ (151) |
Model | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | 1 | ||
Model | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | (1) | ||
Model | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Fair Value | $ | $ (107) | ||
Model | Minimum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | (4.20) | ||
Model | Minimum | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | (4.20) | ||
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) | 32.60 | ||
Model | Maximum | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 6.10 | ||
Model | Maximum | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 5.30 | ||
Model | Maximum | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Power (in dollars per MWH) | MWh | 2,984,000 | ||
Power, Regional prices (in dollars per unit) | 33.40 | ||
Model | Weighted Average | FTRs | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 0.80 | ||
Model | Weighted Average | FTRs | FES | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
RTO auction clearing prices (in dollars per unit) | 0.60 | ||
Model | Weighted Average | NUG contracts | |||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | |||
Power (in dollars per MWH) | MWh | 754,000 | ||
Power, Regional prices (in dollars per unit) | 32.80 |
Fair Value Measurements (Det105
Fair Value Measurements (Details 3) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Debt securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | $ 1,735 | $ 1,778 |
Unrealized Gains | 38 | 16 |
Fair Value | 1,773 | 1,794 |
Equity securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 822 | 542 |
Unrealized Gains | 103 | 34 |
Fair Value | 925 | 576 |
FES | Debt securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 847 | 801 |
Unrealized Gains | 27 | 9 |
Fair Value | 874 | 810 |
FES | Equity securities | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ||
Cost Basis | 564 | 354 |
Unrealized Gains | 70 | 24 |
Fair Value | $ 634 | $ 378 |
Fair Value Measurements (Det106
Fair Value Measurements (Details 4) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
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 | $ 1,678 | $ 1,534 | $ 2,133 |
Realized Gains | 170 | 209 | 146 |
Realized Losses | (121) | (191) | (75) |
OTTI | (21) | (102) | (37) |
Interest and Dividend Income | 100 | 101 | 96 |
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 | 717 | 733 | 1,163 |
Realized Gains | 117 | 158 | 113 |
Realized Losses | (69) | (134) | (54) |
OTTI | (19) | (90) | (33) |
Interest and Dividend Income | $ 56 | $ 57 | $ 56 |
Fair Value Measurements (Det107
Fair Value Measurements (Details 5) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
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 | $ 19,885 | $ 20,244 |
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 | 19,829 | 21,519 |
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 | 3,000 | 3,027 |
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 | $ 1,555 | $ 3,121 |
Fair Value Measurements (Det108
Fair Value Measurements (Details Textuals) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value of Financial Instruments [Line Items] | ||
Investment excludes receivables, payables and accrued income | $ (3) | $ 7 |
Cash balance excluded from available for sale securities | 61 | 157 |
Investments not required to be disclosed | 266 | 255 |
FES | ||
Fair Value of Financial Instruments [Line Items] | ||
Investment excludes receivables, payables and accrued income | 2 | 1 |
Cash balance excluded from available for sale securities | $ 44 | $ 139 |
Derivative Instruments (Details
Derivative Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair value of derivatives | ||
Derivative Assets | $ 218 | $ 237 |
Derivative Liabilities | (238) | (281) |
Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 140 | 157 |
Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 78 | 80 |
Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (78) | (106) |
Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (160) | (175) |
Commodity contracts | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 133 | 150 |
Commodity contracts | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 77 | 78 |
Commodity contracts | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (72) | (94) |
Commodity contracts | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (52) | (37) |
FTRs | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 7 | 7 |
FTRs | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 1 |
FTRs | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (6) | (12) |
FTRs | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | 0 | (1) |
NUGs | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 1 | 1 |
NUGs | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (108) | (137) |
FES | ||
Fair value of derivatives | ||
Derivative Assets | 214 | 233 |
Derivative Liabilities | (129) | (142) |
FES | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 137 | 154 |
FES | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 77 | 79 |
FES | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (77) | (104) |
FES | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (52) | (38) |
FES | Commodity contracts | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 133 | 150 |
FES | Commodity contracts | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 77 | 78 |
FES | Commodity contracts | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (72) | (94) |
FES | Commodity contracts | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (52) | (37) |
FES | FTRs | Current Assets | ||
Fair value of derivatives | ||
Derivative Assets | 4 | 4 |
FES | FTRs | Deferred Charges and Other Assets | ||
Fair value of derivatives | ||
Derivative Assets | 0 | 1 |
FES | FTRs | Current Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | (5) | (10) |
FES | FTRs | Noncurrent Liabilities | ||
Fair value of derivatives | ||
Derivative Liabilities | $ 0 | $ (1) |
Derivative Instruments (Deta110
Derivative Instruments (Details 1) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivative Assets | ||
Fair Value | $ 218 | $ 237 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (123) | (133) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 95 | 104 |
Derivative Liabilities | ||
Fair Value | (238) | (281) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 123 | 133 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 1 | 8 |
Net Fair Value | (114) | (140) |
Commodity contracts | ||
Derivative Assets | ||
Fair Value | 210 | 228 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (117) | (125) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 93 | 103 |
Derivative Liabilities | ||
Fair Value | (124) | (131) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 117 | 125 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 1 | 3 |
Net Fair Value | (6) | (3) |
FTRs | ||
Derivative Assets | ||
Fair Value | 7 | 8 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (6) | (8) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 1 | 0 |
Derivative Liabilities | ||
Fair Value | (6) | (13) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 6 | 8 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 5 |
Net Fair Value | 0 | 0 |
NUGs | ||
Derivative Assets | ||
Fair Value | 1 | 1 |
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 | 1 | 1 |
Derivative Liabilities | ||
Fair Value | (108) | (137) |
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 | (108) | (137) |
FES | ||
Derivative Assets | ||
Fair Value | 214 | 233 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (121) | (130) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 93 | 103 |
Derivative Liabilities | ||
Fair Value | (129) | (142) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 121 | 130 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 2 | 9 |
Net Fair Value | (6) | (3) |
FES | Commodity contracts | ||
Derivative Assets | ||
Fair Value | 210 | 228 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (117) | (125) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 93 | 103 |
Derivative Liabilities | ||
Fair Value | (124) | (131) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 117 | 125 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 1 | 3 |
Net Fair Value | (6) | (3) |
FES | FTRs | ||
Derivative Assets | ||
Fair Value | 4 | 5 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | (4) | (5) |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 0 | 0 |
Derivative Liabilities | ||
Fair Value | (5) | (11) |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 4 | 5 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 1 | 6 |
Net Fair Value | $ 0 | $ 0 |
Derivative Instruments (Deta111
Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions | Dec. 31, 2016MWhMMBTU |
Power Contracts | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 18 |
Sales (in MWH or mmBTUs) | 47 |
Net (in MWH or mmBTUs) | (29) |
FTRs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 28 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 28 |
NUGs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 3 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 3 |
Natural Gas | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | MMBTU | 29 |
Sales (in MWH or mmBTUs) | MMBTU | 29 |
Net (in MWH or mmBTUs) | MMBTU | 0 |
FES | Power Contracts | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 18 |
Sales (in MWH or mmBTUs) | 47 |
Net (in MWH or mmBTUs) | (29) |
FES | FTRs | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | 22 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 22 |
FES | Natural Gas | |
Volume of First Energy's outstanding derivative transactions | |
Purchases (in MWH or mmBTUs) | MMBTU | 29 |
Sales (in MWH or mmBTUs) | MMBTU | 29 |
Net (in MWH or mmBTUs) | MMBTU | 0 |
Derivative Instruments (Deta112
Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | $ 218 | $ 161 | $ 62 |
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 | (131) | (130) | 365 |
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 | (9) | 73 | (64) |
Realized Gain (Loss) Reclassified | (35) | (49) | (44) |
Fuel Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | (8) | (34) | (6) |
Interest Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 14 | ||
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 | 210 | 111 | (6) |
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 | (131) | (130) | 365 |
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 | (14) | 93 | (86) |
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 | (8) | (34) | (6) |
Commodity contracts | Interest Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | ||
FTRs | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 8 | 50 | 68 |
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 | 5 | (20) | 22 |
Realized Gain (Loss) Reclassified | (35) | (49) | (44) |
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 |
FTRs | Interest Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | ||
Interest rate swaps | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 0 | ||
Interest rate swaps | 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 | ||
Interest rate swaps | 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 | 0 | ||
Realized Gain (Loss) Reclassified | 0 | ||
Interest rate swaps | 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 | ||
Interest rate swaps | Interest Expense | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 14 | ||
FES | Revenues | |||
Effect of derivative instruments on the statements of income and comprehensive income for instruments not in hedging relationships | |||
Realized Gain (Loss) Reclassified | 218 | 160 | 61 |
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 | (131) | (130) | 365 |
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 | (9) | 74 | (65) |
Realized Gain (Loss) Reclassified | (35) | (49) | (43) |
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 | 210 | 111 | (6) |
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 | (131) | (130) | 365 |
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 | (14) | 93 | (86) |
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 | 8 | 49 | 67 |
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 | 5 | (19) | 21 |
Realized Gain (Loss) Reclassified | $ (35) | $ (49) | $ (43) |
Derivative Instruments (Deta113
Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | $ (135) | $ (140) |
Unrealized loss | (18) | (56) |
Purchases | 4 | 12 |
Settlements | 44 | 49 |
