Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Nov. 04, 2013 | |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'FIRSTENERGY CORP | ' |
Entity Central Index Key | '0001031296 | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Amendment Flag | 'false | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock Shares Outstanding | ' | 418,229,541 |
FES | ' | ' |
Entity Information [Line Items] | ' | ' |
Entity Registrant Name | 'FirstEnergy Solutions Corp. | ' |
Entity Central Index Key | '0001407703 | ' |
Document Type | '10-Q | ' |
Document Period End Date | 30-Sep-13 | ' |
Amendment Flag | 'false | ' |
Document Fiscal Year Focus | '2013 | ' |
Document Fiscal Period Focus | 'Q3 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Non-accelerated Filer | ' |
Entity Common Stock Shares Outstanding | ' | 7 |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (FirstEnergy Corp.) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
REVENUES: | ' | ' | ' | ' | ||||
Electric utilities | $2,530 | $2,670 | $7,139 | $7,533 | ||||
Unregulated businesses | 1,506 | 1,382 | 4,131 | 4,247 | ||||
Total revenues | 4,036 | [1] | 4,052 | [1] | 11,270 | [1] | 11,780 | [1] |
OPERATING EXPENSES: | ' | ' | ' | ' | ||||
Fuel | 657 | 636 | 1,915 | 1,833 | ||||
Purchased power | 1,120 | 1,063 | 2,932 | 3,367 | ||||
Other operating expenses | 877 | 861 | 2,645 | 2,597 | ||||
Provision for depreciation | 316 | 272 | 909 | 834 | ||||
Amortization of regulatory assets, net | 312 | 61 | 443 | 198 | ||||
General taxes | 242 | 257 | 747 | 760 | ||||
Impairment of long-lived assets | 0 | 0 | 473 | 0 | ||||
Total operating expenses | 3,524 | 3,150 | 10,064 | 9,589 | ||||
OPERATING INCOME (LOSS) | 512 | 902 | 1,206 | 2,191 | ||||
OTHER INCOME (EXPENSE): | ' | ' | ' | ' | ||||
Gain (loss) on debt redemptions | 9 | 0 | -132 | 0 | ||||
Investment income | 5 | 39 | 8 | 63 | ||||
Interest expense | -257 | -230 | -771 | -750 | ||||
Capitalized interest | 17 | 18 | 51 | 54 | ||||
Total other income (expense) | -226 | -173 | -844 | -633 | ||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 286 | 729 | 362 | 1,558 | ||||
INCOME TAXES | 77 | 307 | 129 | 650 | ||||
NET INCOME FROM CONTINUING OPERATIONS | 209 | 422 | 233 | 908 | ||||
Discontinued operations (net of income taxes of $3, $2, $9 and $8, respectively) (Note 16) | 9 | 3 | 17 | 11 | ||||
NET INCOME (LOSS) | 218 | 425 | 250 | 919 | ||||
Income attributable to noncontrolling interest | 0 | 0 | 0 | 1 | ||||
EARNINGS AVAILABLE TO FIRSTENERGY CORP. | $218 | $425 | $250 | $918 | ||||
EARNINGS PER SHARE OF COMMON STOCK: | ' | ' | ' | ' | ||||
Basic - Continuing Operations, in dollars per share | $0.50 | $1.01 | $0.56 | $2.17 | ||||
Basic - Discontinued Operations (Note 16), in dollars per share | $0.02 | $0.01 | $0.04 | $0.03 | ||||
Basic - Earnings Available to FirstEnergy Corp., in dollars per share | $0.52 | $1.02 | $0.60 | $2.20 | ||||
Diluted - Continuing Operations, in dollars per share | $0.50 | $1 | $0.56 | $2.16 | ||||
Diluted - Discontinued Operations (Note 16), in dollars per share | $0.02 | $0.01 | $0.04 | $0.03 | ||||
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share | $0.52 | $1.01 | $0.60 | $2.19 | ||||
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: | ' | ' | ' | ' | ||||
Basic, in shares | 418 | 417 | 418 | 418 | ||||
Diluted, in shares | 419 | 419 | 419 | 419 | ||||
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share | $1.10 | $1.10 | $1.65 | $1.65 | ||||
[1] | Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, respectively. |
Consolidated_Statements_of_Inc1
Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Income Statement [Abstract] | ' | ' | ' | ' |
Tax effect of discontinued operations | $3 | $2 | $9 | $8 |
Excise tax collections included in Revenue | $117 | $123 | $346 | $351 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Statement of Other Comprehensive Income [Abstract] | ' | ' | ' | ' |
NET INCOME | $218 | $425 | $250 | $919 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
Pension and OPEB prior service costs | -47 | -47 | -148 | -148 |
Amortized losses on derivative hedges | 2 | 0 | 4 | 1 |
Change in unrealized gain on available-for-sale securities | 6 | 1 | 3 | 13 |
Other comprehensive income (loss) | -39 | -46 | -141 | -134 |
Income tax benefits on other comprehensive loss | -15 | -24 | -55 | -75 |
Net other comprehensive income (loss) | -24 | -22 | -86 | -59 |
COMPREHENSIVE INCOME (LOSS) | 194 | 403 | 164 | 860 |
Comprehensive income attributable to noncontrolling interest | 0 | 0 | 0 | 1 |
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. | $194 | $403 | $164 | $859 |
Consolidated_Balance_Sheets_Fi
Consolidated Balance Sheets (FirstEnergy Corp.) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | $222 | $172 |
Receivables- | ' | ' |
Customers, net of allowance for uncollectible accounts of $41 in 2013 and $40 in 2012 | 1,579 | 1,614 |
Other, net of allowance for uncollectible accounts of $3 in 2013 and $4 in 2012 | 231 | 315 |
Materials and supplies, at average cost | 731 | 861 |
Prepaid taxes | 104 | 119 |
Derivatives | 140 | 160 |
Accumulated deferred income taxes | 290 | 319 |
Other | 262 | 208 |
Total current assets | 3,559 | 3,768 |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' |
In service | 44,089 | 43,210 |
Less - Accumulated provision for depreciation | 13,167 | 12,600 |
Property, plant and equipment in service net of accumulated provision for depreciation | 30,922 | 30,610 |
Construction work in progress | 2,301 | 2,293 |
Total net property, plant and equipment | 33,223 | 32,903 |
INVESTMENTS: | ' | ' |
Nuclear plant decommissioning trusts | 2,183 | 2,204 |
Investments in lease obligation bonds | 46 | 54 |
Other | 876 | 936 |
Total other property and investments | 3,105 | 3,194 |
ASSETS HELD FOR SALE, NET (NOTE 16): | 234 | 0 |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' |
Goodwill | 6,418 | 6,447 |
Regulatory assets | 2,146 | 2,375 |
Other | 1,698 | 1,719 |
Total deferred charges and other assets | 10,262 | 10,541 |
Total assets | 50,383 | 50,406 |
CURRENT LIABILITIES: | ' | ' |
Currently payable long-term debt | 1,889 | 1,999 |
Short-term borrowings | 3,404 | 1,969 |
Accounts payable | 995 | 1,599 |
Accrued taxes | 401 | 543 |
Accrued compensation and benefits | 289 | 331 |
Derivatives | 105 | 126 |
Other | 872 | 1,038 |
Total current liabilities | 7,955 | 7,605 |
Common stockholders' equity- | ' | ' |
Common stock, $0.10 par value, authorized 490,000,000 shares - 418,216,437 shares outstanding | 42 | 42 |
Other paid-in capital | 9,755 | 9,769 |
Accumulated other comprehensive income | 299 | 385 |
Retained earnings | 2,448 | 2,888 |
Total common stockholders' equity | 12,544 | 13,084 |
Noncontrolling interest | 3 | 9 |
Total equity | 12,547 | 13,093 |
Long-term debt and other long-term obligations | 15,291 | 15,179 |
Total capitalization | 27,838 | 28,272 |
NONCURRENT LIABILITIES: | ' | ' |
Accumulated deferred income taxes | 6,603 | 6,616 |
Retirement benefits | 3,104 | 3,080 |
Asset retirement obligations | 1,834 | 1,599 |
Deferred gain on sale and leaseback transaction | 866 | 892 |
Adverse power contract liability | 467 | 506 |
Other | 1,716 | 1,836 |
Total noncurrent liabilities | 14,590 | 14,529 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | ' | ' |
Total liabilities and capitalization | $50,383 | $50,406 |
Consolidated_Balance_Sheets_Fi1
Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, except Share data, unless otherwise specified | ||
Common stockholders' equity- | ' | ' |
Common stock, par value (in dollars per share) | $0.10 | $0.10 |
Common stock, shares authorized | 490,000,000 | 490,000,000 |
Common stock, shares outstanding | 418,216,437 | 418,216,437 |
Customer [Member] | ' | ' |
Receivables- | ' | ' |
Allowance for uncollectible accounts (in dollars) | $41 | $40 |
Other [Member] | ' | ' |
Receivables- | ' | ' |
Allowance for uncollectible accounts (in dollars) | $3 | $4 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
NET INCOME | $250 | $919 |
Adjustments to reconcile net income to net cash from operating activities- | ' | ' |
Provision for depreciation | 909 | 834 |
Amortization of regulatory assets, net | 443 | 198 |
Nuclear fuel amortization | 156 | 156 |
Deferred purchased power and other costs | -61 | -214 |
Deferred income taxes and investment tax credits, net | 114 | 712 |
Impairments of long-lived assets | 473 | 0 |
Investments impairments | 74 | 10 |
Deferred rents and lease market valuation liability | -22 | -62 |
Retirement benefits | -133 | -97 |
Gain on asset sales | -21 | -17 |
Commodity derivative transactions, net (Note 10) | 24 | -80 |
Pension trust contribution | 0 | -600 |
Cash collateral, net | -67 | -3 |
Loss on debt redemptions | 132 | 0 |
Make-whole premiums paid on debt redemptions | -181 | 0 |
Income from discontinued operations (Note 16) | -17 | -11 |
Decrease (increase) in operating assets- | ' | ' |
Receivables | -7 | -41 |
Materials and supplies | 117 | -63 |
Prepayments and other current assets | -59 | -151 |
Increase (decrease) in operating liabilities- | ' | ' |
Accounts payable | -279 | -227 |
Accrued taxes | -146 | -58 |
Accrued interest | 29 | 50 |
Accrued compensation and retirement benefits | -43 | -71 |
Other | -14 | 92 |
Net cash provided from operating activities | 1,671 | 1,276 |
New Financing- | ' | ' |
Long-term debt | 2,745 | 660 |
Short-term borrowings, net | 1,435 | 1,604 |
Redemptions and Repayments- | ' | ' |
Long-term debt | -2,662 | -870 |
Tender premiums paid on debt redemptions | -110 | 0 |
Common stock dividend payments | -690 | -690 |
Other | -64 | -42 |
Net cash provided from (used for) financing activities | 654 | 662 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Property additions | -1,960 | -1,686 |
Nuclear fuel | -159 | -207 |
Sales of investment securities held in trusts | 1,545 | 2,133 |
Purchases of investment securities held in trusts | -1,567 | -2,188 |
Cash investments | -12 | 100 |
Asset removal costs | -125 | -119 |
Other | 3 | -23 |
Net cash used for investing activities | -2,275 | -1,990 |
Net change in cash and cash equivalents | 50 | -52 |
Cash and cash equivalents at beginning of period | 172 | 202 |
Cash and cash equivalents at end of period | $222 | $150 |
Consolidated_Statements_of_Inc2
Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
REVENUES: | ' | ' | ' | ' | ||||
Electric sales | $1,506 | $1,382 | $4,131 | $4,247 | ||||
Total revenues | 4,036 | [1] | 4,052 | [1] | 11,270 | [1] | 11,780 | [1] |
OPERATING EXPENSES: | ' | ' | ' | ' | ||||
Fuel | 657 | 636 | 1,915 | 1,833 | ||||
Purchased power | 1,120 | 1,063 | 2,932 | 3,367 | ||||
Other operating expenses | 877 | 861 | 2,645 | 2,597 | ||||
Provision for depreciation | 316 | 272 | 909 | 834 | ||||
General taxes | 242 | 257 | 747 | 760 | ||||
Total operating expenses | 3,524 | 3,150 | 10,064 | 9,589 | ||||
OPERATING INCOME (LOSS) | 512 | 902 | 1,206 | 2,191 | ||||
OTHER INCOME (EXPENSE): | ' | ' | ' | ' | ||||
Loss on debt redemptions | 9 | 0 | -132 | 0 | ||||
Investment income (loss) | 5 | 39 | 8 | 63 | ||||
Interest expense | -257 | -230 | -771 | -750 | ||||
Capitalized interest | 17 | 18 | 51 | 54 | ||||
Total other income (expense) | -226 | -173 | -844 | -633 | ||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 286 | 729 | 362 | 1,558 | ||||
INCOME TAXES (BENEFITS) | 77 | 307 | 129 | 650 | ||||
NET INCOME FROM CONTINUING OPERATIONS | 209 | 422 | 233 | 908 | ||||
Discontinued operations (net of income taxes of $5, $3, $8 and $6, respectively) (Note 16) | 9 | 3 | 17 | 11 | ||||
NET INCOME (LOSS) | 218 | 425 | 250 | 919 | ||||
STATEMENTS OF COMPREHENSIVE INCOME | ' | ' | ' | ' | ||||
NET INCOME | 218 | 425 | 250 | 919 | ||||
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' | ||||
Pension and OPEB prior service costs | -47 | -47 | -148 | -148 | ||||
Amortized loss (gain) on derivative hedges | 2 | 0 | 4 | 1 | ||||
Change in unrealized gain on available-for-sale securities | 6 | 1 | 3 | 13 | ||||
Other comprehensive income (loss) | -39 | -46 | -141 | -134 | ||||
Income taxes (benefits) on other comprehensive income (loss) | -15 | -24 | -55 | -75 | ||||
Net other comprehensive income (loss) | -24 | -22 | -86 | -59 | ||||
COMPREHENSIVE INCOME (LOSS) | 194 | 403 | 164 | 860 | ||||
FES | ' | ' | ' | ' | ||||
REVENUES: | ' | ' | ' | ' | ||||
Other | 38 | 37 | 107 | 91 | ||||
Total revenues | 1,679 | 1,550 | 4,655 | 4,511 | ||||
OPERATING EXPENSES: | ' | ' | ' | ' | ||||
Fuel | 304 | 303 | 936 | 978 | ||||
Other operating expenses | 339 | 342 | 1,105 | 1,028 | ||||
Provision for depreciation | 80 | 70 | 231 | 200 | ||||
General taxes | 35 | 35 | 106 | 104 | ||||
Total operating expenses | 1,614 | 1,383 | 4,534 | 4,116 | ||||
OPERATING INCOME (LOSS) | 65 | 167 | 121 | 395 | ||||
OTHER INCOME (EXPENSE): | ' | ' | ' | ' | ||||
Loss on debt redemptions | 0 | 0 | -103 | 0 | ||||
Investment income (loss) | -3 | 38 | -4 | 50 | ||||
Miscellaneous income | 21 | 1 | 29 | 25 | ||||
Capitalized interest | 9 | 9 | 28 | 27 | ||||
Total other income (expense) | -9 | -6 | -183 | -45 | ||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 56 | 161 | -62 | 350 | ||||
INCOME TAXES (BENEFITS) | 23 | 65 | -19 | 139 | ||||
NET INCOME FROM CONTINUING OPERATIONS | 33 | 96 | -43 | 211 | ||||
Discontinued operations (net of income taxes of $5, $3, $8 and $6, respectively) (Note 16) | 7 | 5 | 14 | 11 | ||||
NET INCOME (LOSS) | 40 | 101 | -29 | 222 | ||||
STATEMENTS OF COMPREHENSIVE INCOME | ' | ' | ' | ' | ||||
NET INCOME | 40 | 101 | -29 | 222 | ||||
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' | ||||
Pension and OPEB prior service costs | -5 | -5 | -16 | -2 | ||||
Amortized loss (gain) on derivative hedges | -1 | -2 | -3 | -6 | ||||
Change in unrealized gain on available-for-sale securities | 5 | -2 | 2 | 11 | ||||
Other comprehensive income (loss) | -1 | -9 | -17 | 3 | ||||
Income taxes (benefits) on other comprehensive income (loss) | -1 | -3 | -7 | 1 | ||||
Net other comprehensive income (loss) | 0 | -6 | -10 | 2 | ||||
COMPREHENSIVE INCOME (LOSS) | 40 | 95 | -39 | 224 | ||||
FES | Affiliates | ' | ' | ' | ' | ||||
REVENUES: | ' | ' | ' | ' | ||||
Electric sales | 186 | 155 | 482 | 385 | ||||
OPERATING EXPENSES: | ' | ' | ' | ' | ||||
Purchased power | 132 | 131 | 401 | 381 | ||||
OTHER INCOME (EXPENSE): | ' | ' | ' | ' | ||||
Interest expense | -1 | -3 | -7 | -7 | ||||
FES | Non-Affiliates | ' | ' | ' | ' | ||||
REVENUES: | ' | ' | ' | ' | ||||
Electric sales | 1,455 | 1,358 | 4,066 | 4,035 | ||||
OPERATING EXPENSES: | ' | ' | ' | ' | ||||
Purchased power | 724 | 502 | 1,755 | 1,425 | ||||
OTHER INCOME (EXPENSE): | ' | ' | ' | ' | ||||
Interest expense | ($35) | ($51) | ($126) | ($140) | ||||
[1] | Includes excise tax collections of $117 million and $123 million in the three months ended SeptemberB 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended SeptemberB 30, 2013 and 2012, respectively. |
Consolidated_Statements_of_Inc3
Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Tax effect of discontinued operations | $3 | $2 | $9 | $8 |
FES | ' | ' | ' | ' |
Tax effect of discontinued operations | $5 | $3 | $8 | $6 |
Consolidated_Balance_Sheets_Fi2
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | $222 | $172 |
Receivables- | ' | ' |
Customers, net of allowance for uncollectible accounts of $14 in 2013 and $16 in 2012 | 1,579 | 1,614 |
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012 | 231 | 315 |
Materials and supplies | 731 | 861 |
Derivatives | 140 | 160 |
Prepayments and other | 262 | 208 |
Total current assets | 3,559 | 3,768 |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' |
In service | 44,089 | 43,210 |
Less - Accumulated provision for depreciation | 13,167 | 12,600 |
Property, plant and equipment in service net of accumulated provision for depreciation | 30,922 | 30,610 |
Construction work in progress | 2,301 | 2,293 |
Total net property, plant and equipment | 33,223 | 32,903 |
INVESTMENTS: | ' | ' |
Nuclear plant decommissioning trusts | 2,183 | 2,204 |
Other | 876 | 936 |
Total other property and investments | 3,105 | 3,194 |
ASSETS HELD FOR SALE (NOTE 16) | 234 | 0 |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' |
Goodwill | 6,418 | 6,447 |
Other | 1,698 | 1,719 |
Total deferred charges and other assets | 10,262 | 10,541 |
Total assets | 50,383 | 50,406 |
CURRENT LIABILITIES: | ' | ' |
Currently payable long-term debt | 1,889 | 1,999 |
Short-term borrowings | 3,404 | 1,969 |
Accounts payable- | ' | ' |
Accrued taxes | 401 | 543 |
Derivatives | 105 | 126 |
Other | 872 | 1,038 |
Total current liabilities | 7,955 | 7,605 |
Common stockholders' equity- | ' | ' |
Common stock, without par value, authorized 750 shares- 7 shares outstanding | 42 | 42 |
Accumulated other comprehensive income | 299 | 385 |
Retained earnings | 2,448 | 2,888 |
Total common stockholders' equity | 12,544 | 13,084 |
Long-term debt and other long-term obligations | 15,291 | 15,179 |
Total capitalization | 27,838 | 28,272 |
NONCURRENT LIABILITIES: | ' | ' |
Deferred gain on sale and leaseback transaction | 866 | 892 |
Accumulated deferred income taxes | 6,603 | 6,616 |
Asset retirement obligations | 1,834 | 1,599 |
Retirement benefits | 3,104 | 3,080 |
Other | 1,716 | 1,836 |
Total noncurrent liabilities | 14,590 | 14,529 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | ' | ' |