Outstanding net asset (liability), Ending Balance | (105) | (135) |
NUGs | ||
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | (136) | (151) |
Unrealized loss | (15) | (47) |
Purchases | 0 | 0 |
Settlements | 44 | 62 |
Outstanding net asset (liability), Ending Balance | (107) | (136) |
Regulated FTRs | ||
Outstanding net asset (liability) [Roll Forward] | ||
Outstanding net asset (liability), Beginning Balance | 1 | 11 |
Unrealized loss | (3) | (9) |
Purchases | 4 | 12 |
Settlements | 0 | (13) |
Outstanding net asset (liability), Ending Balance | $ 2 | $ 1 |
Derivative Instruments (Deta114
Derivative Instruments (Details Textuals) $ in Millions | 12 Months Ended | |
Dec. 31, 2016USD ($)agreement | Dec. 31, 2015USD ($)agreement | |
Derivative [Line Items] | ||
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements | $ 10 | $ 20 |
Expected adverse change in quoted market prices of derivative instruments | 10.00% | |
Decrease net income due to adverse change in commodity prices | $ 29 | |
NUGs | ||
Derivative [Line Items] | ||
Liability position | 107 | |
FTRs | ||
Derivative [Line Items] | ||
Net asset position under commodity derivative contracts | 1 | |
Collateral posted | 1 | |
Cash Flow Hedges | ||
Derivative [Line Items] | ||
Unamortized gains or (losses) associated with designated cash flow hedges | (12) | (11) |
Unamortized gains or (losses) associated with prior interest rate hedges | (33) | $ (42) |
Gains (losses) to be amortized to interest expenses during next twelve months | $ (8) | |
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 | $ (7) | |
Reclassifications from long-term debt | $ 10 | $ 12 |
Number of fixed-for-floating interest rate swap agreements outstanding | agreement | 0 | 0 |
Interest rate swaps | ||
Derivative [Line Items] | ||
Number of interest rate swaps outstanding | agreement | 0 | 0 |
FES | Commodity contracts | ||
Derivative [Line Items] | ||
Net asset position under commodity derivative contracts | $ 86 | |
Collateral posted | 52 | |
FES | FTRs | ||
Derivative [Line Items] | ||
Collateral posted | 5 | |
FES | Cash Flow Hedges | ||
Derivative [Line Items] | ||
Unamortized gains or (losses) associated with prior interest rate hedges | $ (3) | $ (3) |
Capitalization (Details)
Capitalization (Details) | Dec. 31, 2016$ / 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, 2016 | Dec. 31, 2015 |
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 2,305 | $ 2,098 |
Unsecured debt | 14,258 | 14,872 |
Capital lease obligations | 104 | 132 |
Unamortized debt premiums (discounts) | (25) | (18) |
Unamortized debt issuance costs | (87) | (93) |
Unamortized fair value adjustments | (6) | 5 |
Currently payable long-term debt | (1,685) | (1,166) |
Total long-term debt and other long-term obligations | 18,192 | 19,099 |
FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | 627 | 342 |
Unsecured debt | 2,373 | 2,685 |
Capital lease obligations | 8 | 13 |
Unamortized debt premiums (discounts) | (1) | (1) |
Unamortized debt issuance costs | (15) | (17) |
Currently payable long-term debt | (179) | (512) |
Total long-term debt and other long-term obligations | 2,813 | 2,510 |
FMBs | ||
Schedule of Capitalization [Line Items] | ||
FMBs | $ 3,328 | 3,269 |
FMBs | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.34% | |
FMBs | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 9.74% | |
Secured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 2,295 | 2,096 |
Secured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 0.679% | |
Secured notes - fixed rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 12.00% | |
Secured notes - fixed rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 617 | 340 |
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) | 12.00% | |
Secured notes - variable rate | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 10 | 2 |
Secured notes - variable rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.50% | |
Secured notes - variable rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.50% | |
Secured notes - variable rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Secured notes | $ 10 | 2 |
Secured notes - variable rate | FES | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.50% | |
Secured notes - variable rate | FES | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 3.50% | |
Unsecured notes - fixed rate | ||
Schedule of Capitalization [Line Items] | ||
Unsecured debt | $ 13,058 | 13,580 |
Unsecured notes - fixed rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.15% | |
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 | $ 2,373 | 2,593 |
Unsecured notes - fixed rate | FES | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.15% | |
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 | $ 1,200 | 1,292 |
Unsecured notes - variable rate | Minimum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.34% | |
Unsecured notes - variable rate | Maximum | ||
Schedule of Capitalization [Line Items] | ||
Interest rate (percent) | 2.43% | |
Unsecured notes - variable rate | FES | ||
Schedule of Capitalization [Line Items] | ||
Unsecured debt | $ 0 | $ 92 |
Capitalization (Details 2)
Capitalization (Details 2) $ in Millions | Dec. 31, 2016USD ($) |
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years | |
2,017 | $ 1,641 |
2,018 | 1,702 |
2,019 | 2,266 |
2,020 | 1,231 |
2,021 | 832 |
FES | |
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years | |
2,017 | 163 |
2,018 | 516 |
2,019 | 478 |
2,020 | 667 |
2,021 | $ 774 |
Capitalization (Details 3)
Capitalization (Details 3) $ in Millions | Dec. 31, 2016USD ($) |
Outstanding PCRBs | |
2,017 | $ 1,641 |
2,018 | 1,702 |
2,019 | 2,266 |
2,020 | 1,231 |
2,021 | 832 |
PCRB | |
Outstanding PCRBs | |
2,017 | 130 |
2,018 | 375 |
2,019 | 232 |
2,020 | 490 |
2,021 | 342 |
FES | |
Outstanding PCRBs | |
2,017 | 163 |
2,018 | 516 |
2,019 | 478 |
2,020 | 667 |
2,021 | 774 |
FES | PCRB | |
Outstanding PCRBs | |
2,017 | 130 |
2,018 | 375 |
2,019 | 232 |
2,020 | 490 |
2,021 | $ 342 |
Capitalization (Details Textual
Capitalization (Details Textuals) | Jan. 19, 2017$ / shares | Dec. 13, 2016USD ($)shares | Dec. 06, 2016USD ($) | Oct. 17, 2016USD ($) | Sep. 30, 2016USD ($) | Sep. 15, 2016USD ($) | Aug. 15, 2016USD ($) | Jul. 01, 2016USD ($) | Jun. 01, 2016USD ($) | May 01, 2016USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Sep. 30, 2016$ / shares | Jun. 30, 2016$ / shares | Mar. 31, 2016$ / shares | Dec. 31, 2015USD ($)$ / sharesshares | Sep. 30, 2015$ / shares | Jun. 30, 2015$ / shares | Mar. 31, 2015$ / shares | Dec. 31, 2016USD ($)subsidiary$ / sharesshares | Dec. 31, 2015USD ($)$ / sharesshares | Dec. 31, 2014$ / sharesshares | Dec. 15, 2016USD ($) | Dec. 05, 2016USD ($) | Sep. 23, 2016USD ($) | Jun. 30, 2013USD ($) |
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Retained earnings (accumulated deficit) | $ (4,532,000,000) | $ 2,256,000,000 | $ (4,532,000,000) | $ 2,256,000,000 | |||||||||||||||||||||
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 | |||||||||||||||||||||
Number of subsidiaries that issued environmental control bonds | subsidiary | 2 | ||||||||||||||||||||||||
Environmental control bonds outstanding | $ 406,000,000 | $ 429,000,000 | $ 406,000,000 | $ 429,000,000 | |||||||||||||||||||||
Transition bond outstanding | 85,000,000 | 128,000,000 | 85,000,000 | 128,000,000 | |||||||||||||||||||||
Principal default amount specified in debt covenants | 100,000,000 | ||||||||||||||||||||||||
Currently payable long-term debt | 1,685,000,000 | 1,166,000,000 | 1,685,000,000 | 1,166,000,000 | |||||||||||||||||||||
Subsequent Event | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Dividends declared, in dollars per share | $ / shares | $ 0.36 | ||||||||||||||||||||||||
Phase In Recovery Bonds | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Long-term debt and other long-term obligations | 339,000,000 | 362,000,000 | $ 339,000,000 | 362,000,000 | |||||||||||||||||||||
Term Loan | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 1,200,000,000 | $ 1,000,000,000 | |||||||||||||||||||||||
Term of revolving credit facility | 5 years | ||||||||||||||||||||||||
AGC | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
FERC-defined equity to total capitalization ratio | 45.00% | ||||||||||||||||||||||||
FES | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Retained earnings (accumulated deficit) | (3,509,000,000) | 1,946,000,000 | $ (3,509,000,000) | 1,946,000,000 | |||||||||||||||||||||
Currently payable long-term debt | 179,000,000 | $ 512,000,000 | 179,000,000 | $ 512,000,000 | |||||||||||||||||||||
FG | Loans Payable | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 12,000,000 | $ 12,000,000 | |||||||||||||||||||||||
FG | Loans Payable | Fixed Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Face amount of loan | $ 86,000,000 | 86,000,000 | |||||||||||||||||||||||
FG | Loans Payable | Variable Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | 12,000,000 | ||||||||||||||||||||||||
FG | PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 60,000,000 | $ 225,000,000 | |||||||||||||||||||||||
FG | PCRB | Fixed Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.25% | ||||||||||||||||||||||||
Face amount of loan | $ 100,000,000 | ||||||||||||||||||||||||
FG | Line of Credit | Variable Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Elimination of LOC | 92,000,000 | ||||||||||||||||||||||||
NG | PCRB | 4.375% Fixed PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.375% | ||||||||||||||||||||||||
Face amount of loan | $ 285,000,000 | ||||||||||||||||||||||||
JCP&L | Senior Notes | 5.625% Senior Unsecured Notes Due May 2016 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Repayments of Senior notes | $ 300,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 5.625% | ||||||||||||||||||||||||
WP | FMBs | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 145,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 5.875% | ||||||||||||||||||||||||
Face amount of loan | $ 100,000,000 | ||||||||||||||||||||||||
WP | FMBs | $475M Million First Mortgage Bonds 3.84% Due 2046 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 3.84% | ||||||||||||||||||||||||
Face amount of loan | $ 475,000,000 | ||||||||||||||||||||||||
WP | FMBs | $100M FMBs 3.84% Due 2046 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 3.84% | ||||||||||||||||||||||||
Face amount of loan | $ 100,000,000 | ||||||||||||||||||||||||
WP | FMBs | $100M FMBs 4.09% Due 2047 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.09% | ||||||||||||||||||||||||
Face amount of loan | $ 100,000,000 | ||||||||||||||||||||||||
WP | FMBs | $275M FMBs 4.14% Due 2047 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.14% | ||||||||||||||||||||||||
Face amount of loan | $ 275,000,000 | ||||||||||||||||||||||||
WP | FMBs | $275M FMBs 5.95% Due December 2017 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 275,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 5.95% | 5.95% | |||||||||||||||||||||||
PE | FMBs | $155 M FMBs, 3.89% Due 2046 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 3.89% | ||||||||||||||||||||||||
Face amount of loan | $ 155,000,000 | ||||||||||||||||||||||||
PE | FMBs | $100M FMBs 5.80% Due 2016 | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Debt repaid | $ 100,000,000 | ||||||||||||||||||||||||
Interest rate (percent) | 5.80% | ||||||||||||||||||||||||
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 | 2,685,946 | 2,457,827 | 2,474,011 | ||||||||||||||||||||||
Minimum | FMBs | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 3.34% | 3.34% | |||||||||||||||||||||||
Minimum | FG | PCRB | Fixed Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.25% | ||||||||||||||||||||||||
Face amount of loan | $ 86,000,000 | ||||||||||||||||||||||||
Maximum | FMBs | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 9.74% | 9.74% | |||||||||||||||||||||||
Maximum | FG | PCRB | Fixed Rate PCRB | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Interest rate (percent) | 4.50% | ||||||||||||||||||||||||
Pension Plan [Member] | |||||||||||||||||||||||||
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 | ||||||||||||||||||||||||
Revolving Credit Facility | Parent and Certain Subsidiaries | |||||||||||||||||||||||||
Debt Instrument [Line Items] | |||||||||||||||||||||||||
Term of revolving credit facility | 5 years |
Short-Term Borrowings and Ba120
Short-Term Borrowings and Bank Lines of Credit (Details) - USD ($) | Jan. 31, 2017 | Dec. 31, 2016 | Dec. 06, 2016 | Dec. 05, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Short-term Debt [Line Items] | |||||||
Cash and Cash Equivalents, at Carrying Value | $ 199,000,000 | $ 131,000,000 | $ 85,000,000 | $ 218,000,000 | |||
Subsequent Event | |||||||
Short-term Debt [Line Items] | |||||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | ||||||
Available Liquidity | 2,341,000,000 | ||||||
Cash, Available Liquidity | 308,000,000 | ||||||
Total Available Liquidity | 2,649,000,000 | ||||||
FirstEnergy | |||||||
Short-term Debt [Line Items] | |||||||
Maximum amount borrowed under revolving credit facility | 4,000,000,000 | ||||||
FirstEnergy | Line of Credit | Subsequent Event | |||||||
Short-term Debt [Line Items] | |||||||
Available Liquidity | 1,341,000,000 | ||||||
FET | |||||||
Short-term Debt [Line Items] | |||||||
Maximum amount borrowed under revolving credit facility | 1,000,000,000 | ||||||
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 | 2,000,000 | $ 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 | 502,000,000 | ||||||
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 | $ 500,000,000 | $ 4,000,000,000 | $ 3,500,000,000 | ||||
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 | |||||||
Short-term Debt [Line Items] | |||||||
Maximum amount borrowed under revolving credit facility | $ 1,000,000,000 | 1,000,000,000 | |||||
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 | $ 900,000,000 | ||||||
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 Ba121
Short-Term Borrowings and Bank Lines of Credit (Details 1) | Dec. 31, 2016USD ($) |
FE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | $ 4,000,000,000 |
Regulatory and Other Short-Term Debt Limitations | 0 |
FET | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 1,000,000,000 |
Regulatory and Other Short-Term Debt Limitations | 0 |
OE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
CEI | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
TE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
JCP&L | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 600,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
ME | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 300,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
PN | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 300,000,000 |
Regulatory and Other Short-Term Debt Limitations | 300,000,000 |
WP | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 200,000,000 |
Regulatory and Other Short-Term Debt Limitations | 200,000,000 |
MP | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
PE | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 150,000,000 |
Regulatory and Other Short-Term Debt Limitations | 150,000,000 |
ATSI | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 500,000,000 |
Regulatory and Other Short-Term Debt Limitations | 500,000,000 |
Penn | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 50,000,000 |
Regulatory and Other Short-Term Debt Limitations | 100,000,000 |
TrAIL | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 400,000,000 |
Regulatory and Other Short-Term Debt Limitations | 400,000,000 |
MAIT | |
Borrowing sub-limits for each borrower and limitations on short-term indebtedness | |
Revolving Credit Facility Sub-Limits | 400,000,000 |
Regulatory and Other Short-Term Debt Limitations | $ 400,000,000 |
Short-Term Borrowings and Ba122
Short-Term Borrowings and Bank Lines of Credit (Details 2) | Dec. 31, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | ||
Weighted average interest rate | 2.47% | 2.16% |
Short-Term Borrowings and Ba123
Short-Term Borrowings and Bank Lines of Credit (Details Textuals) | Feb. 16, 2017USD ($)agreement | Dec. 06, 2016USD ($)distribution_utility | Dec. 31, 2016USD ($)money_pool | Dec. 31, 2021 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Jan. 31, 2017USD ($) | Dec. 05, 2016USD ($) | Dec. 31, 2015USD ($) |
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Number of regulated distribution utilities | distribution_utility | 10 | |||||||||
Short-term borrowings | $ 2,675,000,000 | $ 1,708,000,000 | ||||||||
Number of money pools | money_pool | 2 | |||||||||
Average interest rate for borrowings | 2.47% | 2.16% | ||||||||
Subsequent Event | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | $ 5,000,000,000 | |||||||||
Term Loan | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Term of revolving credit facility | 5 years | |||||||||
Face amount of loan | $ 1,200,000,000 | $ 1,000,000,000 | ||||||||
Term Loan | Prime Rate | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Variable rate (percent) | 0.50% | |||||||||
Term Loan | LIBOR | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Variable rate (percent) | 1.00% | |||||||||
Term Loan | Subsequent Event | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Debt Instrument, Number of Agreements | agreement | 2 | |||||||||
Term Loan | Variable Rate Term Loan Due 2016 | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Face amount of loan | 200,000,000 | |||||||||
Term Loan | $125M Term Loan | Bank of America N.A. | Subsequent Event | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Term of revolving credit facility | 3 years | |||||||||
Face amount of loan | $ 125,000,000 | |||||||||
Term Loan | $125M Term Loan | The Bank of Nova Scotia | Subsequent Event | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Term of revolving credit facility | 3 years | |||||||||
Face amount of loan | $ 125,000,000 | |||||||||
FET | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | $ 1,000,000,000 | |||||||||
FES | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Short-term borrowings | 0 | $ 8,000,000 | ||||||||
FES | Affiliates | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Other Short-term Borrowings | 101,000,000 | $ 0 | ||||||||
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 | |||||||||
NG | FMBs | $450M FMB's | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Face amount of loan | 450,000,000 | |||||||||
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 | $ 4,000,000,000 | 500,000,000 | 3,500,000,000 | |||||||
Increase in borrowing capacity | 500,000,000 | |||||||||
Cross-default provision for other indebtedness | 100,000,000 | |||||||||
Amounts excluded from capitalization ratio | $ 2,750,000,000 | |||||||||
Line of Credit | Revolving Credit Facility | Minimum | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Consolidated debt to total capitalization ratio (percent) | 65.00% | |||||||||
Line of Credit | Revolving Credit Facility | Minimum | Forecast | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Interest coverage ratio (percent) | 2.5 | 2.25 | 2 | 1.75 | ||||||
Line of Credit | Revolving Credit Facility | Maximum | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Consolidated debt to total capitalization ratio (percent) | 100.00% | |||||||||
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 | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | $ 1,000,000,000 | 1,000,000,000 | ||||||||
Line of Credit | Revolving Credit Facility | FET | Minimum | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Consolidated debt to total capitalization ratio (percent) | 75.00% | |||||||||
Line of Credit | Revolving Credit Facility | FET | Maximum | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Consolidated debt to total capitalization ratio (percent) | 100.00% | |||||||||
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 and AE Supply | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | 1,500,000,000 | |||||||||
Amounts excluded from capitalization ratio | $ 5,500,000,000 | |||||||||
Line of Credit | Revolving Credit Facility | FES | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | 900,000,000 | |||||||||
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 | Revolving Credit Facility | AE Supply | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Maximum amount borrowed under revolving credit facility | $ 600,000,000 | |||||||||
Line of Credit | Revolving Credit Facility | FE and FET | Prime Rate | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Variable rate (percent) | 0.50% | |||||||||
Line of Credit | Revolving Credit Facility | FE and FET | LIBOR | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Variable rate (percent) | 1.00% | |||||||||
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 | |||||||||
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 | |||||||||
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 | 0.69% | |||||||||
Money Pool | Unregulated Companies | ||||||||||
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract] | ||||||||||
Average interest rate for borrowings | 2.02% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | Jun. 30, 2016 | May 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 |
Asset Retirement Obligations [Line Items] | ||||
Nuclear plant decommissioning trusts | $ 2,514 | $ 2,282 | ||
Fair value of decommissioning trust assets | 2,282 | |||
Changes to the asset retirement obligations | ||||
Beginning Balance | 1,410 | 1,387 | ||
Liabilities settled | (27) | (13) | ||
Accretion | 95 | 92 | ||
Revisions in estimated cash flows | (4) | 56 | ||
Ending Balance | 1,482 | 1,410 | ||
FES | ||||
Asset Retirement Obligations [Line Items] | ||||
Nuclear plant decommissioning trusts | 1,552 | 1,327 | ||
Fair value of decommissioning trust assets | 1,327 | |||
Changes to the asset retirement obligations | ||||
Beginning Balance | 831 | 841 | ||
Liabilities settled | (18) | (8) | ||
Accretion | 56 | 55 | ||
Revisions in estimated cash flows | (32) | 57 | ||
Ending Balance | 901 | 831 | ||
FES | Beaver Valley, Davis-Besse and Perry Nuclear Generating Stations | ||||
Changes to the asset retirement obligations | ||||
Ending Balance | 713 | |||
FES | Davis-Besse and Perry Nuclear Generating Stations | ||||
Changes to the asset retirement obligations | ||||
Revisions in estimated cash flows | $ 57 | |||
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 | Dec. 12, 2016USD ($) | Nov. 02, 2016USD ($) | Apr. 28, 2016USD ($) | Jul. 16, 2015 | Feb. 27, 2013USD ($) | Dec. 31, 2016componentbasic_generation_service | Dec. 31, 2016USD ($)componentbasic_generation_service | Dec. 31, 2017USD ($) |
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 | ||||||
Number of BGS | basic_generation_service | 1 | 1 | ||||||
PE | Maryland | ||||||||
Regulatory Matters [Line Items] | ||||||||
Expenditures for cost recovery program incurred | $ 43 | |||||||
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% | |||||||
Amortization period for expenditures for cost recovery program | 5 years | |||||||
JCP&L | New Jersey | NJBPU | ||||||||
Regulatory Matters [Line Items] | ||||||||
Requested rate increase (decrease) | $ 142.1 | |||||||
Requested increase in revenues | $ 80 | |||||||
Public Utilities, Approved Annual Increase to Accelerated Amortization | $ 19 | |||||||
Forecast | PE | Maryland | ||||||||
Regulatory Matters [Line Items] | ||||||||
Expenditures for cost recovery program | $ 70 |
Regulatory Matters - Ohio (Deta
Regulatory Matters - Ohio (Details) $ in Millions | Nov. 14, 2016USD ($) | Oct. 12, 2016USD ($) | Apr. 15, 2016 | Aug. 07, 2013USD ($)auction | Sep. 30, 2016 | Dec. 31, 2016USD ($)MWh |
Regulatory Matters [Line Items] | ||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | |||||
Ohio | ||||||
Regulatory Matters [Line Items] | ||||||
Annual energy savings | MWh | 1,990 | |||||
EEPP term of plan | 3 years | |||||
Portfolio plan estimated cost | $ 268 | |||||
Credit to non-shopping customers | $ 43.4 | |||||
Ohio | Year 2015 | ||||||
Regulatory Matters [Line Items] | ||||||
Annual energy savings | MWh | 486 | |||||
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 | 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 | Energy Conservation, Economic Development and Job Retention | ||||||
Regulatory Matters [Line Items] | ||||||
Contribution amount | $ 51 |
Regulatory Matters - Pennsylvan
Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Thousands | Dec. 09, 2016USD ($) | Nov. 21, 2016brief | Oct. 14, 2016USD ($)proceedingParty | Sep. 28, 2016USD ($) | Aug. 22, 2016USD ($) | Aug. 16, 2016USD ($) | Aug. 05, 2016MW | Apr. 28, 2016USD ($) | Nov. 03, 2015proposal | Oct. 19, 2015USD ($) | Jun. 19, 2015 | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)proposalprogram | Dec. 31, 2027MW | Dec. 31, 2020MW | Feb. 03, 2017Party | Dec. 01, 2016Party |