Total liabilities and capitalization | 50,383 | 50,406 |
FES | ' | ' |
CURRENT ASSETS: | ' | ' |
Cash and cash equivalents | 2 | 3 |
Receivables- | ' | ' |
Customers, net of allowance for uncollectible accounts of $14 in 2013 and $16 in 2012 | 524 | 483 |
Affiliated companies | 519 | 379 |
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012 | 123 | 91 |
Notes receivable from affiliated companies | 254 | 276 |
Materials and supplies | 439 | 505 |
Derivatives | 139 | 158 |
Prepayments and other | 105 | 87 |
Total current assets | 2,105 | 1,982 |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' |
In service | 12,508 | 11,997 |
Less - Accumulated provision for depreciation | 4,649 | 4,408 |
Property, plant and equipment in service net of accumulated provision for depreciation | 7,859 | 7,589 |
Construction work in progress | 1,116 | 1,141 |
Total net property, plant and equipment | 8,975 | 8,730 |
INVESTMENTS: | ' | ' |
Nuclear plant decommissioning trusts | 1,270 | 1,283 |
Other | 11 | 12 |
Total other property and investments | 1,281 | 1,295 |
ASSETS HELD FOR SALE (NOTE 16) | 121 | 0 |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' |
Customer intangibles | 99 | 110 |
Goodwill | 23 | 24 |
Property taxes | 36 | 36 |
Unamortized sale and leaseback costs | 161 | 119 |
Derivatives | 65 | 99 |
Other | 268 | 253 |
Total deferred charges and other assets | 652 | 641 |
Total assets | 13,134 | 12,648 |
CURRENT LIABILITIES: | ' | ' |
Currently payable long-term debt | 859 | 1,102 |
Short-term borrowings | 4 | 4 |
Accounts payable- | ' | ' |
Affiliated companies | 776 | 726 |
Other | 213 | 159 |
Accrued taxes | 42 | 171 |
Derivatives | 103 | 124 |
Other | 176 | 280 |
Total current liabilities | 2,173 | 2,566 |
Common stockholders' equity- | ' | ' |
Common stock, without par value, authorized 750 shares- 7 shares outstanding | 3,078 | 1,573 |
Accumulated other comprehensive income | 62 | 72 |
Retained earnings | 2,089 | 2,118 |
Total common stockholders' equity | 5,229 | 3,763 |
Long-term debt and other long-term obligations | 2,178 | 3,118 |
Total capitalization | 7,407 | 6,881 |
NONCURRENT LIABILITIES: | ' | ' |
Deferred gain on sale and leaseback transaction | 866 | 892 |
Accumulated deferred income taxes | 699 | 515 |
Asset retirement obligations | 1,159 | 965 |
Retirement benefits | 255 | 241 |
Derivatives | 22 | 37 |
Other | 553 | 551 |
Total noncurrent liabilities | 3,554 | 3,201 |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13) | ' | ' |
Total liabilities and capitalization | $13,134 | $12,648 |
Consolidated_Balance_Sheets_Fi3
Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, except Share data, unless otherwise specified | ||
Common stockholders' equity- | ' | ' |
Common stock, shares authorized | 490,000,000 | 490,000,000 |
Common stock, shares outstanding | 418,216,437 | 418,216,437 |
Customer [Member] | ' | ' |
Receivables- | ' | ' |
Allowance for uncollectible accounts (in dollars) | 41 | 40 |
Other Receivables [Member] | ' | ' |
Receivables- | ' | ' |
Allowance for uncollectible accounts (in dollars) | 3 | 4 |
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) | 14 | 16 |
FES | Other Receivables [Member] | ' | ' |
Receivables- | ' | ' |
Allowance for uncollectible accounts (in dollars) | 3 | 2 |
Consolidated_Statements_of_Cas1
Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $) | 9 Months Ended | |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
NET INCOME | $250 | $919 |
Adjustments to reconcile net income (loss) to net cash from operating activities- | ' | ' |
Provision for depreciation | 909 | 834 |
Nuclear fuel amortization | 156 | 156 |
Deferred rents and lease market valuation liability | -22 | -62 |
Deferred income taxes and investment tax credits, net | 114 | 712 |
Investments impairments | 74 | 10 |
Pension trust contribution | 0 | -600 |
Commodity derivative transactions, net (Note 10) | 24 | -80 |
Cash collateral, net | -67 | -3 |
Loss on debt redemptions | 132 | 0 |
Make-whole premiums paid on debt redemptions | -181 | 0 |
Income from discontinued operations (Note 16) | -17 | -11 |
Decrease (increase) in operating assets- | ' | ' |
Receivables | -7 | -41 |
Materials and supplies | 117 | -63 |
Prepayments and other current assets | -59 | -151 |
Increase (decrease) in operating liabilities- | ' | ' |
Accounts payable | -279 | -227 |
Accrued taxes | -146 | -58 |
Accrued compensation and retirement benefits | -43 | -71 |
Other | -14 | 92 |
Net cash provided from operating activities | 1,671 | 1,276 |
New financing- | ' | ' |
Long-term debt | 2,745 | 660 |
Short-term borrowings, net | 1,435 | 1,604 |
Redemptions and Repayments- | ' | ' |
Long-term debt | -2,662 | -870 |
Tender premiums paid on debt redemptions | -110 | 0 |
Other | -64 | -42 |
Net cash provided from (used for) financing activities | 654 | 662 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Property additions | -1,960 | -1,686 |
Nuclear fuel | -159 | -207 |
Sales of investment securities held in trusts | 1,545 | 2,133 |
Purchases of investment securities held in trusts | -1,567 | -2,188 |
Other | 3 | -23 |
Net cash used for investing activities | -2,275 | -1,990 |
Net change in cash and cash equivalents | 50 | -52 |
Cash and cash equivalents at beginning of period | 172 | 202 |
Cash and cash equivalents at end of period | 222 | 150 |
FES | ' | ' |
CASH FLOWS FROM OPERATING ACTIVITIES: | ' | ' |
NET INCOME | -29 | 222 |
Adjustments to reconcile net income (loss) to net cash from operating activities- | ' | ' |
Provision for depreciation | 231 | 200 |
Nuclear fuel amortization | 156 | 159 |
Deferred rents and lease market valuation liability | -36 | -144 |
Deferred income taxes and investment tax credits, net | 205 | 123 |
Investments impairments | 66 | 8 |
Pension trust contribution | 0 | -209 |
Gain on asset sales | -20 | -17 |
Commodity derivative transactions, net (Note 10) | 24 | -67 |
Cash collateral, net | -35 | -4 |
Loss on debt redemptions | 103 | 0 |
Make-whole premiums paid on debt redemptions | -31 | 0 |
Income from discontinued operations (Note 16) | -14 | -11 |
Decrease (increase) in operating assets- | ' | ' |
Receivables | -214 | 95 |
Materials and supplies | 66 | -40 |
Prepayments and other current assets | -22 | 5 |
Increase (decrease) in operating liabilities- | ' | ' |
Accounts payable | 129 | 312 |
Accrued taxes | -131 | -150 |
Accrued compensation and retirement benefits | -5 | 10 |
Other | -54 | 9 |
Net cash provided from operating activities | 389 | 501 |
New financing- | ' | ' |
Long-term debt | 0 | 560 |
Short-term borrowings, net | 0 | 3 |
Equity contribution from parent | 1,500 | 0 |
Redemptions and Repayments- | ' | ' |
Long-term debt | -1,179 | -246 |
Tender premiums paid on debt redemptions | -67 | 0 |
Other | -7 | -9 |
Net cash provided from (used for) financing activities | 247 | 308 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' |
Property additions | -477 | -535 |
Nuclear fuel | -159 | -207 |
Proceeds from asset sales | 21 | 17 |
Sales of investment securities held in trusts | 650 | 1,167 |
Purchases of investment securities held in trusts | -694 | -1,194 |
Loans to affiliated companies, net | 22 | -55 |
Other | 0 | -6 |
Net cash used for investing activities | -637 | -813 |
Net change in cash and cash equivalents | -1 | -4 |
Cash and cash equivalents at beginning of period | 3 | 7 |
Cash and cash equivalents at end of period | $2 | $3 |
Organization_and_Basis_of_Pres
Organization and Basis of Presentation | 9 Months Ended |
Sep. 30, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [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 is a diversified energy holding company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and FET), FES and its principal subsidiaries (FG and NG) and FESC. During the second quarter of 2013, FE completed a $1.5 billion equity contribution to FES. | |
These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2012. | |
FirstEnergy follows GAAP and complies 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 accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair statement of the financial statements. 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 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, 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 share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. 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. | |
New Accounting Pronouncements | |
New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries. |
Goodwill
Goodwill | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Goodwill [Abstract] | ' | ||||||||||||||||||||
Goodwill | ' | ||||||||||||||||||||
GOODWILL | |||||||||||||||||||||
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy first assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then the two-step goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. | |||||||||||||||||||||
FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, Competitive Energy Services and Other/Corporate. Goodwill is allocated to these reportable segments based on the original purchase price allocation of acquisitions. Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows: | |||||||||||||||||||||
Goodwill | Regulated Distribution | Regulated Transmission | Competitive Energy Services | Other/Corporate | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 5,025 | $ | 526 | $ | 896 | $ | — | $ | 6,447 | |||||||||||
Classification to Assets Held for Sale(1) | — | — | (29 | ) | — | (29 | ) | ||||||||||||||
Balance as of September 30, 2013 | $ | 5,025 | $ | 526 | $ | 867 | $ | — | $ | 6,418 | |||||||||||
-1 | See Note 16, Discontinued Operations and Assets Held for Sale. | ||||||||||||||||||||
FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission segments as of July 31, 2013. FirstEnergy assessed economic, industry and market considerations in addition to overall financial performance of its Regulated Distribution and Regulated Transmission segments. It was determined that the fair values of these segments were, more likely than not, greater than their carrying values. Due to excess generation supply in the region, which has caused a period of protracted low power and capacity prices impacting Competitive operations, FirstEnergy performed a quantitative assessment of the Competitive Energy Services segment as of July 31, 2013. The fair value of the Competitive Energy Services segment was calculated using a discounted cash flow analysis which included the effects of the potential sale of certain hydroelectric power stations and transfer of the Harrison plant to the Regulated Distribution Segment and the Pleasants plant to the Competitive Energy Services Segment as discussed in Note 12, Regulatory Matters. Assumptions used in the analysis include discount rates, market performance, projected operating and capital cash flows and the fair value of debt. The estimated fair value of the Competitive Energy Services segment exceeded its carrying amount (including goodwill) as of July 31, 2013. Continued weak economic conditions, lower than forecasted power and capacity prices, and revised environmental requirements could have a negative impact on future goodwill assessments. | |||||||||||||||||||||
In October of 2013, in connection with the closing of the West Virginia asset transfer, as discussed in Note 12, Regulatory Matters, FirstEnergy transferred approximately $67 million of goodwill from the Competitive Energy Services segment to the Regulated Distribution segment based on the relative fair value of the generating plants to the fair value of the respective segment. |
Impairment_of_Longlived_Assets
Impairment of Long-lived Assets | 9 Months Ended | ||
Sep. 30, 2013 | |||
Property, Plant and Equipment [Abstract] | ' | ||
Impairment of Long-lived Assets | ' | ||
IMPAIRMENT OF LONG-LIVED ASSETS | |||
FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value. | |||
Generating Plant Retirements - 2013 | |||
On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013: | |||
Generating Units | MW Capacity | Location | |
Hatfield's Ferry, Units 1-3 | 1,710 | Masontown, Pennsylvania | |
Mitchell, Units 2-3 | 370 | Courtney, Pennsylvania | |
As a result of this decision, in the second quarter of 2013, FirstEnergy recorded a pre-tax impairment of approximately $473 million to continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The impairment charge is included within the results of the Competitive Energy Services Segment. | |||
Approximately 240 plant employees and generation related positions were affected by these plant deactivations. FirstEnergy recorded approximately $7 million (pre-tax) severance related expenses that were recognized in Other operating expenses in the Consolidated Statements of Income during the nine months ended 2013. | |||
On October 9, 2013, Hatfield's Ferry Units 1-3 and Mitchell Units 2-3 were deactivated. With the termination of operations at Hatfield's Ferry, AE Supply has the right to redeem $235 million of its outstanding PCRBs at par. A conditional notice of full redemption was issued on October 18, 2013, calling the $235 million of outstanding PCRB's for redemption on November 15, 2013. | |||
AE Supply has obligations, such as fuel supply, that could be affected by the plant closings and management is currently unable to reasonably estimate potential costs, or a range thereof, that could be incurred. | |||
Generating Plant Retirements - 2012 | |||
As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated. FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated. During the nine months ended September 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately $14 million ($10 million by FES) as a result of the deactivations. These costs are included in Other operating expenses in the Consolidated Statements of Income (Loss). | |||
Cost Savings Initiatives | |||
In addition to deactivating Hatfield's Ferry and Mitchell, FirstEnergy identified and intends to implement additional cost control opportunities across the organization. These actions include reductions to medical and other employee benefits and other organizational changes, including a reduction in staffing of an additional 250 positions. FirstEnergy incurred approximately $2 million (pre-tax) of severance related expenses in the third quarter of 2013. |
Earnings_Per_Share_of_Common_S
Earnings Per Share of Common Stock | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Earnings Per Share [Abstract] | ' | ||||||||||||||||
EARNINGS PER SHARE OF COMMON STOCK | ' | ||||||||||||||||
EARNINGS PER SHARE OF COMMON STOCK | |||||||||||||||||
Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. | |||||||||||||||||
The following table reconciles basic and diluted earnings per share of common stock: | |||||||||||||||||
Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||||||||||
Reconciliation of Basic and Diluted Earnings per Share of Common Stock | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions, except per share amounts) | |||||||||||||||||
Net income from continuing operations | $ | 209 | $ | 422 | $ | 233 | $ | 908 | |||||||||
Less: Income attributable to noncontrolling interest | — | — | — | 1 | |||||||||||||
Income from continuing operations available to common shareholders | 209 | 422 | 233 | 907 | |||||||||||||
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 | |||||||||||||
Earnings available to FirstEnergy Corp. | $ | 218 | $ | 425 | $ | 250 | $ | 918 | |||||||||
Weighted average number of basic shares outstanding | 418 | 417 | 418 | 418 | |||||||||||||
Assumed exercise of dilutive stock options and awards(1) | 1 | 2 | 1 | 1 | |||||||||||||
Weighted average number of diluted shares outstanding | 419 | 419 | 419 | 419 | |||||||||||||
Earnings per share: | |||||||||||||||||
Basic earnings per share: | |||||||||||||||||
Net income from continuing operations | $ | 0.5 | $ | 1.01 | $ | 0.56 | $ | 2.17 | |||||||||
Discontinued operations (Note 16) | 0.02 | 0.01 | 0.04 | 0.03 | |||||||||||||
Net earnings per basic share | $ | 0.52 | $ | 1.02 | $ | 0.6 | $ | 2.2 | |||||||||
Diluted earnings per share: | |||||||||||||||||
Net income from continuing operations | $ | 0.5 | $ | 1 | $ | 0.56 | $ | 2.16 | |||||||||
Discontinued operations (Note 16) | 0.02 | 0.01 | 0.04 | 0.03 | |||||||||||||
Net earnings per diluted share | $ | 0.52 | $ | 1.01 | $ | 0.6 | $ | 2.19 | |||||||||
(1) | For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. |
Pension_and_Other_Postemployme
Pension and Other Postemployment Benefits | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS | ' | ||||||||||||||||
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS | |||||||||||||||||
The components of the consolidated net periodic cost for pensions and OPEB (including amounts capitalized) were as follows: | |||||||||||||||||
Components of Net Periodic Benefit Costs (Credits) | Pensions | OPEB | |||||||||||||||
For the Three Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
Service costs | $ | 49 | $ | 40 | $ | 3 | $ | 3 | |||||||||
Interest costs | 93 | 97 | 9 | 12 | |||||||||||||
Expected return on plan assets | (125 | ) | (121 | ) | (8 | ) | (9 | ) | |||||||||
Amortization of prior service costs (credits) | 3 | 3 | (50 | ) | (50 | ) | |||||||||||
Net periodic costs (credits) | $ | 20 | $ | 19 | $ | (46 | ) | $ | (44 | ) | |||||||
Components of Net Periodic Benefit Costs (Credits) | Pensions | OPEB | |||||||||||||||