Pennsylvania | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Project term | 2 years | 2 years | ||||||||||||||||
Number of requests for proposal | proposal | 1,000,000 | 1 | ||||||||||||||||
Pennsylvania | 3 Month Period | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Energy contract term | 3 months | |||||||||||||||||
Pennsylvania | 12 Month Period | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Energy contract term | 12 months | 12 months | ||||||||||||||||
Pennsylvania | 24 Month Period | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Energy contract term | 24 months | 24 months | ||||||||||||||||
Pennsylvania | Unfavorable Regulatory Action | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Potential cost of compliance | $ 174,000 | |||||||||||||||||
Pennsylvania | ME | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | $ 140,200 | |||||||||||||||||
Interim amount of rate increase (decrease) | $ 96,000 | |||||||||||||||||
Pennsylvania | Penn | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | 42,000 | |||||||||||||||||
Interim amount of rate increase (decrease) | 29,000 | |||||||||||||||||
Pennsylvania | WP | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | 98,200 | |||||||||||||||||
Interim amount of rate increase (decrease) | 66,000 | |||||||||||||||||
Pennsylvania | PN | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | $ 158,800 | |||||||||||||||||
Interim amount of rate increase (decrease) | $ 100,000 | |||||||||||||||||
Pennsylvania | PPUC | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
LTIP recovery period | 5 years | |||||||||||||||||
Pennsylvania | PPUC | DSIC | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Loss Contingency, Pending Proceedings, Number Consolidated | proceeding | 4 | |||||||||||||||||
Pennsylvania | PPUC | DSIC Rates | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Public Utilities, Number of Parties Who Filed A Brief | Party | 2 | 1 | ||||||||||||||||
Loss Contingency, Claims Dismissed, Number | brief | 1 | |||||||||||||||||
Pennsylvania | PPUC | ME | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Proposed ROE (percent) | 1.80% | |||||||||||||||||
Energy consumption reduction targets (percent) | 4.00% | |||||||||||||||||
Requested rate increase (decrease) | $ 43,440 | |||||||||||||||||
Pennsylvania | PPUC | Penn | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Proposed ROE (percent) | 1.70% | |||||||||||||||||
Energy consumption reduction targets (percent) | 3.30% | |||||||||||||||||
Requested rate increase (decrease) | 56,350 | |||||||||||||||||
Pennsylvania | PPUC | WP | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Proposed ROE (percent) | 1.80% | |||||||||||||||||
Energy consumption reduction targets (percent) | 2.60% | |||||||||||||||||
Requested rate increase (decrease) | 88,340 | |||||||||||||||||
Pennsylvania | PPUC | PN | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Proposed ROE (percent) | 0.00% | |||||||||||||||||
Energy consumption reduction targets (percent) | 3.90% | |||||||||||||||||
Requested rate increase (decrease) | $ 56,740 | |||||||||||||||||
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 | $ 10,400 | |||||||||||||||||
Minimum energy requirement to file and implement a RFP (in MW's) | MW | 100 | |||||||||||||||||
Actual under-recovery balance | $ 119,000 | |||||||||||||||||
West Virginia | WVPSC | MP and PE | ENEC | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | $ 65,000 | |||||||||||||||||
Requested rate increase (decrease) (percent) | 4.70% | |||||||||||||||||
Approved amount of rate increase | $ 25,000 | |||||||||||||||||
Rate stability period | 2 years | |||||||||||||||||
West Virginia | WVPSC | MP and PE | ENEC | Forecast | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Projected over-recovery amount | $ 54,000 | |||||||||||||||||
West Virginia | WVPSC | MP and PE | Modernization and Improvement Plan for Coal-Fired Boilers | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | $ 6,900 | |||||||||||||||||
Requested rate increase (decrease) (percent) | 0.50% | |||||||||||||||||
West Virginia | WVPSC | MP and PE | Accelerated Recovery Costs For Modernizing and Improving Coal-Fired Boilers | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Requested rate increase (decrease) | $ 7,400 | |||||||||||||||||
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 | |||||||||||||||||
Subsequent Event | Pennsylvania | PPUC | DSIC Rates | ||||||||||||||||||
Regulatory Matters [Line Items] | ||||||||||||||||||
Public Utilities, Number of Parties Who Filed A Brief | Party | 1 |
Regulatory Matters - Reliabilit
Regulatory Matters - Reliability and FERC Matters (Details) $ in Millions | Feb. 20, 2017 | Feb. 17, 2017USD ($)Natural_gas_plant | Jan. 19, 2017 | Jan. 18, 2017USD ($)Natural_gas_plantMW | Aug. 24, 2016USD ($) | Aug. 24, 2012USD ($) | Apr. 30, 2007kv | Dec. 31, 2016USD ($)entityMW |
Regulatory Matters [Line Items] | ||||||||
Regional enforcement entities | entity | 8 | |||||||
FERC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Power threshold for cost methodology (in KW) | kv | 500 | |||||||
Denied recovery charges of exit fees | $ | $ 78.8 | |||||||
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% | |||||||
ROE granted for RTO's (percent) | 0.50% | |||||||
Remaining recovery period of regulatory assets | 5 years | |||||||
Settled Litigation | California Claims Matters | FERC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Settlement amount | $ | $ 3.6 | |||||||
Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 1,572 | |||||||
Subsequent Event | PATH | FERC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Base ROE (percent) | 10.40% | 8.11% | ||||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Cash purchase price | $ | $ 925 | $ 925 | ||||||
Plant generation capacity (in MW's) | 1,572 | |||||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | AE Supply | ||||||||
Regulatory Matters [Line Items] | ||||||||
Number of gas generating plants | Natural_gas_plant | 4 | 4 | ||||||
Springdale Generating Facility Units 1-5 | Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 638 | |||||||
Chamberburg Generating Facility Units 12-13 | Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 88 | |||||||
Gans Generating Facility Units 8-9 | Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 88 | |||||||
Hunlock Creek | Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 45 | |||||||
Bath County Hydro | Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||||
Regulatory Matters [Line Items] | ||||||||
Plant generation capacity (in MW's) | 713 |
Commitments, Guarantees and 129
Commitments, Guarantees and Contingencies (Details) $ in Millions | Dec. 31, 2016USD ($) |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 425 |
Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 150 |
FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 247 |
AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 28 |
At Current Credit Rating | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 10 |
At Current Credit Rating | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 0 |
At Current Credit Rating | FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 7 |
At Current Credit Rating | AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 3 |
Upon Further Downgrade | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 48 |
Upon Further Downgrade | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 48 |
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 | 367 |
Surety Bond | Regulated Distribution | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 102 |
Surety Bond | FES | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | 240 |
Surety Bond | AE Supply | |
Guarantor Obligations [Line Items] | |
Potential additional collateral obligations | $ 25 |
Commitments, Guarantees and 130
Commitments, Guarantees and Contingencies - Nuclear Insurance, Commitments and Collateral (Details) $ in Millions | Dec. 06, 2016 | Dec. 31, 2016USD ($)Nuclear_Power_Plant |
Loss Contingencies [Line Items] | ||
Liability assessed with respect to single nuclear incident | $ 13,300 | |
Plants licensed to operate | Nuclear_Power_Plant | 102 | |
Portion of insurance coverage of private insurer included in single nuclear incident | $ 375 | |
Portion of insurance coverage by industry retrospective rating plan | 13,000 | |
Losses in excess of private insurance contributed for each nuclear unit license | 127 | |
Losses in excess of private insurance contributed for each nuclear unit license per unit | 19 | |
Nuclear incidence liability per incident of parent and subsidiary companys based on their present nuclear ownership and leasehold interests | 509 | |
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 | |
Aggregate indemnity | $ 1,400 | |
Waiting period | 140 days | |
Coverage of decontamination costs | $ 2,750 | |
Insurance coverage for replacement power costs | $ 1,060 | |
Environmental plan, submission period | 30 days | |
Outstanding guarantees and other assurances aggregated | $ 3,300 | |
FE | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 581 | |
Subsidiaries' Guarantees | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 1,933 | |
Other Guarantees | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 300 | |
Other Assurances | ||
Loss Contingencies [Line Items] | ||
Outstanding guarantees and other assurances aggregated | 465 | |
Regulated Distribution | ||
Loss Contingencies [Line Items] | ||
Company posted collateral related to net liability positions | 3 | |
NG | ||
Loss Contingencies [Line Items] | ||
Nuclear incidence liability per incident of parent and subsidiary companys based on their present nuclear ownership and leasehold interests | 506 | |
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 | 75 | |
Aggregate indemnity | $ 1,390 | |
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 | $ 190 | |
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 | $ 300 | |
AE Supply | ||
Loss Contingencies [Line Items] | ||
Company posted collateral related to net liability positions | $ 4 | |
Revolving Credit Facility | Parent and Certain Subsidiaries | ||
Loss Contingencies [Line Items] | ||
Term of revolving credit facility | 5 years |
Commitments, Guarantees and 131
Commitments, Guarantees and Contingencies - Clean Air Act and Climate Change (Details) $ in Millions | Oct. 01, 2015 | Aug. 03, 2015T | Sep. 30, 2016 | Dec. 31, 2016USD ($)phaseT | Dec. 31, 2014USD ($) | Dec. 31, 2016USD ($)T | Nov. 12, 2014 |
Loss Contingencies [Line Items] | |||||||
Proposed reduction in power plants carbon pollution (percent) | 90.00% | ||||||
FES | |||||||
Loss Contingencies [Line Items] | |||||||
Amount of damages paid | $ 70 | ||||||
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 | ||||||
Hazardous Air Pollutant Emissions | |||||||
Loss Contingencies [Line Items] | |||||||
Potential cost of compliance, MATS | $ 345 | $ 345 | |||||
Hazardous Air Pollutant Emissions | CES | |||||||
Loss Contingencies [Line Items] | |||||||
Potential cost of compliance, MATS | 168 | 168 | |||||
Hazardous Air Pollutant Emissions | Regulated Distribution | |||||||
Loss Contingencies [Line Items] | |||||||
Potential cost of compliance, MATS | $ 177 | 177 | |||||
Caa Compliance | |||||||
Loss Contingencies [Line Items] | |||||||
Loss in period | $ 286 | ||||||
Mass remaining under contract | T | 5,500,000 | 5,500,000 | |||||
Caa Compliance | CES | |||||||
Loss Contingencies [Line Items] | |||||||
Loss in period | $ 125 | ||||||
Caa Compliance | Regulated Distribution | |||||||
Loss Contingencies [Line Items] | |||||||
Loss in period | $ 161 | ||||||
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% | 69.99% |
Commitments, Guarantees and 132
Commitments, Guarantees and Contingencies - Clean Water Act and Regulation of Waste Disposal (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($) | Dec. 31, 2015 | Apr. 19, 2013option | |
Loss Contingencies [Line Items] | |||
Number of treatment options | option | 8 | ||
Number of preferred treatment options | option | 4 | ||
Renewal cycle of waste water discharge permit | 5 years | ||
Clean Water Act | |||
Loss Contingencies [Line Items] | |||
Annual percentage that fish impingement should be reduced to, per CWA | 12.00% | ||
TMDL limit development period | 5 years | ||
Regulation of Waste Disposal | |||
Loss Contingencies [Line Items] | |||
Accrual for environmental loss contingencies | $ 137 | ||