For the Nine Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
Service costs | $ | 147 | $ | 120 | $ | 9 | $ | 9 | |||||||||
Interest costs | 279 | 291 | 27 | 36 | |||||||||||||
Expected return on plan assets | (375 | ) | (363 | ) | (24 | ) | (27 | ) | |||||||||
Amortization of prior service costs (credits) | 9 | 9 | (157 | ) | (152 | ) | |||||||||||
Net periodic costs (credits) | $ | 60 | $ | 57 | $ | (145 | ) | $ | (134 | ) | |||||||
Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and FES were as follows: | |||||||||||||||||
Net Periodic Benefit Expense (Credit) | Pensions | OPEB | |||||||||||||||
For the Three Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
FirstEnergy | $ | 16 | $ | 14 | $ | (31 | ) | $ | (30 | ) | |||||||
FES | 5 | 5 | (4 | ) | (4 | ) | |||||||||||
Net Periodic Benefit Expense (Credit) | Pensions | OPEB | |||||||||||||||
For the Nine Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
FirstEnergy | $ | 41 | $ | 41 | $ | (95 | ) | $ | (92 | ) | |||||||
FES | 13 | 13 | (12 | ) | (12 | ) | |||||||||||
Accumulated_Other_Comprehensiv
Accumulated Other Comprehensive Income | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Statement of Other Comprehensive Income [Abstract] | ' | ||||||||||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME | ' | ||||||||||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME | |||||||||||||||||
The changes in AOCI, net of tax, in the three and nine months ended September 30, 2013 and 2012, for FirstEnergy and FES are shown in the following tables: | |||||||||||||||||
FirstEnergy | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of July 1, 2013 | $ | (37 | ) | $ | 13 | $ | 347 | $ | 323 | ||||||||
Other comprehensive income before reclassifications | — | 5 | — | 5 | |||||||||||||
Amounts reclassified from AOCI | 1 | (1 | ) | (29 | ) | (29 | ) | ||||||||||
Net other comprehensive income (loss) | 1 | 4 | (29 | ) | (24 | ) | |||||||||||
AOCI Balance as of September 30, 2013 | $ | (36 | ) | $ | 17 | $ | 318 | $ | 299 | ||||||||
AOCI Balance as of July 1, 2012 | $ | (39 | ) | $ | 27 | $ | 401 | $ | 389 | ||||||||
Other comprehensive income before reclassifications | — | 25 | — | 25 | |||||||||||||
Amounts reclassified from AOCI | — | (25 | ) | (22 | ) | (47 | ) | ||||||||||
Net other comprehensive loss | — | — | (22 | ) | (22 | ) | |||||||||||
AOCI Balance as of September 30, 2012 | $ | (39 | ) | $ | 27 | $ | 379 | $ | 367 | ||||||||
FES | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of July 1, 2013 | $ | 1 | $ | 12 | $ | 49 | $ | 62 | |||||||||
Other comprehensive income before reclassifications | — | 4 | — | 4 | |||||||||||||
Amounts reclassified from AOCI | — | (1 | ) | (3 | ) | (4 | ) | ||||||||||
Net other comprehensive income (loss) | — | 3 | (3 | ) | — | ||||||||||||
AOCI Balance as of September 30, 2013 | $ | 1 | $ | 15 | $ | 46 | $ | 62 | |||||||||
AOCI Balance as of July 1, 2012 | $ | 6 | $ | 25 | $ | 53 | $ | 84 | |||||||||
Other comprehensive income (loss) before reclassifications | (1 | ) | 24 | — | 23 | ||||||||||||
Amounts reclassified from AOCI | (1 | ) | (25 | ) | (3 | ) | (29 | ) | |||||||||
Net other comprehensive loss | (2 | ) | (1 | ) | (3 | ) | (6 | ) | |||||||||
AOCI Balance as of September 30, 2012 | $ | 4 | $ | 24 | $ | 50 | $ | 78 | |||||||||
FirstEnergy | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of January 1, 2013 | $ | (38 | ) | $ | 15 | $ | 408 | $ | 385 | ||||||||
Other comprehensive income before reclassifications | — | 19 | — | 19 | |||||||||||||
Amounts reclassified from AOCI | 2 | (17 | ) | (90 | ) | (105 | ) | ||||||||||
Net other comprehensive income (loss) | 2 | 2 | (90 | ) | (86 | ) | |||||||||||
AOCI Balance as of September 30, 2013 | $ | (36 | ) | $ | 17 | $ | 318 | $ | 299 | ||||||||
AOCI Balance as of January 1, 2012 | $ | (39 | ) | $ | 19 | $ | 446 | $ | 426 | ||||||||
Other comprehensive income before reclassifications | 1 | 38 | 5 | 44 | |||||||||||||
Amounts reclassified from AOCI | (1 | ) | (30 | ) | (72 | ) | (103 | ) | |||||||||
Net other comprehensive income (loss) | — | 8 | (67 | ) | (59 | ) | |||||||||||
AOCI Balance as of September 30, 2012 | $ | (39 | ) | $ | 27 | $ | 379 | $ | 367 | ||||||||
FES | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of January 1, 2013 | $ | 3 | $ | 13 | $ | 56 | $ | 72 | |||||||||
Other comprehensive income before reclassifications | — | 17 | — | 17 | |||||||||||||
Amounts reclassified from AOCI | (2 | ) | (15 | ) | (10 | ) | (27 | ) | |||||||||
Net other comprehensive income (loss) | (2 | ) | 2 | (10 | ) | (10 | ) | ||||||||||
AOCI Balance as of September 30, 2013 | $ | 1 | $ | 15 | $ | 46 | $ | 62 | |||||||||
AOCI Balance as of January 1, 2012 | $ | 8 | $ | 16 | $ | 52 | $ | 76 | |||||||||
Other comprehensive income before reclassifications | — | 37 | 8 | 45 | |||||||||||||
Amounts reclassified from AOCI | (4 | ) | (29 | ) | (10 | ) | (43 | ) | |||||||||
Net other comprehensive income (loss) | (4 | ) | 8 | (2 | ) | 2 | |||||||||||
AOCI Balance as of September 30, 2012 | $ | 4 | $ | 24 | $ | 50 | $ | 78 | |||||||||
The following amounts were reclassified from AOCI in the three months ended September 30, 2013 and 2012: | |||||||||||||||||
FE | Three Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (1 | ) | $ | (2 | ) | Other operating expenses | ||||||||||
Long-term debt | 3 | 2 | Interest expense | ||||||||||||||
2 | — | Total before taxes | |||||||||||||||
(1 | ) | — | Income taxes | ||||||||||||||
$ | 1 | $ | — | Net of tax | |||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (2 | ) | $ | (40 | ) | Investment income | ||||||||||
1 | 15 | Income taxes | |||||||||||||||
$ | (1 | ) | $ | (25 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (47 | ) | $ | (47 | ) | (a) | ||||||||||
18 | 25 | Income taxes | |||||||||||||||
$ | (29 | ) | $ | (22 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
FES | Three Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (1 | ) | $ | (2 | ) | Other operating expenses | ||||||||||
1 | 1 | Income taxes (benefits) | |||||||||||||||
$ | — | $ | (1 | ) | Net of tax | ||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (2 | ) | $ | (40 | ) | Investment income (loss) | ||||||||||
1 | 15 | Income taxes (benefits) | |||||||||||||||
$ | (1 | ) | $ | (25 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (5 | ) | $ | (5 | ) | (a) | ||||||||||
2 | 2 | Income taxes (benefits) | |||||||||||||||
$ | (3 | ) | $ | (3 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
The following amounts were reclassified from AOCI in the nine months ended September 30, 2013 and 2012: | |||||||||||||||||
FE | Nine Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (5 | ) | $ | (7 | ) | Other operating expenses | ||||||||||
Long-term debt | 9 | 6 | Interest expense | ||||||||||||||
4 | (1 | ) | Total before taxes | ||||||||||||||
(2 | ) | — | Income taxes | ||||||||||||||
$ | 2 | $ | (1 | ) | Net of tax | ||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (27 | ) | $ | (48 | ) | Investment income | ||||||||||
10 | 18 | Income taxes | |||||||||||||||
$ | (17 | ) | $ | (30 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (148 | ) | $ | (143 | ) | (a) | ||||||||||
58 | 71 | Income taxes | |||||||||||||||
$ | (90 | ) | $ | (72 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
FES | Nine Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (5 | ) | $ | (6 | ) | Other operating expenses | ||||||||||
Long-term debt | 2 | — | Interest expense | ||||||||||||||
(3 | ) | (6 | ) | Total before taxes | |||||||||||||
1 | 2 | Income taxes (benefits) | |||||||||||||||
$ | (2 | ) | $ | (4 | ) | Net of tax | |||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (24 | ) | $ | (46 | ) | Investment income (loss) | ||||||||||
9 | 17 | Income taxes (benefits) | |||||||||||||||
$ | (15 | ) | $ | (29 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (16 | ) | $ | (15 | ) | (a) | ||||||||||
6 | 5 | Income taxes (benefits) | |||||||||||||||
$ | (10 | ) | $ | (10 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. |
Income_Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2013 | |
Income Tax Disclosure [Abstract] | ' |
INCOME TAXES | ' |
INCOME TAXES | |
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Judgment is required in determining FirstEnergy's income taxes and in evaluating tax positions taken or expected to be taken on its tax returns. In the third quarter of 2013, FirstEnergy increased its liability for unrecognized income tax benefits by approximately $5 million. There were no material changes to FirstEnergy's unrecognized income tax benefits during the first nine months of 2012. | |
As of September 30, 2013, it is reasonably possible that approximately $4 million of unrecognized income tax benefits may be resolved within the next twelve months, all of which, if recognized, would affect FirstEnergy's effective tax rate. | |
FirstEnergy recognizes interest expense or income related to uncertain tax positions. 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 tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. During the first nine months of 2013 and 2012, there were no material changes to the amount of accrued interest. The net amount of interest accrued as of September 30, 2013 and December 31, 2012 was approximately $10 million and $9 million, respectively. | |
As of December 31, 2012, the deferred income taxes consisted of $319 million of current federal, $466 million of long-term federal and $389 million of state and local net operating loss carryforwards. The American Taxpayer Relief Act of 2012 (Act) was enacted in January 2013 and provides 50% accelerated (bonus) depreciation for qualifying expenditures made in 2013. As a result of the availability of 50% bonus depreciation for 2013, none of the $319 million of the current federal deferred tax asset as of December 31, 2012, will be realized in 2013, but will be available for future periods. As of September 30, 2013, FirstEnergy expects to utilize federal and state net operating loss carryforwards in the next twelve months and therefore has classified $290 million to current deferred income taxes. | |
As discussed in Note 3, Impairment of Long-Lived Assets, on July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating two coal-fired generating plants. As a result of the decision, FirstEnergy determined that it is more likely than not that certain state and local net operating loss carryforwards will not be realized through future operations or through the reversal of existing temporary differences. As a result, FirstEnergy recorded a valuation reserve of approximately $20 million against net operating loss carryforwards in the second quarter of 2013. | |
On July 9, 2013, Pennsylvania House Bill 465 (HB 465) was enacted, adopting new market-based sourcing rules for certain items of income as well as increasing the Pennsylvania net operating loss deduction credit for tax years beginning after December 31, 2013 and 2014 to the greater of 25% or $4 million of taxable income and 30% or $5 million of taxable income, respectively. Based on income projections, Pennsylvania net operating loss carryforward valuation reserves were reduced by approximately $8 million in the third quarter of 2013. | |
During the third quarter of 2013, FirstEnergy made changes to state apportionment factors in certain jurisdictions based on sales sourcing rules for electricity, which reduced deferred tax liabilities by approximately $9 million. Furthermore, in the third quarter of 2013, based on the assessment of business operations, FirstEnergy determined that income from certain subsidiaries should not be apportioned to certain tax jurisdictions due to the absence of business nexus. This assessment resulted in a reduction to deferred tax liabilities of approximately $22 million. | |
FirstEnergy's three and nine months ended September 30, 2013 effective tax rate was 26.9% and 35.6%, respectively. The effective tax rate for the three months ended September 30, 2013 benefited by reductions in valuation reserves against net operating loss carryforwards, and changes in state apportionment factors as described above. The effective tax rate for the nine months ended September 30, 2013 benefited by changes in state apportionment factors as discussed above, however, was partially offset by a net increase in valuation reserves against net operating loss carryforwards. | |
FirstEnergy's three and nine months ended September 30, 2012 effective tax rate was 42.1% and 41.7%, respectively. The effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by recognition of valuation reserves against net operating loss carryforwards and the elimination of certain tax deductions associated with Medicare Part D subsidies. | |
FES’ three and nine months ended September 30, 2013 effective tax rate was 41.1% and 30.6%, respectively. The effective tax rate for the nine months ended September 30, 2013 was impacted by the loss on debt redemptions of approximately $103 million and a $4 million valuation reserve against net operating loss carryforwards. | |
FES’ three and nine months ended September 30, 2012 effective tax rate was 40.5% and 39.7%, respectively. FES’ effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by higher state apportionment allocation factors. | |
The 2013 effective tax rate for FirstEnergy and FES is estimated to be approximately 37%. |
Variable_Interest_Entities
Variable Interest Entities | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Variable Interest Entities [Abstract] | ' | |||||||||||
VARIABLE INTEREST ENTITIES | ' | |||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||
FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 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. | ||||||||||||
VIEs included in FirstEnergy’s consolidated financial statements are: the PNBV capital trust that was created to refinance debt originally issued in connection with sale and leaseback transactions; wholly-owned limited liability companies of the Ohio Companies (as described below); wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs and special purpose limited liability companies created to issue environmental control bonds that were used to construct environmental control facilities. | ||||||||||||
In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC, respectively, as separate, wholly-owned limited liability SPEs. Each SPE is a bankruptcy-remote, special purpose limited liability company that is restricted to activities necessary to issue phase-in recovery bonds and perform other functions in connection with the bond issuance. Creditors of FirstEnergy and the Ohio Companies have no recourse to any assets or revenues of the SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property held by the SPEs (i.e. the right to impose, charge and collect irrevocable non-bypassable usage-based charges payable by retail electric customers in the service territories of the Ohio Companies) and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. The SPEs are considered VIEs and each one is consolidated into its applicable utility. In June 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. | ||||||||||||
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. The change in noncontrolling interest within the Consolidated Balance Sheets during the nine months ended September 30, 2013, was primarily due to $6 million of distributions to owners. | ||||||||||||
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into the following categories based on similar risk characteristics and significance. | ||||||||||||
Mining Operations | ||||||||||||
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. 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. | ||||||||||||
Trusts | ||||||||||||
FirstEnergy's consolidated financial statements include PNBV. FirstEnergy used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. | ||||||||||||
PATH-WV | ||||||||||||
PATH 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 AE 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 the portion of the PATH project that was to be constructed by PATH-WV. | ||||||||||||
On August 24, 2012, PJM removed the PATH project from its long-range expansion plans. See Note 12, Regulatory Matters, for additional information on the abandonment of PATH. | ||||||||||||
Power Purchase Agreements | ||||||||||||
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities 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 21 long-term power purchase agreements 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 two of these NUG entities, it does not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold variable interests in the remaining two entities; 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 to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $48 million and $65 million during the three months ended September 30, 2013 and 2012, respectively and $139 million and $184 million during the nine months ended September 30, 2013 and 2012, respectively. | ||||||||||||
Sale and Leaseback | ||||||||||||
FirstEnergy has variable interests in certain sale and leaseback transactions. 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. | ||||||||||||
During 2012, NG repurchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $129 million. In 2012, FG acquired certain equity and other lessor interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $262 million and in March of 2013, FG acquired the remaining interests for approximately $221 million. | ||||||||||||
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 September 30, 2013: | ||||||||||||
Maximum | Discounted Lease | Net | ||||||||||
Exposure | Payments, net(1) | Exposure | ||||||||||
(In millions) | ||||||||||||
FES | $ | 1,288 | $ | 1,079 | $ | 209 | ||||||
Other FE subsidiaries | 762 | 329 | 433 | |||||||||
(1) | The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion. |
Fair_Value_Measurements
Fair Value Measurements | 9 Months Ended | |||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ' | |||||||||||||||||||||||||||||||||||
FAIR VALUE MEASUREMENTS | ' | |||||||||||||||||||||||||||||||||||
FAIR VALUE MEASUREMENTS | ||||||||||||||||||||||||||||||||||||
RECURRING AND NONRECURRING 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, NUGs and LCAPPs are as 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 RTO 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 RTO 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 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs. | ||||||||||||||||||||||||||||||||||||
NUG contracts represent purchase power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next three 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. | ||||||||||||||||||||||||||||||||||||
LCAPP contracts are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. LCAPP contracts are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2016/2017 delivery year are developed through a simulation of future PJM RPM auctions. The capacity price forecast assumes a continuation of the current PJM RPM market design and is reflective of the regional peak demand growth and generation fleet additions and retirements that underlie FirstEnergy’s long-term energy price forecast. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 10, Derivative Instruments for additional information regarding LCAAP contracts. | ||||||||||||||||||||||||||||||||||||
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 September 30, 2013, from those used as of December 31, 2012. 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 nine months ended September 30, 2013. 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 | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||
Assets | (In millions) | |||||||||||||||||||||||||||||||||||
Corporate debt securities | $ | — | $ | 1,299 | $ | — | $ | 1,299 | $ | — | $ | 1,259 | $ | — | $ | 1,259 | ||||||||||||||||||||
Derivative assets - commodity contracts | 4 | 197 | — | 201 | — | 252 | — | 252 | ||||||||||||||||||||||||||||
Derivative assets - FTRs | — | — | 3 | 3 | — | — | 8 | 8 | ||||||||||||||||||||||||||||
Derivative assets - NUG contracts(1) | — | — | 23 | 23 | — | — | 36 | 36 | ||||||||||||||||||||||||||||
Equity securities(2) | 461 | — | — | 461 | 310 | — | — | 310 | ||||||||||||||||||||||||||||
Foreign government debt securities | — | 101 | — | 101 | — | 126 | — | 126 | ||||||||||||||||||||||||||||
U.S. government debt securities | — | 171 | — | 171 | — | 179 | — | 179 | ||||||||||||||||||||||||||||
U.S. state debt securities | — | 226 | — | 226 | — | 299 | — | 299 | ||||||||||||||||||||||||||||
Other(3) | 160 | 157 | — | 317 | 126 | 227 | — | 353 | ||||||||||||||||||||||||||||
Total assets | $ | 625 | $ | 2,151 | $ | 26 | $ | 2,802 | $ | 436 | $ | 2,342 | $ | 44 | $ | 2,822 | ||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Derivative liabilities - commodity contracts | $ | (5 | ) | $ | (107 | ) | $ | — | $ | (112 | ) | $ | (3 | ) | $ | (151 | ) | $ | — | $ | (154 | ) | ||||||||||||||
Derivative liabilities - FTRs | — | — | (14 | ) | (14 | ) | — | — | (9 | ) | (9 | ) | ||||||||||||||||||||||||
Derivative liabilities - NUG contracts(1) | — | — | (233 | ) | (233 | ) | — | — | (290 | ) | (290 | ) | ||||||||||||||||||||||||
Derivative liabilities - LCAPP contracts(1) | — | — | (166 | ) | (166 | ) | — | — | (144 | ) | (144 | ) | ||||||||||||||||||||||||
Total liabilities | $ | (5 | ) | $ | (107 | ) | $ | (413 | ) | $ | (525 | ) | $ | (3 | ) | $ | (151 | ) | $ | (443 | ) | $ | (597 | ) | ||||||||||||
Net assets (liabilities)(4) | $ | 620 | $ | 2,044 | $ | (387 | ) | $ | 2,277 | $ | 433 | $ | 2,191 | $ | (399 | ) | $ | 2,225 | ||||||||||||||||||
(1) | NUG and LCAPP contracts are generally 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 short-term cash investments. | |||||||||||||||||||||||||||||||||||
(4) | Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, 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 and LCAPP contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
NUG Contracts(1) | LCAPP Contracts(1) | FTRs | ||||||||||||||||||||||||||||||||||
Derivative Assets | Derivative Liabilities | Net | Derivative Assets | Derivative Liabilities | Net | Derivative Assets | Derivative Liabilities | Net | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
January 1, 2012 Balance | $ | 57 | $ | (349 | ) | $ | (292 | ) | $ | — | $ | — | $ | — | $ | 1 | $ | (23 | ) | $ | (22 | ) | ||||||||||||||
Unrealized gain (loss) | (20 | ) | (180 | ) | (200 | ) | — | 1 | 1 | 6 | (6 | ) | — | |||||||||||||||||||||||
Purchases | — | — | — | — | (145 | ) | (145 | ) | 13 | (10 | ) | 3 | ||||||||||||||||||||||||
Settlements | (1 | ) | 239 | 238 | — | — | — | (12 | ) | 30 | 18 | |||||||||||||||||||||||||
December 31, 2012 Balance | $ | 36 | $ | (290 | ) | $ | (254 | ) | $ | — | $ | (144 | ) | $ | (144 | ) | $ | 8 | $ | (9 | ) | $ | (1 | ) | ||||||||||||
Unrealized gain (loss) | (6 | ) | (6 | ) | (12 | ) | — | (22 | ) | (22 | ) | 1 | 2 | 3 | ||||||||||||||||||||||
Purchases | — | — | — | — | — | — | 5 | (15 | ) | (10 | ) | |||||||||||||||||||||||||
Settlements | (7 | ) | 63 | 56 | — | — | — | (11 | ) | 8 | (3 | ) | ||||||||||||||||||||||||
September 30, 2013 Balance | $ | 23 | $ | (233 | ) | $ | (210 | ) | $ | — | $ | (166 | ) | $ | (166 | ) | $ | 3 | $ | (14 | ) | $ | (11 | ) | ||||||||||||
(1) | Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. | |||||||||||||||||||||||||||||||||||
Level 3 Quantitative Information | ||||||||||||||||||||||||||||||||||||
The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2013: | ||||||||||||||||||||||||||||||||||||
Fair Value, Net (In millions) | Valuation | Significant Input | Range | Weighted Average | Units | |||||||||||||||||||||||||||||||
Technique | ||||||||||||||||||||||||||||||||||||
FTRs | $ | (11 | ) | Model | RTO auction clearing prices | ($5.60) to $5.40 | $0.62 | Dollars/MWH | ||||||||||||||||||||||||||||
NUG Contracts | $ | (210 | ) | Model | Generation | 600 to 5,864,000 | 1,421,000 | MWH | ||||||||||||||||||||||||||||
Electricity regional prices | $41.40 to $57.30 | $49.40 | Dollars/MWH | |||||||||||||||||||||||||||||||||
LCAPP Contracts | $ | (166 | ) | Model | Regional capacity prices | $158.60 to $187.60 | $171.20 | Dollars/MW-Day | ||||||||||||||||||||||||||||
FES | ||||||||||||||||||||||||||||||||||||
Recurring Fair Value Measurements | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||
Assets | (In millions) | |||||||||||||||||||||||||||||||||||
Corporate debt securities | $ | — | $ | 742 | $ | — | $ | 742 | $ | — | $ | 703 | $ | — | $ | 703 | ||||||||||||||||||||
Derivative assets - commodity contracts | 4 | 197 | — | 201 | — | 252 | — | 252 | ||||||||||||||||||||||||||||
Derivative assets - FTRs | — | — | 2 | 2 | — | — | 6 | 6 | ||||||||||||||||||||||||||||
Equity securities(1) | 338 | — | — | 338 | 294 | — | — | 294 | ||||||||||||||||||||||||||||
Foreign government debt securities | — | 58 | — | 58 | — | 61 | — | 61 | ||||||||||||||||||||||||||||
U.S. government debt securities | — | 26 | — | 26 | — | 27 | — | 27 | ||||||||||||||||||||||||||||
Other(2) | — | 94 | — | 94 | — | 104 | — | 104 | ||||||||||||||||||||||||||||
Total assets | $ | 342 | $ | 1,117 | $ | 2 | $ | 1,461 | $ | 294 | $ | 1,147 | $ | 6 | $ | 1,447 | ||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Derivative liabilities - commodity contracts | $ | (5 | ) | $ | (107 | ) | $ | — | $ | (112 | ) | $ | (3 | ) | $ | (151 | ) | $ | — | $ | (154 | ) | ||||||||||||||
Derivative liabilities - FTRs | — | — | (13 | ) | (13 | ) | — | — | (6 | ) | (6 | ) | ||||||||||||||||||||||||
Total liabilities | $ | (5 | ) | $ | (107 | ) | $ | (13 | ) | $ | (125 | ) | $ | (3 | ) | $ | (151 | ) | $ | (6 | ) | $ | (160 | ) | ||||||||||||
Net assets (liabilities)(3) | $ | 337 | $ | 1,010 | $ | (11 | ) | $ | 1,336 | $ | 291 | $ | 996 | $ | — | $ | 1,287 | |||||||||||||||||||
(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 $12 million and $94 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with the 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 September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
Derivative Asset FTRs | Derivative Liability FTRs | Net FTRs | ||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
January 1, 2012 Balance | $ | 1 | $ | (7 | ) | $ | (6 | ) | ||||||||||||||||||||||||||||
Unrealized gain (loss) | 4 | (4 | ) | — | ||||||||||||||||||||||||||||||||
Purchases | 9 | (7 | ) | 2 | ||||||||||||||||||||||||||||||||
Settlements | (8 | ) | 12 | 4 | ||||||||||||||||||||||||||||||||
December 31, 2012 Balance | $ | 6 | $ | (6 | ) | $ | — | |||||||||||||||||||||||||||||
Unrealized loss | (1 | ) | (1 | ) | (2 | ) | ||||||||||||||||||||||||||||||
Purchases | 4 | (12 | ) | (8 | ) | |||||||||||||||||||||||||||||||
Settlements | (7 | ) | 6 | (1 | ) | |||||||||||||||||||||||||||||||
September 30, 2013 Balance | $ | 2 | $ | (13 | ) | $ | (11 | ) | ||||||||||||||||||||||||||||
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 September 30, 2013: | ||||||||||||||||||||||||||||||||||||
Fair Value, Net (In millions) | Valuation | Significant Input | Range | Weighted Average | Units | |||||||||||||||||||||||||||||||
Technique | ||||||||||||||||||||||||||||||||||||
FTRs | $ | (11 | ) | Model | RTO auction clearing prices | ($5.60) to $5.40 | $0.40 | 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, AFS securities and notes receivable. | ||||||||||||||||||||||||||||||||||||
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 first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value. | ||||||||||||||||||||||||||||||||||||
Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI. | ||||||||||||||||||||||||||||||||||||
The 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, nuclear fuel disposal and NUG 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, nuclear fuel disposal and NUG trusts as of September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
September 30, 2013(1) | December 31, 2012(2) | |||||||||||||||||||||||||||||||||||
Cost Basis | Unrealized Gains | Fair Value | Cost Basis | Unrealized Gains | Fair Value | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Debt securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,825 | $ | 21 | $ | 1,846 | $ | 1,827 | $ | 34 | $ | 1,861 | ||||||||||||||||||||||||
FES | 868 | 9 | 877 | 778 | 14 | 792 | ||||||||||||||||||||||||||||||
Equity securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 433 | $ | 28 | $ | 461 | $ | 293 | $ | 16 | $ | 309 | ||||||||||||||||||||||||
FES | 317 | 21 | 338 | 281 | 13 | 294 | ||||||||||||||||||||||||||||||
(1) | Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million. | |||||||||||||||||||||||||||||||||||
(2) | Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 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 months and nine months ended September 30, 2013 and 2012 were as follows: | ||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and | |||||||||||||||||||||||||||||||
Dividend Income | ||||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 368 | $ | 9 | $ | (15 | ) | $ | (21 | ) | $ | 26 | ||||||||||||||||||||||||
FES | 164 | 5 | (3 | ) | (21 | ) | 16 | |||||||||||||||||||||||||||||
September 30, 2012 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and Dividend Income | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,751 | $ | 81 | $ | (30 | ) | $ | (2 | ) | $ | 18 | ||||||||||||||||||||||||
FES | 1,059 | 60 | (21 | ) | (2 | ) | 10 | |||||||||||||||||||||||||||||
Nine Months Ended | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and | |||||||||||||||||||||||||||||||
Dividend Income | ||||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,545 | $ | 49 | $ | (31 | ) | $ | (74 | ) | $ | 74 | ||||||||||||||||||||||||
FES | 650 | 38 | (14 | ) | (66 | ) | 44 | |||||||||||||||||||||||||||||
September 30, 2012 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and Dividend Income | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 2,133 | $ | 118 | $ | (58 | ) | $ | (9 | ) | $ | 51 | ||||||||||||||||||||||||
FES | 1,167 | 85 | (40 | ) | (8 | ) | 27 | |||||||||||||||||||||||||||||
Held-To-Maturity Securities | ||||||||||||||||||||||||||||||||||||
The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||||||
Cost Basis | Unrealized Gains | Fair Value | Cost Basis | Unrealized Gains | Fair Value | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Debt Securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 46 | $ | 1 | $ | 47 | $ | 54 | $ | 30 | $ | 84 | ||||||||||||||||||||||||
Investments in emission allowances, employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $646 million as of September 30, 2013, and $644 million as of December 31, 2012, 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 and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||||||||||||||||||||||
Value | Value | Value | Value | |||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 17,007 | $ | 17,721 | $ | 16,957 | $ | 19,460 | ||||||||||||||||||||||||||||
FES | 3,015 | 3,082 | 4,194 | 4,524 | ||||||||||||||||||||||||||||||||
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 and its subsidiaries. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of September 30, 2013 and December 31, 2012. | ||||||||||||||||||||||||||||||||||||
During the first quarter of 2013, FE issued in aggregate $1.5 billion of senior unsecured notes in two series: $650 million of 2.75% senior notes due March 15, 2018 and $850 million of 4.25% senior notes due March 15, 2023. The stated interest rates are subject to adjustments based upon changes in the credit ratings of FirstEnergy but will not decrease below the issued rates. The proceeds were used to repay short-term borrowings and to invest in the money pool for FES and AE Supply's use in funding a portion of their concurrent tender offers. | ||||||||||||||||||||||||||||||||||||
Also during the first quarter of 2013, pursuant to tender offers launched in February 2013, FES and AE Supply repurchased $369 million and $294 million, respectively, of outstanding senior notes with interest rates ranging from 5.75% to 6.8%. The $369 million of FES repurchases consisted of original maturities of $252 million due 2021 and $117 million due 2039. The $294 million of AE Supply repurchases consisted of original maturities of $194 million due 2019 and $100 million due 2039. FES and AE Supply paid $67 million and $43 million, respectively, in tender premiums to repurchase the tendered senior notes. FirstEnergy recorded a loss on debt redemption of $119 million (FES - $71 million), including such premiums and other related expenses. The tender premiums paid are included in cash flows from financing activities in the Consolidated Statement of Cash Flows. | ||||||||||||||||||||||||||||||||||||
In March 2013, ME issued $300 million of 3.50% senior unsecured notes due March 15, 2023. Proceeds from this offering were used to repay $150 million of ME 4.95% senior unsecured notes that matured in March 2013 and short-term borrowings. | ||||||||||||||||||||||||||||||||||||
On April 15, 2013, FES redeemed $400 million of its 4.80% senior notes due 2015 and recorded a loss on debt redemption of $32 million including $31 million of make-whole premiums paid. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. | ||||||||||||||||||||||||||||||||||||
On June 3, 2013, FG exercised a mandatory put option and repurchased approximately $235 million of PCRBs due 2023, which FG is currently holding for remarketing subject to future market and other conditions. | ||||||||||||||||||||||||||||||||||||
As discussed in Note 8, Variable Interest Entities, in June 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. | ||||||||||||||||||||||||||||||||||||
During August, the Ohio Companies redeemed an additional $660 million of long-term debt with interest rates ranging from 5.65% to 7.25% and paid approximately $120 million of make-whole premiums which were deferred as a regulatory asset and will be amortized over the original life of the redeemed debt. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. Additionally, during August, JCP&L issued $500 million of 4.7% unsecured notes due April 2024 and used the proceeds to pay down a portion of its short-term debt obligations. | ||||||||||||||||||||||||||||||||||||
On May 8, 2013, FE, FES, and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million. | ||||||||||||||||||||||||||||||||||||
On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility. Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The effect of these amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013. |
Derivative_Instruments
Derivative Instruments | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