Environmental liabilities former gas facilities | 89 | ||
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 133
Commitments, Guarantees and Contingencies - Other Legal Proceedings (Details) - USD ($) | Dec. 31, 2016 | Dec. 06, 2016 | Dec. 05, 2016 | Dec. 31, 2015 |
Loss Contingencies [Line Items] | ||||
Nuclear plant decommissioning trusts | $ 2,514,000,000 | $ 2,282,000,000 | ||
Parental support agreement | 3,300,000,000 | |||
Nuclear Plant Matters | ||||
Loss Contingencies [Line Items] | ||||
Nuclear plant decommissioning trusts | 2,500,000,000 | |||
Additions to parental guarantee associated with funding of decommissioning costs | 25,000,000 | |||
NG | Nuclear Plant Matters | ||||
Loss Contingencies [Line Items] | ||||
Nuclear plant decommissioning trusts | 10,000,000 | |||
FES | ||||
Loss Contingencies [Line Items] | ||||
Nuclear plant decommissioning trusts | 1,552,000,000 | $ 1,327,000,000 | ||
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 | 500,000,000 | $ 4,000,000,000 | $ 3,500,000,000 | |
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 | $ 900,000,000 |
Transactions With Affiliated134
Transactions With Affiliated Companies (Details) - FES T in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)T | Dec. 31, 2015USD ($)T | Dec. 31, 2014USD ($)T | |
Investment Income: | |||
Interest income from FE | $ 2 | $ 2 | $ 3 |
Interest Expense: | |||
Interest expense to affiliates | 5 | 4 | 3 |
Interest expense to FE | 2 | 3 | 4 |
AE Supply | |||
REVENUES: | |||
Revenues | $ 80.4 | $ 62.8 | $ 96.3 |
Interest Expense: | |||
Amount of coal sold under purchase agreement (in T) | T | 1.5 | 1.2 | 1.7 |
Electric sales to affiliates | |||
REVENUES: | |||
Revenues | $ 457 | $ 664 | $ 861 |
Other | |||
REVENUES: | |||
Revenues | 11 | 14 | 15 |
Purchased power from affiliates | |||
Expenses: | |||
Expenses | 622 | 353 | 271 |
Fuel | |||
Expenses: | |||
Expenses | 4 | 1 | 1 |
Support services | |||
Expenses: | |||
Expenses | 748 | 705 | 619 |
Pension and OPEB mark-to-market adjustment | |||
Expenses: | |||
Expenses | $ 71 | $ 76 | $ 257 |
Supplemental Guarantor Infor135
Supplemental Guarantor Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | $ 3,375 | $ 3,917 | $ 3,401 | $ 3,869 | $ 3,541 | $ 4,123 | $ 3,465 | $ 3,897 | $ 14,562 | [1] | $ 15,026 | [1] | $ 15,049 | [1] |
OPERATING EXPENSES: | ||||||||||||||
Fuel | 1,666 | 1,855 | 2,280 | |||||||||||
Purchased power | 3,813 | 4,318 | 4,716 | |||||||||||
Other operating expenses | 1,023 | 953 | 964 | 918 | 950 | 842 | 900 | 1,057 | 3,858 | 3,749 | 3,962 | |||
Pension and OPEB mark-to-market adjustment | 147 | 0 | 0 | 0 | 242 | 0 | 0 | 0 | 147 | 242 | 835 | |||
Provision for depreciation | 339 | 311 | 334 | 329 | 313 | 328 | 322 | 319 | 1,313 | 1,282 | 1,220 | |||
General taxes | 1,042 | 978 | 962 | |||||||||||
Impairment of assets | 9,218 | 0 | 1,447 | 0 | 18 | 8 | 16 | 0 | 10,665 | 42 | 0 | |||
Total operating expenses | 22,824 | 12,734 | 13,987 | |||||||||||
OPERATING INCOME (LOSS) | (8,924) | 861 | (975) | 776 | 236 | 908 | 554 | 594 | (8,262) | 2,292 | 1,062 | |||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | 84 | (22) | 72 | |||||||||||
Interest expense | (1,157) | (1,132) | (1,081) | |||||||||||
Capitalized financing costs | 103 | 117 | 118 | |||||||||||
Total other expense | (970) | (1,399) | (891) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (9,232) | 893 | 171 | |||||||||||
INCOME TAXES (BENEFITS) | (3,389) | 251 | (130) | 213 | (170) | 226 | 115 | 144 | (3,055) | 315 | (42) | |||
INCOME (LOSS) FROM CONTINUING OPERATIONS | (6,177) | 578 | 213 | |||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | 0 | 86 | |||||||||||
NET INCOME (LOSS) | (5,796) | 380 | (1,089) | 328 | (226) | 395 | 187 | 222 | (6,177) | 578 | 299 | |||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | (5,796) | 380 | (1,089) | 328 | (226) | 395 | 187 | 222 | (6,177) | 578 | 299 | |||
Pension and OPEB prior service costs | (59) | (116) | (76) | |||||||||||
Amortized gain on derivative hedges | 8 | 5 | (2) | |||||||||||
Change in unrealized gain on available-for-sale securities | 55 | (11) | 26 | |||||||||||
Other comprehensive income (loss) | 4 | (122) | (52) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | 1 | (47) | (14) | |||||||||||
Other comprehensive income (loss), net of tax | 3 | (75) | (38) | |||||||||||
Tax effect of discontinued operations | 0 | 0 | 69 | |||||||||||
Eliminations | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | (3,587) | (3,758) | (3,920) | |||||||||||
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 | (3) | (3) | (3) | |||||||||||
General taxes | 0 | 0 | 0 | |||||||||||
Impairment of assets | (83) | 0 | ||||||||||||
Total operating expenses | (3,624) | (3,712) | (3,874) | |||||||||||
OPERATING INCOME (LOSS) | 37 | (46) | (46) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | 4,538 | (870) | (799) | |||||||||||
Miscellaneous income | 0 | 0 | 0 | |||||||||||
Capitalized financing costs | 0 | 0 | 0 | |||||||||||
Total other expense | 4,652 | (778) | (724) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | 4,689 | (824) | (770) | |||||||||||
INCOME TAXES (BENEFITS) | 35 | 15 | 6 | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | (776) | |||||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | |||||||||||||
NET INCOME (LOSS) | 4,654 | (839) | (776) | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | 4,654 | (839) | (776) | |||||||||||
Pension and OPEB prior service costs | 14 | 5 | 5 | |||||||||||
Amortized gain on derivative hedges | 0 | 0 | 0 | |||||||||||
Change in unrealized gain on available-for-sale securities | (52) | 8 | (21) | |||||||||||
Other comprehensive income (loss) | (38) | 13 | (16) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | (15) | 5 | (6) | |||||||||||
Other comprehensive income (loss), net of tax | (23) | 8 | (10) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | 4,631 | (831) | (786) | |||||||||||
Eliminations | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | (3,587) | (3,758) | (3,920) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | 57 | 34 | 15 | |||||||||||
Eliminations | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | 57 | 58 | 60 | |||||||||||
FES | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 4,242 | 4,824 | 5,990 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 0 | 0 | 0 | |||||||||||
Other operating expenses | 310 | 378 | 790 | |||||||||||
Pension and OPEB mark-to-market adjustment | (1) | (8) | 19 | |||||||||||
Provision for depreciation | 13 | 12 | 10 | |||||||||||
General taxes | 31 | 45 | 72 | |||||||||||
Impairment of assets | 39 | 21 | ||||||||||||
Total operating expenses | 5,436 | 5,958 | 7,578 | |||||||||||
OPERATING INCOME (LOSS) | (1,194) | (1,134) | (1,588) | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | (4,585) | 844 | 791 | |||||||||||
Miscellaneous income | 4 | 1 | 2 | |||||||||||
Capitalized financing costs | 0 | 0 | 0 | |||||||||||
Total other expense | (4,686) | 764 | 725 | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (5,880) | (370) | (863) | |||||||||||
INCOME TAXES (BENEFITS) | (425) | (452) | (619) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | (244) | |||||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | |||||||||||||
NET INCOME (LOSS) | (5,455) | 82 | (244) | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | (5,455) | 82 | (244) | |||||||||||
Pension and OPEB prior service costs | (14) | (6) | (6) | |||||||||||
Amortized gain on derivative hedges | 0 | (3) | (10) | |||||||||||
Change in unrealized gain on available-for-sale securities | 52 | (9) | 21 | |||||||||||
Other comprehensive income (loss) | 38 | (18) | 5 | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | 15 | (7) | 2 | |||||||||||
Other comprehensive income (loss), net of tax | 23 | (11) | 3 | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (5,432) | 71 | (241) | |||||||||||
FES | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 4,024 | 3,826 | 3,920 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (50) | (29) | (12) | |||||||||||
FES | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 1,020 | 1,684 | 2,767 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (55) | (52) | (56) | |||||||||||
FG | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 1,739 | 1,801 | 1,902 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 582 | 679 | 1,055 | |||||||||||
Other operating expenses | 286 | 273 | 269 | |||||||||||
Pension and OPEB mark-to-market adjustment | (4) | 10 | 90 | |||||||||||
Provision for depreciation | 120 | 124 | 119 | |||||||||||
General taxes | 30 | 26 | 31 | |||||||||||
Impairment of assets | 3,937 | 2 | ||||||||||||
Total operating expenses | 4,951 | 1,114 | 1,568 | |||||||||||
OPERATING INCOME (LOSS) | (3,212) | 687 | 334 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | 30 | 17 | 8 | |||||||||||
Miscellaneous income | 3 | 2 | 4 | |||||||||||
Capitalized financing costs | 8 | 6 | 4 | |||||||||||
Total other expense | (74) | (87) | (92) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (3,286) | 600 | 242 | |||||||||||
INCOME TAXES (BENEFITS) | (1,169) | 224 | 87 | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | 155 | |||||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 116 | |||||||||||||
NET INCOME (LOSS) | (2,117) | 376 | 271 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | (2,117) | 376 | 271 | |||||||||||
Pension and OPEB prior service costs | (14) | (5) | (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) | (14) | (5) | (5) | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | (5) | (2) | (2) | |||||||||||
Other comprehensive income (loss), net of tax | (9) | (3) | (3) | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (2,126) | 373 | 268 | |||||||||||
FG | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (10) | (8) | (6) | |||||||||||
FG | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 4 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (105) | (104) | (102) | |||||||||||
NG | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 2,004 | 2,138 | 2,172 | |||||||||||
OPERATING EXPENSES: | ||||||||||||||
Fuel | 198 | 192 | 198 | |||||||||||
Other operating expenses | 632 | 608 | 527 | |||||||||||
Pension and OPEB mark-to-market adjustment | 53 | 55 | 188 | |||||||||||
Provision for depreciation | 206 | 191 | 193 | |||||||||||
General taxes | 27 | 27 | 25 | |||||||||||
Impairment of assets | 4,729 | 10 | ||||||||||||
Total operating expenses | 6,032 | 1,368 | 1,402 | |||||||||||
OPERATING INCOME (LOSS) | (4,028) | 770 | 770 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | 84 | (5) | 61 | |||||||||||
Miscellaneous income | 0 | 0 | 0 | |||||||||||
Capitalized financing costs | 26 | 29 | 30 | |||||||||||
Total other expense | 62 | (29) | 33 | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (3,966) | 741 | 803 | |||||||||||
INCOME TAXES (BENEFITS) | (1,429) | 278 | 298 | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | 505 | |||||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | |||||||||||||
NET INCOME (LOSS) | (2,537) | 463 | 505 | |||||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | (2,537) | 463 | 505 | |||||||||||
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 | 52 | (8) | 21 | |||||||||||
Other comprehensive income (loss) | 52 | (8) | 21 | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | 20 | (3) | 8 | |||||||||||
Other comprehensive income (loss), net of tax | 32 | (5) | 13 | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (2,505) | 458 | 518 | |||||||||||
NG | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 187 | 285 | 271 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (4) | (4) | (4) | |||||||||||
NG | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 0 | 0 | 0 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (44) | (49) | (54) | |||||||||||
FES | ||||||||||||||
Consolidating Statements of Income | ||||||||||||||
REVENUES | 997 | 1,100 | 1,102 | 1,199 | 1,171 | 1,338 | 1,119 | 1,377 | 4,398 | [2] | 5,005 | [2] | 6,144 | [2] |
OPERATING EXPENSES: | ||||||||||||||
Fuel | 780 | 871 | 1,253 | |||||||||||
Other operating expenses | 352 | 316 | 369 | 240 | 312 | 246 | 337 | 413 | 1,277 | 1,308 | 1,635 | |||
Pension and OPEB mark-to-market adjustment | 48 | 0 | 0 | 0 | 57 | 0 | 0 | 0 | 48 | 57 | 297 | |||
Provision for depreciation | 86 | 83 | 84 | 83 | 84 | 79 | 81 | 80 | 336 | 324 | 319 | |||
General taxes | 88 | 98 | 128 | |||||||||||