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 relating 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. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualified and were designated as cash flow hedge instruments are recorded in AOCI. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has contractual derivative agreements through 2031. | |||||||||||||||||
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. The effective portion of gains and losses on a derivative contract is reported as a component of AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. | |||||||||||||||||
Total net unamortized gains included in AOCI associated with instruments previously designated to be in a cash flow hedging relationship totaled $5 million and $10 million as of September 30, 2013 and December 31, 2012, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $10 million is expected to be amortized to income during the next twelve months. | |||||||||||||||||
FirstEnergy has used forward starting 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 treated 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. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of September 30, 2013 or December 31, 2012. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $61 million and $70 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. | |||||||||||||||||
Refer to Note 6, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||
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. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of September 30, 2013 and December 31, 2012, 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 $48 million and $79 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $13 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $4 million and $6 million during the three months ended September 30, 2013 and 2012, respectively and $15 million and $17 million during the nine months ended September 30, 2013 and 2012, respectively. In connection with the redemptions of senior notes by FES and taxable bonds by CEI and OE, unamortized gains associated with fixed for floating interest rate swap agreements of $9 million and $17 million were included in the Gain (loss) on debt redemptions in the Consolidated Statements of Income for the three and nine months ended September 30, 2013, respectively. Refer to Note 9, Fair Value Measurements - Long-Term Debt and Other Long-Term Obligations, for additional information regarding FirstEnergy's debt redemptions during the three and nine months ended September 30, 2013. | |||||||||||||||||
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. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. | |||||||||||||||||
As of September 30, 2013, FirstEnergy’s net asset position under commodity derivative contracts was $89 million, which related to FES positions. Under these commodity derivative contracts, FES posted $43 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $9 million of additional collateral if the credit rating for its debt were to fall below investment grade. | |||||||||||||||||
Based on commodity derivative contracts held as of September 30, 2013, an adverse change of 10% in commodity prices would decrease net income by approximately $27 million during the next twelve months. | |||||||||||||||||
Interest Rate Swaps | |||||||||||||||||
In 2013, in connection with certain debt redemptions, FirstEnergy recorded gains of approximately $17 million, including $9 million in the third quarter related to terminated interest rate swaps. In August 2012, FirstEnergy terminated all of the forward starting swap agreements that were executed in the second quarter of 2012, resulting in a net gain, recorded in the third quarter of 2012 as a reduction to interest expense, and cash proceeds of approximately $6 million. | |||||||||||||||||
NUGs | |||||||||||||||||
As of September 30, 2013, FirstEnergy's net liability position under NUG contracts was $210 million representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. | |||||||||||||||||
LCAPP | |||||||||||||||||
The LCAPP law was enacted in New Jersey during 2011 to promote the construction of qualified electric generation facilities. JCP&L maintains two LCAPP contracts, which are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. JCP&L expects to recover from its customers payments made to the generators and give credit to customers for payments from the generators under these contracts. As a result, the projected future obligations for the LCAPP contracts are reflected on the Consolidated Balance Sheets as derivative liabilities with a corresponding regulatory asset. Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP is preempted by the FPA and unconstitutional. On October 22, 2013, the Superior Court of New Jersey Appellate Division dismissed two consolidated appeals which had been taken from the final order of the NJBPU which accepted and adopted the recommendation of the NJBPU's Agent regarding implementation of the LCAPP law. Dismissal of the consolidated appeals, along with pending matters currently on remand to the NJBPU, was without prejudice subject to the parties exercising their appellate rights in the federal courts. JCP&L continues to maintain a derivative liability with a corresponding regulatory asset on its Consolidated Balance Sheet until the the matter is finally resolved. | |||||||||||||||||
FTRs | |||||||||||||||||
As of September 30, 2013, FirstEnergy's and FES's net liability position under FTRs was $11 million and FES posted $6 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 an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE. | |||||||||||||||||
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 the RTO, 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 | ||||||||||||||||
September 30, | December 31, | September 30, | December 31, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(In millions) | (In millions) | ||||||||||||||||
Current Assets - Derivatives | Current Liabilities - Derivatives | ||||||||||||||||
Commodity Contracts | $ | 137 | $ | 153 | Commodity Contracts | $ | (94 | ) | $ | (119 | ) | ||||||
FTRs | 3 | 7 | FTRs | (11 | ) | (7 | ) | ||||||||||
140 | 160 | (105 | ) | (126 | ) | ||||||||||||
Noncurrent Liabilities - Adverse Power Contract Liability | |||||||||||||||||
NUGs | (233 | ) | (290 | ) | |||||||||||||
Deferred Charges and Other Assets - Other | LCAAP | (166 | ) | (144 | ) | ||||||||||||
Commodity Contracts | 64 | 99 | Noncurrent Liabilities - Other | ||||||||||||||
FTRs | — | 1 | Commodity Contracts | (18 | ) | (36 | ) | ||||||||||
NUGs | 23 | 36 | FTRs | (3 | ) | (2 | ) | ||||||||||
87 | 136 | (420 | ) | (472 | ) | ||||||||||||
Derivative Assets | $ | 227 | $ | 296 | Derivative Liabilities | $ | (525 | ) | $ | (598 | ) | ||||||
FirstEnergy enters into contracts with counterparties that allow for net settlement of derivative assets and derivative liabilities. 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 instruments 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 | |||||||||||||||||
September 30, 2013 | Fair Value | Derivative Instruments | Cash Collateral (Received)/Pledged | Net Fair Value | |||||||||||||
(In millions) | |||||||||||||||||
Derivative Assets | |||||||||||||||||
Commodity contracts | $ | 201 | $ | (104 | ) | $ | (11 | ) | $ | 86 | |||||||
FTRs | 3 | (3 | ) | — | — | ||||||||||||
NUG contracts | 23 | — | — | 23 | |||||||||||||
$ | 227 | $ | (107 | ) | $ | (11 | ) | $ | 109 | ||||||||
Derivative Liabilities | |||||||||||||||||
Commodity contracts | $ | (112 | ) | $ | 104 | $ | 5 | $ | (3 | ) | |||||||
FTRs | (14 | ) | 3 | 6 | (5 | ) | |||||||||||
NUG contracts | (233 | ) | — | — | (233 | ) | |||||||||||
LCAPP contracts | (166 | ) | — | — | (166 | ) | |||||||||||
$ | (525 | ) | $ | 107 | $ | 11 | $ | (407 | ) | ||||||||
Amounts Not Offset in Consolidated Balance Sheet | |||||||||||||||||
December 31, 2012 | Fair Value | Derivative Instruments | Cash Collateral (Received)/Pledged | Net Fair Value | |||||||||||||
(In millions) | |||||||||||||||||
Derivative Assets | |||||||||||||||||
Commodity contracts | $ | 252 | $ | (142 | ) | $ | (5 | ) | $ | 105 | |||||||
FTRs | 8 | (8 | ) | — | — | ||||||||||||
NUG contracts | 36 | — | — | 36 | |||||||||||||
$ | 296 | $ | (150 | ) | $ | (5 | ) | $ | 141 | ||||||||
Derivative Liabilities | |||||||||||||||||
Commodity contracts | $ | (155 | ) | $ | 142 | $ | 12 | $ | (1 | ) | |||||||
FTRs | (9 | ) | 8 | 1 | — | ||||||||||||
NUG contracts | (290 | ) | — | — | (290 | ) | |||||||||||
LCAPP contracts | (144 | ) | — | — | (144 | ) | |||||||||||
$ | (598 | ) | $ | 150 | $ | 13 | $ | (435 | ) | ||||||||
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2013: | |||||||||||||||||
Purchases | Sales | Net | Units | ||||||||||||||
(In millions, except for LCAPP) | |||||||||||||||||
Power Contracts | 32 | 37 | (5 | ) | MWH | ||||||||||||
FTRs | 59 | — | 59 | MWH | |||||||||||||
NUGs | 11 | — | 11 | MWH | |||||||||||||
LCAPP | 408 | — | 408 | MW | |||||||||||||
Natural Gas | 64 | — | 64 | mmBTU | |||||||||||||
The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months and nine months ended September 30, 2013 and 2012, are summarized in the following tables: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Commodity Contracts | FTRs | Interest Rate Swaps | Total | ||||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 11 | $ | (8 | ) | $ | — | $ | 3 | ||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 14 | $ | 6 | $ | — | $ | 20 | |||||||||
Purchased Power Expense | (17 | ) | — | — | (17 | ) | |||||||||||
Other Operating Expense | — | (10 | ) | — | (10 | ) | |||||||||||
Fuel Expense | (2 | ) | — | — | (2 | ) | |||||||||||
2012 | |||||||||||||||||
Unrealized Gain (Loss) Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 7 | $ | (5 | ) | $ | — | $ | 2 | ||||||||
Interest Expense | — | — | 20 | 20 | |||||||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 46 | $ | 6 | $ | — | $ | 52 | |||||||||
Purchased Power Expense | (27 | ) | — | — | (27 | ) | |||||||||||
Other Operating Expense | — | (10 | ) | — | (10 | ) | |||||||||||
Fuel Expense | 3 | — | — | 3 | |||||||||||||
Interest Expense | — | — | 6 | 6 | |||||||||||||
Nine Months Ended September 30 | |||||||||||||||||
Commodity | FTRs | Interest Rate Swaps | Total | ||||||||||||||
Contracts | |||||||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Loss Recognized in: | |||||||||||||||||
Other Operating Expense | $ | (5 | ) | $ | (10 | ) | $ | — | $ | (15 | ) | ||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 29 | $ | 19 | $ | — | $ | 48 | |||||||||
Purchased Power Expense | (30 | ) | — | — | (30 | ) | |||||||||||
Other Operating Expense | — | (28 | ) | — | (28 | ) | |||||||||||
2012 | |||||||||||||||||
Unrealized Gain Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 72 | $ | 12 | $ | — | $ | 84 | |||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 260 | $ | 18 | $ | — | $ | 278 | |||||||||
Purchased Power Expense | (248 | ) | — | — | (248 | ) | |||||||||||
Other Operating Expense | — | (51 | ) | — | (51 | ) | |||||||||||
Fuel Expense | 2 | — | — | 2 | |||||||||||||
Interest Expense | — | — | 6 | 6 | |||||||||||||
The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2013 and 2012, are summarized in the following tables: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | 7 | $ | (8 | ) | $ | 1 | $ | — | ||||||||
Realized Gain (Loss) on Derivative Instrument | 14 | — | (1 | ) | 13 | ||||||||||||
2012 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | (50 | ) | $ | 3 | $ | — | $ | (47 | ) | |||||||
Realized Gain (Loss) on Derivative Instrument | 61 | — | (1 | ) | 60 | ||||||||||||
Nine Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | (13 | ) | $ | (22 | ) | $ | 1 | $ | (34 | ) | ||||||
Realized Gain (Loss) on Derivative Instrument | 57 | — | (1 | ) | 56 | ||||||||||||
2012 | |||||||||||||||||
Unrealized Loss on Derivative Instrument | $ | (183 | ) | $ | (142 | ) | $ | — | $ | (325 | ) | ||||||
Realized Gain on Derivative Instrument | 194 | — | 7 | 201 | |||||||||||||
The following tables provide a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months and nine months ended September 30, 2013 and 2012: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
Outstanding net liability as of July 1, 2013 | $ | (231 | ) | $ | (158 | ) | $ | — | $ | (389 | ) | ||||||
Additions/Change in value of existing contracts | 7 | (8 | ) | 1 | — | ||||||||||||
Settled contracts | 14 | — | (1 | ) | 13 | ||||||||||||
Outstanding net liability as of September 30, 2013 | $ | (210 | ) | $ | (166 | ) | $ | — | $ | (376 | ) | ||||||
Outstanding net liability as of July 1, 2012 | $ | (293 | ) | $ | (145 | ) | $ | — | $ | (438 | ) | ||||||
Additions/Change in value of existing contracts | (50 | ) | 3 | — | (47 | ) | |||||||||||
Settled contracts | 61 | — | (1 | ) | 60 | ||||||||||||
Outstanding net liability as of September 30, 2012 | $ | (282 | ) | $ | (142 | ) | $ | (1 | ) | $ | (425 | ) | |||||
Nine Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
Outstanding net liability as of January 1, 2013 | $ | (254 | ) | $ | (144 | ) | $ | — | $ | (398 | ) | ||||||
Additions/Change in value of existing contracts | (13 | ) | (22 | ) | 1 | (34 | ) | ||||||||||
Settled contracts | 57 | — | (1 | ) | 56 | ||||||||||||
Outstanding net liability as of September 30, 2013 | $ | (210 | ) | $ | (166 | ) | $ | — | $ | (376 | ) | ||||||
Outstanding net liability as of January 1, 2012 | $ | (293 | ) | $ | — | $ | (8 | ) | $ | (301 | ) | ||||||
Additions/Change in value of existing contracts | (183 | ) | (142 | ) | — | (325 | ) | ||||||||||
Settled contracts | 194 | — | 7 | 201 | |||||||||||||
Outstanding net liability as of September 30, 2012 | $ | (282 | ) | $ | (142 | ) | $ | (1 | ) | $ | (425 | ) |
Asset_Retirement_Obligations
Asset Retirement Obligations | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
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. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs. | |||||||||
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 in the recognition of the liability. | |||||||||
The following table summarizes the changes to the ARO balances during 2013: | |||||||||
ARO Reconciliation | FirstEnergy | FES | |||||||
(In millions) | |||||||||
Balance, December 31, 2012 | $ | 1,599 | $ | 965 | |||||
Liabilities settled | (13 | ) | (14 | ) | |||||
Accretion | 85 | 52 | |||||||
Revisions in estimated cash flows | 163 | 156 | |||||||
Balance, September 30, 2013 | $ | 1,834 | $ | 1,159 | |||||
During the first quarter of 2013, revisions to estimated cash flows associated with the ARO liability of FES increased the liability. The revision in estimated cash flows related primarily to increased cost estimates for the closure of LBR. The revised cost estimates were the result of a Closure Plan submitted to the PA DEP by FG on March 28, 2013, which provides for placing a final cap over LBR. See Note 13, Commitments, Guarantees, and Contingencies for additional information related to the closure of LBR. | |||||||||
During the third quarter of 2013, studies were completed to update the estimated cost of asbestos remediation for TE and FES. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and TE and increased the liability for FES and TE by approximately $5 million and $7 million, respectively. |
Regulatory_Matters
Regulatory Matters | 9 Months Ended | |
Sep. 30, 2013 | ||
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 FES, AE Supply or any of their subsidiaries were to engage in the construction of significant new generation facilities in any of those states, they would also be subject to state siting authority. | ||
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 residential SOS for PE customers expired on December 31, 2012, by statute, service continues in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential SOS have also expired, however, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS. | ||
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by 10% and reduce electricity demand by 15%, in each case by 2015. PE's initial plan submitted in compliance with the statute was approved in 2009 and covered 2009-2011, the first three years of the statutory period. Expenditures were originally estimated to be approximately $101 million for the PE programs for the entire period of 2009-2015. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan for the second three year period, 2012-2014, that includes additional and improved programs. The 2012-2014 plan is expected to cost approximately $66 million out of the original $101 million estimate for the entire EmPOWER program. On December 22, 2011, the MDPSC issued an order approving PE's second plan with various modifications and follow-up assignments. 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. | ||
Pursuant to a bill passed by the Maryland legislature in 2011, the MDPSC adopted rules, effective May 28, 2012, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The MDPSC will be required to assess each utility's compliance with the new rules, and may assess penalties of up to $25,000 per day, per violation. The new rules set utility-specific SAIDI and SAIFI targets for 2012-2015; prescribe detailed tree-trimming requirements, outage restoration and downed wire response deadlines; and impose other reliability and customer satisfaction requirements. PE has advised the MDPSC that compliance with the new rules is expected to increase costs by approximately $106 million over the period 2012-2015. On April 1, 2013, the Maryland electric utilities, including PE, filed their first annual reports on compliance with the new rules. The MDPSC conducted a hearing on August 20, 2013 to discuss the reports, after which an order was issued on September 3, 2013, which accepted PE's filing and the operational changes proposed therein. | ||
Following a "derecho" storm through the region on June 29, 2012, the MDPSC convened a new proceeding to consider matters relating to the electric utilities' performance in responding to the storm. Hearings on the matter were conducted in September 2012. Concurrently, Maryland's governor convened a special panel to examine possible ways to improve the resilience of the electric distribution system. On October 3, 2012, that panel issued a report calling for various measures including: acceleration and expansion of some of the requirements contained in the reliability standards which had become final on May 28, 2012; for selective increased investment in system hardening; for creation of separate recovery mechanisms for the costs of those changes and investments; and penalties or bonuses on returns earned by the utilities based on their reliability performance. On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the utilities to submit several reports over a series of months, relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. The order further requires the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information. PE has responded to the requirements in the order consistent with the schedule set forth therein. PE's final filing on September 3, 2013, 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 27 Order, and projected that it would expect to make 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 27 Order. The MDPSC has ordered that certain reports of its Staff relating to these matters be provided by May 1, 2014, and otherwise, has not issued a schedule for further proceedings in this matter. | ||
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, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, 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. | ||
On September 7, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. In its written Order issued July 31, 2012, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that JCP&L is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year. The rate case petition was filed on November 30, 2012. In the filing, JCP&L requested approval to increase its revenues by approximately $31.5 million and reserved the right to update the filing to include costs associated with the impact of Hurricane Sandy. The NJBPU has transmitted the case to the New Jersey Office of Administrative Law for further proceedings and an ALJ has been assigned. On February 22, 2013, JCP&L updated its filing to request recovery of $603 million of distribution-related Hurricane Sandy restoration costs, resulting in increasing the total revenues requested to approximately $112 million. On June 14, 2013, JCP&L further updated its filing to: 1) include the impact of a depreciation study which had been directed by the NJBPU; 2) remove costs associated with 2012 major storms, consistent with the NJBPU orders establishing a generic proceeding to review 2011 and 2012 major storm costs (discussed below); and 3) reflect other revisions to JCP&L's filing. That filing represented an increase of approximately $20.6 million over the revenues produced by existing base rates. Testimony has also been filed in the matter by the Division of Rate Counsel and several other intervening parties in opposition to the base rate increase JCP&L requested. Specifically, the testimony of the Division of Rate Counsel's witnesses recommended that revenues produced by JCP&L's base rates for electric service be reduced by approximately $202.8 million (such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding). JCP&L filed rebuttal testimony in response to the testimony of other parties on August 7, 2013. Hearings in the rate case have commenced and are scheduled to continue through mid-November. | ||
On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by all New Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012. The Order provided that if any utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yet been determined, the prudence of such costs would be reviewed in the generic proceeding. On May 31, 2013, the NJBPU clarified its earlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding with the goal of maintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed. The NJBPU further indicated in the May 31 clarification that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding. On June 21, 2013, consistent with NJBPU's orders, JCP&L filed the detailed report in support of recovery of major storm costs with the NJBPU. On October 23, 2013, a prehearing order was issued and established that evidentiary hearings in this proceeding will be held in January 2014. JCP&L intends to vigorously pursue its position in the base rate case and full recovery of the costs associated with the major storm events of 2011 and 2012 but we cannot predict the outcome of these proceedings. | ||
Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held in September 2011 to solicit comments regarding the state of preparedness and responsiveness of New Jersey's EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 28, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the consultant's report was submitted to and subsequently accepted by the NJBPU on September 12, 2012. JCP&L submitted written comments on the report. On January 24, 2013, based upon recommendations in its consultant's report, the NJBPU ordered the New Jersey EDCs to take a number of specific actions to improve their preparedness and responses to major storms. The order includes specific deadlines for implementation of measures with respect to preparedness efforts, communications, restoration and response, post event and underlying infrastructure issues. On May 31, 2013, the NJBPU ordered that the New Jersey EDCs implement a series of new communications enhancements intended to develop more effective communications among EDCs, municipal officials, customers and the NJBPU during extreme weather events and other expected periods of extended service interruptions. The new requirements include making information regarding estimated times of restoration available on the EDC's web sites and through other technological expedients. JCP&L is implementing the required measures consistent with the schedule set out in the above NJBPU's orders. | ||
OHIO | ||
The Ohio Companies primarily operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: | ||
• | Generation supplied through a CBP; | |
• | A load cap of no less than 80%, so that no single supplier is awarded more than 80% of the tranches, which also applies to tranches assigned post-auction; | |
• | A 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); | |
• | No increase in base distribution rates through May 31, 2014; and | |
• | A new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system. | |
The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, subject to the outcome of certain PJM proceedings. The Ohio Companies have also agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements. | ||
On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012. Several parties timely filed applications for rehearing. The PUCO issued an Entry on Rehearing on January 30, 2013 denying all applications for rehearing. Notices of appeal to the Supreme Court of Ohio were filed by two parties in the case, Northeast Ohio Public Energy Council and the ELPC. The matter has not yet been scheduled for oral argument. | ||
As approved, the ESP 3 plan continues certain provisions from the current ESP including: | ||
• | Continuing the current base distribution rate freeze through May 31, 2016; | |
• | Continuing to provide economic development and assistance to low-income customers for the two-year plan period at levels established in the existing ESP; | |
• | A 6% generation rate discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); | |
• | Continuing to provide power to non-shopping customers at a market-based price set through an auction process; and | |
• | Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers. | |
As approved, the ESP 3 plan will provide additional provisions, including: | ||
• | Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and | |
• | Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period. | |
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately 1,211 GWHs in 2012 (an increase of 416,000 MWHs over 2011 levels), 1,726 GWHs in 2013, 2,306 GWHs in 2014 and 2,903 GWHs for each year thereafter through 2025. The Ohio Companies were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018. On May 15, 2013, the Ohio Companies filed their 2012 Status Update Report in which they indicated compliance with 2012 statutory energy efficiency and peak demand reduction benchmarks. | ||
In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012. Estimated costs for the three Ohio Companies' plans total approximately $250 million over the three-year period, which is expected to be recovered in rates to the extent approved by the PUCO. Hearings were held with the PUCO in October 2012. On March 20, 2013, the PUCO approved the three-year portfolio plan for 2013-2015. Applications for rehearing were filed by the Ohio Companies and several other parties on April 19, 2013. The Ohio Companies filed their request for rehearing primarily to challenge the PUCO's decision to mandate that they offer planned energy efficiency resources into PJM's base residual auction. On May 15, 2013, the PUCO granted the applications for rehearing for the sole purpose of further consideration of the matter. On July 17, 2013, the PUCO issued an entry on rehearing denying the Ohio Companies' application for rehearing, in part, but authorizing the Ohio Companies' to receive 20% of any revenues obtained from bidding energy efficiency and demand response reserves into the PJM auction. The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred. On August 16, 2013, ELPC and OCC filed applications for rehearing under the basis that the PUCO's authorization for the Ohio Companies to share in the PJM revenues was unlawful. The PUCO granted rehearing on September 11, 2013 for the sole purpose of further consideration of the issue. | ||
On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with and are not supported by statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal. The Ohio Companies' response was filed on November 4, 2013. | ||
Additionally, under SB221, electric utilities and electric service companies in Ohio are required to serve part of their load from renewable energy resources measured by an annually increasing percentage amount. In August and October 2009 and in August 2010, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these three RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and contribute toward meeting the benchmark for future years. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies will recover the costs of acquiring these RECs. The PUCO selected auditors to perform a financial and management audit, and final audit reports were filed with the PUCO on August 15, 2012. While generally supportive of the Ohio Companies' approach to procurement of RECs, the management/performance auditor recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state all renewable obligations that the auditor characterized as excessive. A hearing for this matter commenced on February 19, 2013, and concluded on February 25, 2013. The PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of renewable energy credits to meet statutory mandates in all instances except for part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of $43.3 million, plus interest, with such crediting to commence within 60 days following the issuance of a final appealable order on the basis that the Ohio Companies did not prove such purchases were prudent. The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On September 18, 2013, the PUCO issued an entry on rehearing granting rehearing solely for the purpose of further consideration of the matters specified therein. | ||
In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies achieved their in-state solar compliance requirements for 2012. The Ohio Companies also held a short-term RFP process to obtain all state SRECs and both in-state and all state non-solar RECs to help meet the statutory benchmarks for 2012. The Companies recently reported that all of the Ohio Companies met their annual renewable energy resource requirements for reporting year 2012. The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations. | ||
The PUCO instituted a statewide investigation on December 12, 2012 to evaluate the vitality of the competitive retail electric service market in Ohio. The PUCO provided interested stakeholders the opportunity to provide comments on twenty-two questions. The questions posed are categorized as market design and corporate separation. The Ohio Companies timely filed their comments on March 1, 2013, and filed reply comments on April 5, 2013. The PUCO has scheduled a series of workshops for the remainder of 2013, the first of which commenced on July 9, 2013. The Ohio Companies cannot predict the outcome of this investigation. | ||
PENNSYLVANIA | ||
The Pennsylvania Companies currently operate under DSPs that expired on May 31, 2013, 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 descending clock auctions, competitive requests for proposals and spot market purchases. On November 17, 2011, the Pennsylvania Companies filed a Joint Petition for Approval of their DSPs that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015. The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. The PPUC entered an opinion and order on August 16, 2012, which primarily resolved those issues related to procurement and rate design, but required the submission of revised proposals regarding the retail market enhancement programs. The Pennsylvania Companies filed revised proposals on the retail market enhancements on November 14, 2012. A final order was entered on February 15, 2013, which addressed minor changes to the Pennsylvania Companies' revised enhancement proposals and ordered two choices for cost recovery of those programs. On February 28, 2013, the Pennsylvania Companies filed a petition to amend the August 16, 2012, order related to the description of how the hourly industrial product is to be priced. On April 4, 2013, the PPUC entered a Final Order postponing the implementation of one of the retail market enhancements. On March 20, 2013, answers supporting and opposing the Pennsylvania Companies' February 28 petition were filed by several parties. On July 16, 2013, the PPUC entered an order granting the Pennsylvania Companies' February 28, 2013 petition, thereby amending its August 16, 2012 order and clarifying the description of the hourly industrial product pricing. The Pennsylvania Companies are actively implementing their DSPs as of June 1, 2013. On November 4, 2013, the Pennsylvania Companies filed a default service plan that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for quarterly descending clock auctions to procure 3, 12, 24, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure solar renewable energy credits for ME, PN, and Penn. The Pennsylvania Companies expect a decision from the PPUC within nine months. | ||
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN refunded those amounts to customers over a 29-month period that began in January of 2011. In April 2010, ME and PN filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME's and PN's TSC riders. The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal on February 28, 2012, and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari on October 9, 2012. On July 13, 2011, ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania for the purpose of obtaining an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges. Proceedings in the U.S. District Court effectively were suspended until conclusion of the proceedings before the United States Supreme Court. Pursuant to procedural orders issued by U.S. District Court Judge Gardner, on December 21, 2012, the PPUC submitted its motion to dismiss the U.S. District Court proceedings. ME and PN submitted their answers on January 9, 2013, and subsequent pleadings were submitted by the PPUC, ME and PN. Oral arguments on the PPUC motion to dismiss took place on May 20, 2013. On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. On October 29, 2013, ME and PN filed a notice of appeal in the U.S. Court of Appeals for the Third Circuit with respect to the U.S. District Court's decision. As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. FirstEnergy continues to believe in the merits of its case. | ||