Impairment of assets | 8,082 | 0 | 540 | 0 | 17 | 0 | 16 | 0 | 8,622 | 33 | 0 | |||
Total operating expenses | 12,795 | 4,728 | 6,674 | |||||||||||
OPERATING INCOME (LOSS) | (8,153) | 101 | (571) | 226 | 25 | 240 | 0 | 12 | (8,397) | 277 | (530) | |||
OTHER INCOME (EXPENSE): | ||||||||||||||
Investment income (loss), including net income from equity investees | 67 | (14) | 61 | |||||||||||
Miscellaneous income | 7 | 3 | 6 | |||||||||||
Capitalized financing costs | 34 | 35 | 34 | |||||||||||
Total other expense | (46) | (130) | (58) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (BENEFITS) | (8,443) | 147 | (588) | |||||||||||
INCOME TAXES (BENEFITS) | (2,983) | 56 | (143) | 82 | 1 | 70 | (4) | (2) | (2,988) | 65 | (228) | |||
INCOME (LOSS) FROM CONTINUING OPERATIONS | (5,455) | 82 | (360) | |||||||||||
Discontinued operations (net of income taxes of $69) (Note 20) | 0 | 0 | 116 | |||||||||||
NET INCOME (LOSS) | (5,188) | 40 | (438) | 131 | (14) | 120 | (21) | (3) | (5,455) | 82 | (244) | |||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | ||||||||||||||
NET INCOME (LOSS) | $ (5,188) | $ 40 | $ (438) | $ 131 | $ (14) | $ 120 | $ (21) | $ (3) | (5,455) | 82 | (244) | |||
Pension and OPEB prior service costs | (14) | (6) | (6) | |||||||||||
Amortized gain on derivative hedges | 0 | (3) | (10) | |||||||||||
Change in unrealized gain on available-for-sale securities | 52 | (9) | 21 | |||||||||||
Other comprehensive income (loss) | 38 | (18) | 5 | |||||||||||
Income taxes (benefits) on other comprehensive income (loss ) | 15 | (7) | 2 | |||||||||||
Other comprehensive income (loss), net of tax | 23 | (11) | 3 | |||||||||||
COMPREHENSIVE INCOME (LOSS) | (5,432) | 71 | (241) | |||||||||||
Tax effect of discontinued operations | 0 | 0 | 70 | |||||||||||
FES | Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 624 | 353 | 271 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | (7) | (7) | (7) | |||||||||||
FES | Non-Affiliates | ||||||||||||||
OPERATING EXPENSES: | ||||||||||||||
Purchased power | 1,020 | 1,684 | 2,771 | |||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||
Interest expense | $ (147) | $ (147) | $ (152) | |||||||||||
[1] | Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively. | |||||||||||||
[2] | Includes excise tax collections of $28 million, $44 million and $69 million in 2016, 2015 and 2014, respectively. |
Supplemental Guarantor Infor136
Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
CURRENT ASSETS: | ||||
Cash and cash equivalents | $ 199 | $ 131 | $ 85 | $ 218 |
Receivables- | ||||
Customers | 1,440 | 1,415 | ||
Other Receivables | 175 | 180 | ||
Materials and supplies, at average cost | 564 | 785 | ||
Derivatives | 140 | 157 | ||
Collateral | 176 | 70 | ||
Prepayments and other | 158 | 167 | ||
Total current assets | 2,950 | 3,040 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 43,767 | 49,952 | ||
Less — Accumulated provision for depreciation | 15,731 | 15,160 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 28,036 | 34,792 | ||
Construction work in progress | 1,351 | 2,422 | ||
Total net property, plant and equipment | 29,387 | 37,214 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 2,514 | 2,282 | ||
Other | 512 | 506 | ||
Total other property and investments | 3,026 | 2,788 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Customer intangibles | 120 | |||
Goodwill | 5,618 | 6,418 | 6,418 | |
Other | 1,153 | 1,286 | ||
Total deferred charges and other assets | 7,785 | 9,052 | ||
Total assets | 43,148 | 52,094 | 51,552 | |
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 1,685 | 1,166 | ||
Short-term borrowings | 2,675 | 1,708 | ||
Accounts payable- | ||||
Accrued taxes | 580 | 519 | ||
Derivatives | 78 | 106 | ||
Other | 660 | 642 | ||
Total current liabilities | 7,126 | 5,602 | ||
CAPITALIZATION: | ||||
Total equity | 6,241 | 12,421 | ||
Long-term debt and other long-term obligations | 18,192 | 19,099 | ||
Total capitalization | 24,433 | 31,521 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 757 | 791 | ||
Accumulated deferred income taxes | 3,765 | 6,773 | ||
Retirement benefits | 3,719 | 4,245 | ||
Asset retirement obligations | 1,482 | 1,410 | ||
Other | 1,704 | 1,555 | ||
Total noncurrent liabilities | 11,589 | 14,971 | ||
Total liabilities and capitalization | 43,148 | 52,094 | ||
Eliminations | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | (612) | (846) | ||
Other Receivables | 0 | 0 | ||
Notes receivable from affiliated companies | (3,351) | (2,410) | ||
Materials and supplies, at average cost | 0 | 0 | ||
Derivatives | 0 | 0 | ||
Collateral | 0 | 0 | ||
Prepayments and other | 0 | 0 | ||
Total current assets | (3,963) | (3,256) | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | (290) | (382) | ||
Less — Accumulated provision for depreciation | (187) | (194) | ||
Property, plant and equipment in service net of accumulated provision for depreciation | (103) | (188) | ||
Construction work in progress | 0 | 0 | ||
Total net property, plant and equipment | (103) | (188) | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | (2,923) | (7,452) | ||
Other | 0 | 0 | ||
Total other property and investments | (2,923) | (7,452) | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | (270) | (316) | ||
Customer intangibles | 0 | 0 | ||
Goodwill | 0 | |||
Property taxes | 0 | 0 | ||
Derivatives | 0 | 0 | ||
Other | 21 | 12 | ||
Total deferred charges and other assets | (249) | (304) | ||
Total assets | (7,238) | (11,200) | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | (26) | (25) | ||
Short-term borrowings | 0 | 0 | ||
Accounts payable- | ||||
Affiliated companies | (706) | (856) | ||
Other | 0 | 0 | ||
Accrued taxes | (16) | (86) | ||
Derivatives | 0 | 0 | ||
Other | 36 | 45 | ||
Total current liabilities | (4,063) | (3,332) | ||
CAPITALIZATION: | ||||
Total equity | (2,834) | (7,420) | ||
Long-term debt and other long-term obligations | (1,091) | (1,136) | ||
Total capitalization | (3,925) | (8,556) | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 757 | 791 | ||
Accumulated deferred income taxes | (7) | (103) | ||
Retirement benefits | 0 | 0 | ||
Asset retirement obligations | 0 | 0 | ||
Derivatives | 0 | 0 | ||
Other | 0 | 0 | ||
Total noncurrent liabilities | 750 | 688 | ||
Total liabilities and capitalization | (7,238) | (11,200) | ||
Eliminations | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | (3,351) | (2,410) | ||
FES | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 213 | 275 | ||
Affiliated companies | 332 | 433 | ||
Other Receivables | 17 | 36 | ||
Notes receivable from affiliated companies | 501 | 406 | ||
Materials and supplies, at average cost | 45 | 53 | ||
Derivatives | 137 | 154 | ||
Collateral | 157 | 70 | ||
Prepayments and other | 38 | 48 | ||
Total current assets | 1,440 | 1,475 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 120 | 93 | ||
Less — Accumulated provision for depreciation | 52 | 40 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 68 | 53 | ||
Construction work in progress | 2 | 30 | ||
Total net property, plant and equipment | 70 | 83 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | 2,923 | 7,452 | ||
Other | 0 | 0 | ||
Total other property and investments | 2,923 | 7,452 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 395 | 300 | ||
Customer intangibles | 9 | 61 | ||
Goodwill | 23 | |||
Property taxes | 0 | 0 | ||
Derivatives | 77 | 79 | ||
Other | 24 | 29 | ||
Total deferred charges and other assets | 505 | 492 | ||
Total assets | 4,938 | 9,502 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 0 | 0 | ||
Short-term borrowings | 0 | 0 | ||
Accounts payable- | ||||
Affiliated companies | 743 | 884 | ||
Other | 17 | 21 | ||
Accrued taxes | 50 | 7 | ||
Derivatives | 71 | 103 | ||
Other | 56 | 66 | ||
Total current liabilities | 3,906 | 3,102 | ||
CAPITALIZATION: | ||||
Total equity | 218 | 5,605 | ||
Long-term debt and other long-term obligations | 691 | 690 | ||
Total capitalization | 909 | 6,295 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Accumulated deferred income taxes | 4 | 6 | ||
Retirement benefits | 25 | 27 | ||
Asset retirement obligations | 0 | 0 | ||
Derivatives | 52 | 37 | ||
Other | 42 | 35 | ||
Total noncurrent liabilities | 123 | 105 | ||
Total liabilities and capitalization | 4,938 | 9,502 | ||
FES | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 2,969 | 2,021 | ||
FG | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 2 | 2 | 2 | 2 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | 315 | 403 | ||
Other Receivables | 2 | 4 | ||
Notes receivable from affiliated companies | 1,585 | 1,210 | ||
Materials and supplies, at average cost | 142 | 204 | ||
Derivatives | 0 | 0 | ||
Collateral | 0 | 0 | ||
Prepayments and other | 24 | 18 | ||
Total current assets | 2,070 | 1,841 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 2,524 | 6,367 | ||
Less — Accumulated provision for depreciation | 1,920 | 2,144 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 604 | 4,223 | ||
Construction work in progress | 67 | 249 | ||
Total net property, plant and equipment | 671 | 4,472 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 0 | 0 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 9 | 10 | ||
Total other property and investments | 9 | 10 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 1,271 | 16 | ||
Customer intangibles | 0 | 0 | ||
Goodwill | 0 | |||
Property taxes | 12 | 12 | ||
Derivatives | 0 | 0 | ||
Other | 327 | 312 | ||
Total deferred charges and other assets | 1,610 | 340 | ||
Total assets | 4,360 | 6,663 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 200 | 229 | ||
Short-term borrowings | 0 | 8 | ||
Accounts payable- | ||||
Affiliated companies | 107 | 146 | ||
Other | 93 | 118 | ||
Accrued taxes | 48 | 93 | ||
Derivatives | 6 | 1 | ||
Other | 54 | 61 | ||
Total current liabilities | 991 | 1,045 | ||
CAPITALIZATION: | ||||
Total equity | 828 | 2,944 | ||
Long-term debt and other long-term obligations | 2,093 | 2,116 | ||
Total capitalization | 2,921 | 5,060 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Accumulated deferred income taxes | 3 | 0 | ||
Retirement benefits | 172 | 305 | ||
Asset retirement obligations | 188 | 191 | ||
Derivatives | 0 | 1 | ||
Other | 85 | 61 | ||
Total noncurrent liabilities | 448 | 558 | ||
Total liabilities and capitalization | 4,360 | 6,663 | ||
FG | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 483 | 389 | ||
NG | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ||||
Customers | 0 | 0 | ||
Affiliated companies | 417 | 461 | ||
Other Receivables | 8 | 19 | ||
Notes receivable from affiliated companies | 1,294 | 805 | ||
Materials and supplies, at average cost | 80 | 213 | ||
Derivatives | 0 | 0 | ||
Collateral | 0 | 0 | ||
Prepayments and other | 1 | 0 | ||
Total current assets | 1,800 | 1,498 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 4,703 | 8,233 | ||
Less — Accumulated provision for depreciation | 4,144 | 3,775 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 559 | 4,458 | ||
Construction work in progress | 358 | 878 | ||
Total net property, plant and equipment | 917 | 5,336 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 1,552 | 1,327 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 1 | 0 | ||
Total other property and investments | 1,553 | 1,327 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 883 | 0 | ||
Customer intangibles | 0 | 0 | ||
Goodwill | 0 | |||
Property taxes | 28 | 28 | ||
Derivatives | 0 | 0 | ||
Other | 0 | 14 | ||
Total deferred charges and other assets | 911 | 42 | ||
Total assets | 5,181 | 8,203 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 5 | 308 | ||
Short-term borrowings | 0 | 0 | ||
Accounts payable- | ||||
Affiliated companies | 406 | 368 | ||
Other | 0 | 0 | ||
Accrued taxes | 61 | 62 | ||
Derivatives | 0 | 0 | ||
Other | 10 | 9 | ||
Total current liabilities | 482 | 747 | ||
CAPITALIZATION: | ||||
Total equity | 2,006 | 4,476 | ||
Long-term debt and other long-term obligations | 1,120 | 840 | ||
Total capitalization | 3,126 | 5,316 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 0 | 0 | ||
Accumulated deferred income taxes | 0 | 697 | ||
Retirement benefits | 0 | 0 | ||
Asset retirement obligations | 713 | 640 | ||
Derivatives | 0 | 0 | ||
Other | 860 | 803 | ||
Total noncurrent liabilities | 1,573 | 2,140 | ||
Total liabilities and capitalization | 5,181 | 8,203 | ||
NG | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | 0 | 0 | ||
FES | ||||
CURRENT ASSETS: | ||||