In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN's annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal transmission losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC's approval in May 2010 authorized an increase to the TSC for ME's customers to provide for full recovery by December 31, 2010. | ||
Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed on utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted an interim report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP did not. WP could be subject to a statutory penalty of up to $20 million and is unable to predict the outcome of this matter. On July 15, 2013, the Pennsylvania Companies filed their preliminary energy efficiency and demand reduction results for the period ending May 31, 2013, indicating that all Pennsylvania Companies are expected to meet their statutory obligations. The Pennsylvania Companies are expected to report their final energy efficiency and demand reduction results for the period ending May 31, 2013, by November 15, 2013. | ||
Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs. The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016. The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator. The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012. On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue. The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps. On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement. Total costs of these plans are expected to be approximately $234 million. All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders. The remaining issue, raised by a natural gas company, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances. On March 14, 2013 the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies, adopting the settlement, and rejecting the natural gas companies recommendations. | ||
In addition, Act 129 required utilities to file a SMIP with the PPUC. On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan. The Deployment Plan requests deployment of approximately 98.5% of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about $1.25 billion. Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C. Evidentiary hearings have been held and briefs were submitted by the Pennsylvania Companies and the Office of Consumer Advocate. | ||
In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. A final order was issued on February 15, 2013 providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items. Subsequently, the PPUC established five workgroups and one comment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order. | ||
The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electricity market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by the Pennsylvania Companies and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES and the Pennsylvania Companies do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition. Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on the proposed rulemaking on April 26, 2012, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them. The House Consumer Affairs Committee of the Pennsylvania General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified. | ||
WEST VIRGINIA | ||
MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 that provided for: | ||
• | $40 million annualized base rate increases effective June 29, 2010; | |
• | Deferral of February 2010 storm restoration expenses over a maximum five-year period; | |
• | Additional $20 million annualized base rate increase effective in January 2011; | |
• | Decrease of $20 million in ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and | |
• | Moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances. | |
In February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP owns all RECs associated with the energy and capacity that MP is required to purchase pursuant to electric energy purchase agreements between MP and three NUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, opposed the petition. On November 22, 2011, the WVPSC granted ownership of all RECs produced by the facilities to MP, and held that an electric utility that purchases electric energy and capacity under an electric power purchase agreement with a Qualifying Facility under PURPA owns the RECs associated with that purchase. The West Virginia Supreme Court upheld the WVPSC's decision. The City of New Martinsville and Morgantown Energy Associates filed petitions at FERC alleging the WVPSC order violated PURPA and requested that FERC initiate an enforcement action. On April 24, 2012, FERC issued an order declining to act on the petitions and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court. MP and PE filed for rehearing of FERC's order, which was denied on September 20, 2012. The City of New Martinsville filed a complaint in the U.S. District Court for the Southern District of West Virginia on June 1, 2012, alleging that the WVPSC order violates PURPA. Morgantown Energy Associates has joined in filing a similar complaint and requesting damages in the same U.S. District Court. MP and PE filed for judgment on the pleadings in both cases on January 25, 2013. The WVPSC filed a motion to dismiss on June 28, 2013. On September 30, 2013, the District Court ruled in favor of MP and PE and the WVPSC and dismissed the proceedings with prejudice. | ||
The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities. A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held. The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan within six months and to propose a cost recovery mechanism. This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date. On July 23, 2013, MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism. On October 3, 2013, the WVPSC issued a procedural schedule for the vegetation management plan proceeding and scheduled a hearing for December 3, 2013. | ||
MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency. MP and PE have filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposes a net ownership transfer of 1,476 MW of coal-fired generation capacity to MP. The proposed transfer would involve MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply. The proposed transfer would implement a cost-effective plan to assist MP in meeting its energy and capacity obligations with its own generation resources, eliminating the need to make unhedged electricity and capacity purchases from the spot market, which is expected to result in greater rate stability for MP's customers. The plan is expected to remedy MP's capacity and energy shortfalls, which are projected to worsen due to a projected increase in annual load growth of approximately 1.4%. MP and PE will file a base rate case no later than six months from the completion of the transaction. On February 11, 2013, the WVPSC issued an order adopting a procedural schedule for this matter and testimony and briefing has followed. MP and PE also filed with FERC for authorization to effect these transfers and on April 23, 2013, FERC issued an order authorizing the transfers. MP's application for FERC authorization to effect the financing was approved on May 13, 2013. Hearings were held at the WVPSC in late May and briefs and reply briefs have been submitted. A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013. On October 7, 2013, WVPSC issued an order authorizing the transaction, with certain conditions and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately $330 million in the fourth quarter of 2013 to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory liability of approximately $23 million in the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million. | ||
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, AE Supply, FG, 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 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 occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the 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 part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows. | ||
FERC MATTERS | ||
PJM Transmission Rate | ||
PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocated for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new 500 kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identified nine separate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain LSEs in PJM bearing the majority of the costs. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis. On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp (or socialized) rate based on the amount of load served in a transmission zone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order and on March 22, 2013, FERC denied rehearing. On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing commenced on September 11, 2013, and is expected to continue into early 2014. Thereafter, the case will be scheduled for oral argument, with a decision currently expected in 2014. | ||
Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order. To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of 50% beneficiary pays and 50% postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing. On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing. On March 22, 2013, FERC granted final acceptance of the hybrid method. Certain parties have sought rehearing of parts of FERC's March 22, 2013 order. These requests for rehearing are pending before FERC. On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the New York Independent System Operator region and; (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning region. These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region. On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000. The July 10, 2013 filings are pending before FERC. | ||
RTO Realignment | ||
On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone. While most of the matters involved with the move have been resolved, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed; the details of the dispute are discussed below under "MISO Multi-Value Project Rule Proposal." In addition, FERC denied recovery of certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation issues by means of ATSI's transmission rate totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. ATSI has asked for rehearing of FERC's orders that address the Michigan Thumb transmission project and the exit fee issue. On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve certain of the exit fee and transmission cost allocation issues that are outstanding with regard to ATSI's transmission rate revisions related to ATSI's move into PJM. On September 19, 2013, FERC rejected that settlement stating ATSI had not shown why its tariff changes are just and reasonable. FERC further stated, consistent with its initial May 31, 2011 ruling on this issue that its September 19, 2013 order is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the costs that are sought to be recovered in ATSI's transmission rates. On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order. | ||
In the May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone. ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing. On November 19, 2012, ATSI filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit of FERC's ruling on the "legacy RTEP" issue, and ATSI's initial brief was filed with that court on April 11, 2013. FERC filed its brief on June 25, 2013, and FirstEnergy filed its reply brief on August 9, 2013, and final reply brief on August 28, 2013. FERC filed its final brief on August 30, 2013. The court has scheduled oral argument for December 11, 2013, and a decision is expected in the second quarter of 2014. | ||
The outcome of those proceedings that address the remaining open issues related to ATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time. | ||
MISO Multi-Value Project Rule Proposal | ||
In July 2010, MISO and certain MISO transmission owners (not including ATSI or FirstEnergy) jointly filed with FERC a proposed cost allocation methodology for certain new transmission projects. The new transmission projects - described as MVPs - are a class of transmission projects that are approved via MISO's MTEP process. Under MISO's proposal, the costs of “Michigan Thumb” MVP project that was approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would be allocated to and charged to ATSI. MISO estimated that approximately $16 million in annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction. In addition, the MISO's MVP tariffs could assess costs on PJM loads that purchase energy that has flowed over the transmission systems into the MISO. | ||
FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project onto ATSI or onto ATSI's customers. FirstEnergy asserts legal, factual and policy arguments. To date, FERC has responded in a series of orders that may require ATSI to absorb the charges for the Michigan Thumb Project pending the outcome of further regulatory proceedings and appeals. These further proceedings can be divided into two tracks: litigation related to MISO's generic MVP cost allocation proposal; and litigation related to MISO's "Schedule 39" tariff that purports to charge the MVP costs to ATSI. | ||
Regarding the first litigation track, in 2010 and 2011 FERC issued orders that approved the MISO proposal. On October 31, 2011, FirstEnergy filed a Petition of Review of those orders with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the appeals were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit. Briefs were filed in late 2012 and early 2013, and the court heard oral arguments on April 10, 2013. On June 7, 2013, the Seventh Circuit issued an order that ratified FERC's acceptance of the MISO's proposed MVP tariff. On October 7, 2013, several parties, including FirstEnergy, filed appeals of the Seventh Circuit's decision with the U.S. Supreme Court. FirstEnergy continues to evaluate the Seventh Circuit's order and its substantive and procedural options on other holdings in the opinion. | ||
Regarding the second litigation track, in February 2012, FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. FERC set for hearing the question of whether it is just and reasonable for ATSI to pay the Michigan Thumb Project costs and, if so, the amount of and methodology for calculating ATSI's Michigan Thumb Project cost responsibility. The hearings took place in April 2013, and on July 16, 2013 the ALJ issued an Initial Decision ruling that ATSI must pay the "Schedule 39" MVP costs. FirstEnergy and other parties submitted Briefs on Exceptions on August 15, 2013. The MISO and other parties filed Briefs Opposing Exceptions on September 4, 2013. The matter is pending before FERC for final decision. | ||
FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss. | ||
California Claims Matters | ||
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the U.S. Court of Appeals for the Ninth Circuit in several pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets, during 2000 and 2001. The Ninth Circuit had previously remanded one of those proceedings to FERC, which dismissed the claims of the California Parties in May 2011, and affirmed the dismissal in June 2012. On June 20, 2012, the California Parties appealed FERC's decision back to the Ninth Circuit. Briefing was completed before the Ninth Circuit on October 23, 2013. The timing of further action by the Ninth Circuit is unknown. | ||
In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed another complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001. The above-noted transactions with CDWR are the basis for including AE Supply in this complaint. AE Supply filed a motion to dismiss, which was granted by FERC in May 2011, and affirmed by FERC in June 2012. The California Attorney General has appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order. | ||
FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss. | ||
PATH Transmission Project | ||
The PATH project was proposed to be comprised of a 765 kV transmission line from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland. PJM initially authorized construction of the PATH project in June 2007. On August 24, 2012, the PJM Board of Managers canceled the PATH project, which it had suspended in February 2011. As a result, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of 10.9% (10.4% base plus 0.5% RTO membership) from PJM customers over the next five years. Several parties protested the request. On November 30, 2012, FERC issued an order denying the 0.5% return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012 subject to settlement judge procedures and hearing if the parties do not agree to a settlement. The issues subject to settlement include the prudence of the costs, the base return on equity and the period of recovery. PATH-Allegheny and PATH-WV are currently engaged in settlement discussions with the other parties. Depending on the outcome of a possible settlement or hearing, if settlement is not achieved, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate. | ||
PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the 0.5% return on equity adder for RTO membership; that request for rehearing remains pending before FERC. In addition, FERC has consolidated for settlement judge procedures and hearing purposes three formal challenges to the PATH formula rate annual updates submitted to FERC in June 2010, June 2011 and June 2012, with the September 28, 2012 filing for recovery of costs associated with the cancellation of the PATH project. FirstEnergy cannot predict the outcome of these matters or estimate the possible loss or range of loss. | ||