Cash and cash equivalents | 2 | 2 | $ 2 | $ 2 |
Receivables- | ||||
Customers | 213 | 275 | ||
Affiliated companies | 452 | 451 | ||
Other Receivables | 27 | 59 | ||
Notes receivable from affiliated companies | 29 | 11 | ||
Materials and supplies, at average cost | 267 | 470 | ||
Derivatives | 137 | 154 | ||
Collateral | 157 | 70 | ||
Prepayments and other | 63 | 66 | ||
Total current assets | 1,347 | 1,558 | ||
PROPERTY, PLANT AND EQUIPMENT: | ||||
In service | 7,057 | 14,311 | ||
Less — Accumulated provision for depreciation | 5,929 | 5,765 | ||
Property, plant and equipment in service net of accumulated provision for depreciation | 1,128 | 8,546 | ||
Construction work in progress | 427 | 1,157 | ||
Total net property, plant and equipment | 1,555 | 9,703 | ||
INVESTMENTS: | ||||
Nuclear plant decommissioning trusts | 1,552 | 1,327 | ||
Investment in affiliated companies | 0 | 0 | ||
Other | 10 | 10 | ||
Total other property and investments | 1,562 | 1,337 | ||
DEFERRED CHARGES AND OTHER ASSETS: | ||||
Accumulated deferred income tax benefits | 2,279 | 0 | ||
Customer intangibles | 9 | 61 | ||
Goodwill | 0 | 23 | ||
Property taxes | 40 | 40 | ||
Derivatives | 77 | 79 | ||
Other | 372 | 367 | ||
Total deferred charges and other assets | 2,777 | 570 | ||
Total assets | 7,241 | 13,168 | ||
CURRENT LIABILITIES: | ||||
Currently payable long-term debt | 179 | 512 | ||
Short-term borrowings | 0 | 8 | ||
Accounts payable- | ||||
Affiliated companies | 550 | 542 | ||
Other | 110 | 139 | ||
Accrued taxes | 143 | 76 | ||
Derivatives | 77 | 104 | ||
Other | 156 | 181 | ||
Total current liabilities | 1,316 | 1,562 | ||
CAPITALIZATION: | ||||
Total equity | 218 | 5,605 | ||
Long-term debt and other long-term obligations | 2,813 | 2,510 | ||
Total capitalization | 3,031 | 8,115 | ||
NONCURRENT LIABILITIES: | ||||
Deferred gain on sale and leaseback transaction | 757 | 791 | ||
Accumulated deferred income taxes | 0 | 600 | ||
Retirement benefits | 197 | 332 | ||
Asset retirement obligations | 901 | 831 | ||
Derivatives | 52 | 38 | ||
Other | 987 | 899 | ||
Total noncurrent liabilities | 2,894 | 3,491 | ||
Total liabilities and capitalization | 7,241 | 13,168 | ||
FES | Affiliates | ||||
CURRENT LIABILITIES: | ||||
Other Short-term Borrowings | $ 101 | $ 0 |
Supplemental Guarantor Infor137
Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions | Dec. 13, 2016 | Feb. 12, 2014 | Dec. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ 3,371 | $ 3,447 | $ 2,713 | |||
New Financing- | ||||||
Long-term debt | 1,976 | 1,311 | 4,528 | |||
Short-term borrowings, net | 975 | 0 | 0 | |||
Equity contribution from parent | $ 500 | $ 500 | ||||
Redemptions and Repayments- | ||||||
Long-term debt | (2,331) | (879) | (1,759) | |||
Short-term borrowings, net | 0 | (91) | (1,605) | |||
Common stock dividend payments | (611) | (607) | (604) | |||
Other | (31) | (13) | (47) | |||
Net cash (used for) provided from financing activities | (22) | (279) | 513 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | (2,835) | (2,704) | (3,312) | |||
Nuclear fuel | (232) | (190) | (233) | |||
Proceeds from asset sales | $ 394 | 15 | 20 | 394 | ||
Sales of investment securities held in trusts | 1,678 | 1,534 | 2,133 | |||
Purchases of investment securities held in trusts | (1,789) | (1,648) | (2,236) | |||
Other | 27 | 8 | 48 | |||
Net cash used for investing activities | (3,281) | (3,122) | (3,359) | |||
Net change in cash and cash equivalents | 68 | 46 | (133) | |||
Cash and cash equivalents at beginning of period | 131 | 85 | 218 | |||
Cash and cash equivalents at end of period | 199 | 199 | 131 | 85 | ||
Eliminations | ||||||
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | (25) | (24) | (22) | |||
New Financing- | ||||||
Long-term debt | 0 | 0 | 0 | |||
Short-term borrowings, net | (941) | (863) | (361) | |||
Equity contribution from parent | 0 | |||||
Redemptions and Repayments- | ||||||
Long-term debt | 25 | 24 | 22 | |||
Short-term borrowings, net | (98) | (178) | ||||
Common stock dividend payments | 0 | |||||
Other | 0 | 0 | ||||
Net cash (used for) provided from financing activities | (916) | (937) | (517) | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | 0 | 0 | 0 | |||
Nuclear fuel | 0 | 0 | 0 | |||
Proceeds from asset sales | 0 | 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 | ||||
Loans to affiliated companies, net | 941 | 961 | 539 | |||
Other | 0 | 0 | 0 | |||
Net cash used for investing activities | 941 | 961 | 539 | |||
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 | 0 | ||
FES | ||||||
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | (842) | (637) | (600) | |||
New Financing- | ||||||
Long-term debt | 0 | 0 | 0 | |||
Short-term borrowings, net | 948 | 796 | 247 | |||
Equity contribution from parent | 500 | |||||
Redemptions and Repayments- | ||||||
Long-term debt | 0 | (17) | (1) | |||
Short-term borrowings, net | 0 | 0 | ||||
Common stock dividend payments | (70) | |||||
Other | 0 | (1) | ||||
Net cash (used for) provided from financing activities | 948 | 709 | 745 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | (30) | (5) | (8) | |||
Nuclear fuel | 0 | 0 | 0 | |||
Proceeds from asset sales | 9 | 10 | 0 | |||
Sales of investment securities held in trusts | 0 | 0 | 0 | |||
Purchases of investment securities held in trusts | 0 | 0 | 0 | |||
Cash investments | 10 | (10) | ||||
Loans to affiliated companies, net | (95) | (67) | (136) | |||
Other | 0 | 0 | (1) | |||
Net cash used for investing activities | (106) | (72) | (145) | |||
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 | 0 | ||
FG | ||||||
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 549 | 551 | 408 | |||
New Financing- | ||||||
Long-term debt | 186 | 45 | 431 | |||
Short-term borrowings, net | 94 | 67 | 114 | |||
Equity contribution from parent | 0 | |||||
Redemptions and Repayments- | ||||||
Long-term debt | (224) | (70) | (269) | |||
Short-term borrowings, net | 0 | 0 | ||||
Common stock dividend payments | 0 | |||||
Other | (6) | (5) | (12) | |||
Net cash (used for) provided from financing activities | 50 | 37 | 264 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | (224) | (223) | (169) | |||
Nuclear fuel | 0 | 0 | 0 | |||
Proceeds from asset sales | 0 | 3 | 307 | |||
Sales of investment securities held in trusts | 0 | 0 | 0 | |||
Purchases of investment securities held in trusts | 0 | 0 | 0 | |||
Cash investments | 0 | 0 | ||||
Loans to affiliated companies, net | (376) | (372) | (815) | |||
Other | 1 | 4 | 5 | |||
Net cash used for investing activities | (599) | (588) | (672) | |||
Net change in cash and cash equivalents | 0 | 0 | 0 | |||
Cash and cash equivalents at beginning of period | 2 | 2 | 2 | |||
Cash and cash equivalents at end of period | 2 | 2 | 2 | 2 | ||
NG | ||||||
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 1,103 | 1,261 | 785 | |||
New Financing- | ||||||
Long-term debt | 285 | 296 | 447 | |||
Short-term borrowings, net | 0 | 0 | 0 | |||
Equity contribution from parent | 0 | |||||
Redemptions and Repayments- | ||||||
Long-term debt | (308) | (348) | (568) | |||
Short-term borrowings, net | (28) | (123) | ||||
Common stock dividend payments | 0 | |||||
Other | (2) | (1) | (2) | |||
Net cash (used for) provided from financing activities | (25) | (81) | (246) | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | (292) | (399) | (662) | |||
Nuclear fuel | (232) | (190) | (233) | |||
Proceeds from asset sales | 0 | 0 | 0 | |||
Sales of investment securities held in trusts | 717 | 733 | 1,163 | |||
Purchases of investment securities held in trusts | (783) | (791) | (1,219) | |||
Cash investments | 0 | 0 | ||||
Loans to affiliated companies, net | (488) | (533) | 412 | |||
Other | 0 | 0 | 0 | |||
Net cash used for investing activities | (1,078) | (1,180) | (539) | |||
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 | 0 | ||
FES | ||||||
Consolidated Statements of Cash Flows [Abstract] | ||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | 785 | 1,151 | 571 | |||
New Financing- | ||||||
Long-term debt | 471 | 341 | 878 | |||
Short-term borrowings, net | 101 | 0 | 0 | |||
Equity contribution from parent | 0 | 500 | ||||
Redemptions and Repayments- | ||||||
Long-term debt | (507) | (411) | (816) | |||
Short-term borrowings, net | 0 | (126) | (301) | |||
Common stock dividend payments | 0 | (70) | 0 | |||
Other | (8) | (6) | (15) | |||
Net cash (used for) provided from financing activities | 57 | (272) | 246 | |||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||
Property additions | (546) | (627) | (839) | |||
Nuclear fuel | (232) | (190) | (233) | |||
Proceeds from asset sales | $ 307 | 9 | 13 | 307 | ||
Sales of investment securities held in trusts | 717 | 733 | 1,163 | |||
Purchases of investment securities held in trusts | (783) | (791) | (1,219) | |||
Cash investments | 10 | (10) | 0 | |||
Loans to affiliated companies, net | (18) | (11) | 0 | |||
Other | 1 | 4 | 4 | |||
Net cash used for investing activities | (842) | (879) | (817) | |||
Net change in cash and cash equivalents | 0 | 0 | 0 | |||
Cash and cash equivalents at beginning of period | 2 | 2 | 2 | |||
Cash and cash equivalents at end of period | $ 2 | $ 2 | $ 2 | $ 2 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Segment Financial Information | ||||||||||||||
Revenues | $ 14,562 | $ 15,026 | $ 15,049 | |||||||||||
Total revenues | $ 3,375 | $ 3,917 | $ 3,401 | $ 3,869 | $ 3,541 | $ 4,123 | $ 3,465 | $ 3,897 | 14,562 | [1] | 15,026 | [1] | 15,049 | [1] |
Depreciation | 339 | 311 | 334 | 329 | 313 | 328 | 322 | 319 | 1,313 | 1,282 | 1,220 | |||
Amortization of regulatory assets, net | 320 | 268 | 12 | |||||||||||
Impairment of assets | 9,218 | 0 | 1,447 | 0 | 18 | 8 | 16 | 0 | 10,665 | 42 | 0 | |||
Investment income (loss) | 84 | (22) | 72 | |||||||||||
Impairment of equity method investment | 0 | 362 | 0 | |||||||||||
Interest expense | 1,157 | 1,132 | 1,081 | |||||||||||
Income taxes (benefits) | (3,389) | 251 | (130) | 213 | (170) | 226 | 115 | 144 | (3,055) | 315 | (42) | |||
Income (loss) from continuing operations | (6,177) | 578 | 213 | |||||||||||
Discontinued operations, net of tax | 0 | 0 | 86 | |||||||||||
NET INCOME (LOSS) | (5,796) | $ 380 | $ (1,089) | $ 328 | (226) | $ 395 | $ 187 | $ 222 | (6,177) | 578 | 299 | |||
Total assets | 43,148 | 52,094 | 43,148 | 52,094 | 51,552 | |||||||||
Total goodwill | 5,618 | 6,418 | 5,618 | 6,418 | 6,418 | |||||||||
Property additions | 2,835 | 2,704 | 3,312 | |||||||||||
Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Regulated Distribution | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 9,629 | 9,582 | 9,054 | |||||||||||
Total revenues | 9,629 | 9,582 | 9,054 | |||||||||||
Depreciation | 676 | 664 | 651 | |||||||||||
Amortization of regulatory assets, net | 313 | 261 | 1 | |||||||||||
Impairment of assets | 0 | 8 | ||||||||||||
Investment income (loss) | 49 | 42 | 56 | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 586 | 600 | 603 | |||||||||||
Income taxes (benefits) | 375 | 325 | 209 | |||||||||||
Income (loss) from continuing operations | 433 | |||||||||||||
Discontinued operations, net of tax | 0 | |||||||||||||
NET INCOME (LOSS) | 651 | 588 | 433 | |||||||||||
Total assets | 27,702 | 27,390 | 27,702 | 27,390 | 27,332 | |||||||||
Total goodwill | 5,004 | 5,092 | 5,004 | 5,092 | 5,092 | |||||||||
Property additions | 1,063 | 1,040 | 855 | |||||||||||
Regulated Distribution | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Regulated Transmission | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 1,151 | 1,054 | 817 | |||||||||||
Total revenues | 1,151 | 1,054 | 817 | |||||||||||
Depreciation | 187 | 164 | 134 | |||||||||||
Amortization of regulatory assets, net | 7 | 7 | 11 | |||||||||||
Impairment of assets | 0 | 0 | ||||||||||||
Investment income (loss) | 0 | 0 | 0 | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 158 | 147 | 117 | |||||||||||
Income taxes (benefits) | 187 | 191 | 139 | |||||||||||
Income (loss) from continuing operations | 255 | |||||||||||||
Discontinued operations, net of tax | 0 | |||||||||||||
NET INCOME (LOSS) | 331 | 328 | 255 | |||||||||||
Total assets | 8,755 | 7,800 | 8,755 | 7,800 | 6,864 | |||||||||
Total goodwill | 614 | 526 | 614 | 526 | 526 | |||||||||
Property additions | 1,101 | 1,020 | 1,446 | |||||||||||
Regulated Transmission | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Competitive Energy Services | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 4,070 | 4,698 | 5,470 | |||||||||||
Total revenues | 4,549 | 5,384 | 6,289 | |||||||||||
Depreciation | 387 | 394 | 387 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets | 10,665 | 34 | ||||||||||||
Investment income (loss) | 66 | (16) | 54 | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 194 | 192 | 197 | |||||||||||
Income taxes (benefits) | (3,498) | 50 | (223) | |||||||||||
Income (loss) from continuing operations | (417) | |||||||||||||
Discontinued operations, net of tax | 86 | |||||||||||||
NET INCOME (LOSS) | (6,919) | 89 | (331) | |||||||||||
Total assets | 5,952 | 16,027 | 5,952 | 16,027 | 16,180 | |||||||||
Total goodwill | 0 | 800 | 0 | 800 | 800 | |||||||||
Property additions | 619 | 588 | 939 | |||||||||||
Competitive Energy Services | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 479 | 686 | 819 | |||||||||||
Other/Corporate | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Total revenues | 0 | 0 | 0 | |||||||||||
Depreciation | 63 | 60 | 48 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets | 0 | 0 | ||||||||||||
Investment income (loss) | 10 | (9) | 2 | |||||||||||
Impairment of equity method investment | 362 | |||||||||||||
Interest expense | 219 | 193 | 168 | |||||||||||
Income taxes (benefits) | (121) | (262) | (178) | |||||||||||
Income (loss) from continuing operations | (58) | |||||||||||||
Discontinued operations, net of tax | 0 | |||||||||||||
NET INCOME (LOSS) | (240) | (427) | (58) | |||||||||||
Total assets | 739 | 877 | 739 | 877 | 1,176 | |||||||||
Total goodwill | 0 | 0 | 0 | 0 | 0 | |||||||||
Property additions | 52 | 56 | 72 | |||||||||||
Other/Corporate | Intersegment Eliminations | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | 0 | 0 | 0 | |||||||||||
Reconciling Adjustments | ||||||||||||||
Segment Financial Information | ||||||||||||||
Revenues | (288) | (308) | (292) | |||||||||||
Total revenues | (767) | (994) | (1,111) | |||||||||||
Depreciation | 0 | 0 | 0 | |||||||||||
Amortization of regulatory assets, net | 0 | 0 | 0 | |||||||||||
Impairment of assets | 0 | 0 | ||||||||||||
Investment income (loss) | (41) | (39) | (40) | |||||||||||
Impairment of equity method investment | 0 | |||||||||||||
Interest expense | 0 | 0 | (4) | |||||||||||
Income taxes (benefits) | 2 | 11 | 11 | |||||||||||
Income (loss) from continuing operations | 0 | |||||||||||||
Discontinued operations, net of tax | 0 | |||||||||||||
NET INCOME (LOSS) | 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 | $ (479) | $ (686) | $ (819) | |||||||||||
[1] | Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively. |
Segment Information (Details Te
Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions | 12 Months Ended | |
Dec. 31, 2016USD ($)mi²customercompanyMW | Oct. 09, 2013MW | |
Segment Reporting Information [Line Items] | ||
Ownership interest (percent) | 3.00% | |
Other/Corporate | ||
Segment Reporting Information [Line Items] | ||
Long-term debt and other long-term obligations | $ | $ 4.2 | |
Debt subject to variable interest rate (percent) | 28.00% | |
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) | 3,790 | |
CES | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | 13,162 | |
FE | Revolving Credit Facility | Other/Corporate | ||
Segment Reporting Information [Line Items] | ||
Long-term line of credit | $ | $ 2.7 | |
Global Holding | Signal Peak | FEV | ||
Segment Reporting Information [Line Items] | ||
Ownership interest (percent) | 33.33% | |
Pleasants Power Station | CES | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | 1,300 | |
Purchase Agreement with Aspen Generating, LLC | ||
Segment Reporting Information [Line Items] | ||
Megawatts of net demonstrated capacity of competitive segment (in MW's) | 1,572 |
Discontinued Operations (Detail
Discontinued Operations (Details) $ in Millions | Feb. 12, 2014USD ($)plant | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from asset sales | $ 394 | $ 15 | $ 20 | $ 394 |
Assets held-for-sale | 235 | |||
Goodwill | 29 | |||
Pre-tax income | 155 | |||
Pre-tax gain on sale of assets | 142 | |||
Revenue | 5 | |||
FES | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Proceeds from asset sales | 307 | $ 9 | $ 13 | 307 |
Assets held-for-sale | 122 | |||
Goodwill | $ 1 | |||
Pre-tax income | 186 | |||
Pre-tax gain on sale of assets | 177 | |||
Revenue | $ 5 | |||
FERC | Hydroelectric Asset Sale | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Application to sell power plant projects, number | plant | 11 |
Summary of Quarterly Financi141
Summary of Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | Dec. 13, 2016 | Dec. 31, 2016 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |||
Quarterly Financial Data [Line Items] | ||||||||||||||||
REVENUES | $ 3,375 | $ 3,917 | $ 3,401 | $ 3,869 | $ 3,541 | $ 4,123 | $ 3,465 | $ 3,897 | $ 14,562 | [1] | $ 15,026 | [1] | $ 15,049 | [1] | ||
Other operating expenses | 1,023 | 953 | 964 | 918 | 950 | 842 | 900 | 1,057 | 3,858 | 3,749 | 3,962 | |||||
Pension and OPEB mark-to-market adjustment | 147 | 0 | 0 | 0 | 242 | 0 | 0 | 0 | 147 | 242 | 835 | |||||
Provision for depreciation | 339 | 311 | 334 | 329 | 313 | 328 | 322 | 319 | 1,313 | 1,282 | 1,220 | |||||
Impairment of assets | 9,218 | 0 | 1,447 | 0 | 18 | 8 | 16 | 0 | 10,665 | 42 | 0 | |||||
Operating Income (Loss) | (8,924) | 861 | (975) | 776 | 236 | 908 | 554 | 594 | (8,262) | 2,292 | 1,062 | |||||
Income (loss) before income taxes (benefits) | (9,185) | 631 | (1,219) | 541 | (396) | 621 | 302 | 366 | ||||||||
Income taxes (benefits) | (3,389) | 251 | (130) | 213 | (170) | 226 | 115 | 144 | (3,055) | 315 | (42) | |||||
NET INCOME (LOSS) | $ (5,796) | $ 380 | $ (1,089) | $ 328 | $ (226) | $ 395 | $ 187 | $ 222 | $ (6,177) | $ 578 | $ 299 | |||||
Earnings (loss) per share of common stock- | ||||||||||||||||
Basic - Earnings (losses) Available to FirstEnergy Corp., in dollars per share | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.78 | $ (0.53) | $ 0.94 | $ 0.44 | $ 0.53 | $ (14.49) | $ 1.37 | $ 0.71 | |||||
Diluted - Earnings (losses) Available to FirstEnergy Corp., in dollars per share | $ (13.44) | $ 0.89 | $ (2.56) | $ 0.77 | $ (0.53) | $ 0.93 | $ 0.44 | $ 0.53 | $ (14.49) | $ 1.37 | $ 0.71 | |||||
Equity contribution from parent | $ 500 | $ 500 | ||||||||||||||
FES | ||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||
REVENUES | $ 997 | $ 1,100 | $ 1,102 | $ 1,199 | $ 1,171 | $ 1,338 | $ 1,119 | $ 1,377 | $ 4,398 | [2] | $ 5,005 | [2] | $ 6,144 | [2] | ||
Other operating expenses | 352 | 316 | 369 | 240 | 312 | 246 | 337 | 413 | 1,277 | 1,308 | 1,635 | |||||
Pension and OPEB mark-to-market adjustment | 48 | 0 | 0 | 0 | 57 | 0 | 0 | 0 | 48 | 57 | 297 | |||||
Provision for depreciation | 86 | 83 | 84 | 83 | 84 | 79 | 81 | 80 | 336 | 324 | 319 | |||||
Impairment of assets | 8,082 | 0 | 540 | 0 | 17 | 0 | 16 | 0 | 8,622 | 33 | 0 | |||||
Operating Income (Loss) | (8,153) | 101 | (571) | 226 | 25 | 240 | 0 | 12 | (8,397) | 277 | (530) | |||||
Income (loss) before income taxes (benefits) | (8,171) | 96 | (581) | 213 | (13) | 190 | (25) | (5) | ||||||||
Income taxes (benefits) | (2,983) | 56 | (143) | 82 | 1 | 70 | (4) | (2) | (2,988) | 65 | (228) | |||||
NET INCOME (LOSS) | $ (5,188) | $ 40 | $ (438) | $ 131 | $ (14) | $ 120 | $ (21) | $ (3) | (5,455) | $ 82 | (244) | |||||
Earnings (loss) per share of common stock- | ||||||||||||||||
Equity contribution from parent | $ 0 | $ 500 | ||||||||||||||
[1] | Includes excise tax collections of $406 million, $416 million and $420 million in 2016, 2015 and 2014, respectively. | |||||||||||||||
[2] | Includes excise tax collections of $28 million, $44 million and $69 million in 2016, 2015 and 2014, respectively. |
Subsequent Events (Details)
Subsequent Events (Details) | Feb. 17, 2017USD ($)Natural_gas_plant | Feb. 16, 2017USD ($)agreement | Jan. 18, 2017USD ($)Natural_gas_plantlimited_guarantyMW | Dec. 06, 2016USD ($) | Dec. 31, 2016MW | Dec. 05, 2016USD ($) |
Purchase Agreement with Aspen Generating, LLC | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 1,572 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 1,572 | |||||
Cash purchase price | $ | $ 925,000,000 | $ 925,000,000 | ||||
Number of limited guaranties | limited_guaranty | 2 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Minimum | ||||||
Subsequent Event [Line Items] | ||||||
Term of guaranties | 1 year | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Maximum | ||||||
Subsequent Event [Line Items] | ||||||
Term of guaranties | 3 years | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Bath County Hydro | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 713 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Springdale Generating Facility Units 1-5 | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 638 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Chamberburg Generating Facility Units 12-13 | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 88 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Gans Generating Facility Units 8-9 | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 88 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | Hunlock Creek | ||||||
Subsequent Event [Line Items] | ||||||
Plant generation capacity (in MW's) | 45 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | AE Supply | ||||||
Subsequent Event [Line Items] | ||||||
Number of gas generating plants | Natural_gas_plant | 4 | 4 | ||||
Discharge of note indenture | $ | $ 305,000,000 | |||||
Make-whole premiums | $ | $ 100,000,000 | |||||
Subsequent Event | Purchase Agreement with Aspen Generating, LLC | AGC | ||||||
Subsequent Event [Line Items] | ||||||
Plant ownership percentage | 59.00% | |||||
Term Loan | ||||||
Subsequent Event [Line Items] | ||||||
Face amount of loan | $ | $ 1,200,000,000 | $ 1,000,000,000 | ||||
Debt Instrument, Term | 5 years | |||||
Term Loan | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Debt Instrument, Number of Agreements | agreement | 2 | |||||
Bank of America N.A. | $125M Term Loan | Term Loan | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Face amount of loan | $ | $ 125,000,000 | |||||
Debt Instrument, Term | 3 years | |||||
The Bank of Nova Scotia | $125M Term Loan | Term Loan | Subsequent Event | ||||||
Subsequent Event [Line Items] | ||||||
Face amount of loan | $ | $ 125,000,000 | |||||
Debt Instrument, Term | 3 years |
Consolidated Valuation and Q143
Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated provision for uncollectible accounts - customers | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | $ 68,775 | $ 59,266 | $ 51,630 |
Charged to Income | 81,719 | 114,249 | 90,144 |
Charged to Other Accounts | 15,222 | 54,199 | 36,373 |
Deductions | 112,409 | 158,939 | 118,881 |
Ending Balance | 53,307 | 68,775 | 59,266 |
Accumulated provision for uncollectible accounts - customers | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 8,466 | 17,862 | 11,073 |
Charged to Income | 4,766 | 7,411 | 21,942 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 8,334 | 16,807 | 15,153 |
Ending Balance | 4,898 | 8,466 | 17,862 |
Accumulated provision for uncollectible accounts - other | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 5,231 | 5,197 | 2,976 |
Charged to Income | 13,597 | 899 | 3,469 |
Charged to Other Accounts | 11,329 | 4,189 | 8,264 |
Deductions | 29,273 | 5,054 | 9,512 |
Ending Balance | 884 | 5,231 | 5,197 |
Accumulated provision for uncollectible accounts - other | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 2,500 | 2,500 | 2,523 |
Charged to Income | 0 | 0 | 9 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 2,500 | 0 | 32 |
Ending Balance | 0 | 2,500 | 2,500 |
Valuation allowance on state and local DTAs | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 192,397 | ||
Charged to Income | 245,382 | ||
Charged to Other Accounts | 0 | ||
Deductions | 0 | ||
Ending Balance | 437,779 | 192,397 | |
Loss carryforward tax valuation reserve | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 192,397 | 174,004 | 125,360 |
Charged to Income | 18,393 | 48,644 | |
Charged to Other Accounts | 0 | 0 | |
Deductions | 0 | 0 | |
Ending Balance | 192,397 | 174,004 | |
Loss carryforward tax valuation reserve | FES | |||
Consolidated Valuation and Qualifying Accounts | |||
Beginning Balance | 45,808 | 32,126 | 26,875 |
Charged to Income | 151,682 | 13,682 | 5,251 |
Charged to Other Accounts | 0 | 0 | 0 |
Deductions | 0 | 0 | 0 |
Ending Balance | $ 197,490 | $ 45,808 | $ 32,126 |