Seneca | ||
The Seneca Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FG. FG holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FG initiated the ILP relicensing process by filing its notice of intent to relicense and related documents in the license docket. | ||
Section 15 of the FPA contemplates that third parties may file a "competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and related documents necessary for the Seneca Nation to submit a competing application. FG believes it is entitled to a statutory “incumbent preference” under Section 15 and that it ultimately should prevail in these proceedings. Nevertheless, the Seneca Nation's pleadings reflect the Nation's apparent intent to obtain the license for the facility, and to assume ownership and operation of the facility as contemplated by the statute. | ||
The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy's petition, including motions to dismiss FirstEnergy's petition. The “project boundary” issue is pending before FERC. | ||
On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On January 7, 2013, FirstEnergy and the Seneca Nation submitted their respective reports for the 2012 study season. On January 31 and February 1, 2013, respectively, the Seneca Nation and FirstEnergy each submitted their respective proposed study plans for the 2013 study season. On March 4, 2013, the Seneca Nation and other parties submitted comments regarding FirstEnergy's proposed study plans. In its comments, the Seneca Nation alleges that FirstEnergy does not hold the real estate rights necessary to operate a hydroelectric project in circumstances where there is flowage over the Seneca Nation's lands. On April 3, 2013, FirstEnergy filed its response to these and other assertions by the Seneca Nation and its allied parties. On May 3, 2013, FERC's Director of the Office of Energy Projects issued FERC Staff's study plan determinations for the 2013 study year. The Director determined that water level fluctuations in the lower reservoir due to hydroelectric project operations have no discernible effect on reservoir lands or environmental resources. This finding is expected to strengthen FirstEnergy's position that the project boundary should be defined to exclude the U.S. Army Corps of Engineers dam and reservoir facilities. FERC Staff's determinations also largely adopted FirstEnergy's position and arguments as to the proper scope of environmental studies for the 2013 study season. The study processes will extend through approximately November 2013. | ||
On July 3, 2013, FirstEnergy and the Seneca Nation each submitted "Preliminary License Proposals" in the relicensing dockets. These submissions are intended to be non-binding indications of types of project upgrades that may be proposed in the parties' respective final licensing applications, as well as an indication of the scope and direction of the parties' plans for the upcoming final licensing applications. On October 1, 2013, FERC staff provided comments on FirstEnergy's and the Seneca Nation's Preliminary Licensing Proposals, including identifying deficiencies for the applicants to address in their applications. FirstEnergy and the Seneca Nation each are required to submit their application for the project license by December 2, 2013. | ||
Hydroelectric Asset Sale | ||
On September 4, 2013, certain of FirstEnergy’s subsidiaries submitted filings with FERC for authorization to sell eleven hydroelectric power plant projects to subsidiaries of Harbor Hydro Holdings, LLC (Harbor Hydro), a subsidiary of LS Power Equity Partners II, LP (LS Power) for approximately $400 million. The eleven hydroelectric projects are: the Seneca Pumped Storage Project, Allegheny Lock & Dam No. 5, Allegheny Lock & Dam No. 6, the Lake Lynn Project, the Millville Hydro Project, the Dam No. 4 Project, the Dam No. 5 Project, and four additional projects located in Shenandoah, Front Royal and Luray, Virginia. The eleven projects have a combined generating capacity of approximately 527 MW. Resolution of the potential competing hydro license application of the Seneca Nation for the Seneca Pumped Storage Project and other claims and matters is a condition to closing of the proposed asset sale. FirstEnergy’s submittals for regulatory authorization include a request for authorization to transfer the hydroelectric licenses under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the hydroelectric projects under Part II of the FPA. On September 25, 2013, the Seneca Nation submitted a pleading in the Part II regulatory proceeding wherein the Seneca Nation reiterated the real estate and other claims that the Seneca Nation has advanced in the Seneca Pumped Storage Project relicensing proceeding. On October 18, 2013, the Seneca Nation reiterated its real estate claims in comments on the Part I application to transfer the license for the Seneca Pumped Storage Project. However, the Seneca Nation noted in both sets of comments that it does not oppose the proposed sale or license transfer “at this time.” On November 1, 2013, FERC issued an order granting the FPA Part II authorization to transfer the hydro assets (the license transfer application remains pending before FERC). Additional filings have been submitted to FERC for the purpose of implementing the transaction once regulatory approval is obtained. The VSCC also must approve the sale for the assets that are located in Virginia, and the application for such approval was submitted on September 19, 2013. Once the regulatory authorizations are granted and the other closing conditions are satisfied, FirstEnergy expects to close this asset sale transaction in the fourth quarter of 2013. See Note 16, Discontinued Operations and Assets Held for Sale for additional information regarding the potential asset sales. | ||
MISO Capacity Portability | ||
On June 11, 2012, FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO and the MISO stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. FirstEnergy submitted comments and reply comments in August 2012. In the fall of 2012, FirstEnergy participated in certain stakeholder meetings to review various proposals advanced by MISO. Although none of MISO's proposals attracted significant stakeholder support, on January 3, 2013, MISO filed a pleading with FERC that renewed many of the arguments advanced in prior MISO filings and asked FERC to take expedited action to address MISO's allegations. FirstEnergy and other parties subsequently submitted filings arguing that MISO's concerns largely are without foundation and suggesting that FERC order that the remaining concerns be addressed in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement. On April 2, 2013, FERC issued an order directing MISO and PJM to make presentations to FERC regarding ongoing regional efforts to address whether barriers to transfer capability exist between the MISO and PJM regions and the actions the FERC should take to address any such barriers. The RTOs presented their respective positions to FERC on June 20, 2013 and provided additional information regarding their stakeholder prioritization survey, in response to a FERC request on June 27, 2013. On September 26, 2013, the RTOs jointly submitted an informational filing providing a description of and schedule for their Joint and Common Market initiatives. FERC has not acted on the presentations, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including a negative impact on the prices at which those auctions would clear. | ||
MOPR Reform | ||
On December 7, 2012, PJM filed amendments to its tariff to revise the MOPR used in the RPM. PJM revised the MOPR to add two broad, categorical exemptions, eliminate an existing exemption, and to limit the applicability of the MOPR to certain capacity resources. The filing also included related and conforming changes to the RPM posting requirements and to those provisions describing the role of the Independent Market Monitor for the PJM Region. On May 2, 2013, FERC issued an order in large part accepting PJM's proposed reform of the MOPR, including the proposed exemptions and applicability but also requiring PJM to commit to future review and, if necessary, additional revisions to the MOPR to accommodate changing market conditions. On June 3, 2013, FirstEnergy submitted a request for rehearing of FERC's May 2, 2013 order. In its rehearing request, FirstEnergy referenced the results of the May 2013 PJM RPM capacity auction, and the data that is available in the public domain about the reasons for the unexpectedly low "rest-of-RTO" clearing price of $59 per MW-day, as supporting its contention that the MOPR reform depressed prices as predicted in FirstEnergy's December 28, 2012 and January 25, 2013 comments. FirstEnergy's request for rehearing is pending before FERC. | ||
Synchronous Condensers | ||
On December 20, 2012, FERC approved the transfer by FG to ATSI of certain deactivated generation assets associated with Eastlake Units 1 through 5 and Lakeshore Unit 18 to facilitate their conversion to synchronous condensers to provide voltage support on the ATSI transmission system. The transfer price of the assets was approximately $21.5 million and the estimated conversion cost was approximately $60 million. The transfer of Eastlake Units 4 and 5 was completed on January 31, 2013 and ATSI completed the conversion of Eastlake Unit 5 in July 2013 and is expected to complete Eastlake Unit 4 by June 1, 2014. The transfer of each of the remaining units and conversion to synchronous condensers will occur when the use of the unit for RMR purposes is no longer required. On January 22, 2013, ATSI requested clarification or, in the alternative, rehearing with respect to a statement in the FERC order authorizing the transfer that ATSI's current formula rate does not include the accounts and components necessary to allow for recovery of the costs associated with acquisition of the transferred assets and that ATSI must make a filing under Section 205 of the FPA in order to recover those costs. ATSI requested clarification from FERC noting its formula rate currently includes the necessary accounts and components to allow for such recovery and that a Section 205 filing is not required. On August 5, 2013, FERC clarified that the issue of whether the cost of the transferred facilities and any conversion costs could be included in ATSI’s formula rates is more appropriately addressed during ATSI’s yearly formula rate update process. Based on this clarification by FERC, FE and FES recognized a pre-tax gain of approximately $17 million in the third quarter of 2013 representing the sales price to ATSI over the net book value. | ||
FTR Underfunding Complaint | ||
In PJM, FTRs are a mechanism to hedge congestion and they operate as a financial replacement for physical firm transmission service. FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market. FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM tariff, the funds that are set aside to pay FTRs can be diverted to other uses, resulting in “underfunding” of FTR payments. Since June of 2010, FES and AE Supply have lost more than $63.5 million in revenues that they otherwise would have received as FTR holders to hedge congestion costs. FES and AE Supply expect to continue to experience significant underfunding. | ||
On December 28, 2011, FES and AE Supply filed a complaint with FERC for the purpose of modifying certain provisions in the PJM tariff to eliminate FTR underfunding. On March 2, 2012, FERC issued an order dismissing the complaint. In its order, FERC ruled that it was not appropriate to initiate action at that time because of the unknown root causes of FTR underfunding. FERC directed PJM to convene stakeholder proceedings for the purpose of determining the root causes of the FTR underfunding. FERC went on to note that its dismissal of the complaint was without prejudice to FES and AE Supply or any other affected entity filing a complaint if the stakeholder proceedings proved unavailing. FES and AE Supply sought rehearing of FERC's order and, on July 19, 2012, FERC denied rehearing. In April, 2012, PJM issued a report on FTR underfunding. However, the PJM stakeholder process proved unavailing as the stakeholders were not willing to change the tariff to eliminate FTR underfunding. Accordingly, on February 15, 2013, FES and AE Supply refiled their complaint with FERC for the purpose of changing the PJM tariff to eliminate FTR underfunding. Various parties filed responsive pleadings, including PJM. On June 5, 2013, FERC issued its order denying the new complaint. On July 5, 2013, FirstEnergy filed a request for rehearing of FERC's order. FirstEnergy's request for rehearing is pending before FERC. |
Commitments_Guarantees_and_Con
Commitments, Guarantees and Contingencies | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES | ' | ||||||||||||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||||||||||
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 September 30, 2013, outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting of parental guarantees ($1,403 million), subsidiaries' guarantees ($2,232 million) and other guarantees ($747 million). | |||||||||||||||||
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 September 30, 2013, FES has posted collateral of $150 million and AE supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of $16 million. | |||||||||||||||||
These credit-risk-related contingent features 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 could be required. | |||||||||||||||||
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries. The following table discloses the additional credit contingent contractual obligations as of September 30, 2013: | |||||||||||||||||
Collateral Provisions | FES | AE Supply | Utilities | Total | |||||||||||||
(In millions) | |||||||||||||||||
Split Rating (One rating agency's rating below investment grade) | $ | 440 | $ | 6 | $ | 55 | $ | 501 | |||||||||
BB+/Ba1 Credit Ratings | $ | 484 | $ | 6 | $ | 55 | $ | 545 | |||||||||
Full impact of credit contingent contractual obligations | $ | 755 | $ | 58 | $ | 90 | $ | 903 | |||||||||
Excluded from the preceding chart is the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Services Segment. As of September 30, 2013, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post $77 million and $2 million, respectively. | |||||||||||||||||
OTHER COMMITMENTS AND CONTINGENCIES | |||||||||||||||||
FirstEnergy is a guarantor under a syndicated three-year senior secured term loan facility due October 18, 2015, under which Global Holding borrowed $350 million. Proceeds from the loan were used to repay Signal Peak's and Global Rail's maturing $350 million syndicated two-year senior secured term loan facility. 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, have also provided their joint and several guaranties of the obligations of Global Holding under the new facility. | |||||||||||||||||
In connection with the new 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 new facility as collateral. | |||||||||||||||||
FirstEnergy, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed to use their best efforts to refinance the new facility no later than July 20, 2015, which reflects the terms of an amendment dated August 14, 2013, on a non-recourse basis so that FirstEnergy's guaranty can be terminated and/or released. If that refinancing does not occur, FirstEnergy may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the new facility in full. In lieu of providing such funding, the co-owners, at FirstEnergy's option, may provide their several guaranties of Global Holding's obligations under the facility. FirstEnergy receives a fee for providing its guaranty, payable semiannually, which accrued at a rate of 4% through December 31, 2012, and accrues at a rate of 5% from January 1, 2013 through October 18, 2015, which amends the rate in the prior agreement, in each case based upon the average daily outstanding aggregate commitments under the facility for such semiannual period. | |||||||||||||||||
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. | |||||||||||||||||
CAA Compliance | |||||||||||||||||
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx 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. | |||||||||||||||||
In July 2008, three complaints representing multiple plaintiffs were filed against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf of twenty-one individuals and the other is a class action complaint seeking certification as a class with the eight named plaintiffs as the class representatives. FG believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss. | |||||||||||||||||
In January 2009, the EPA issued an NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. ME, as a former owner of the facilities, is unable to predict the outcome of this matter or estimate the possible loss or range of loss. | |||||||||||||||||
In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant during 1991 to 1994 without pre-construction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the states of New Jersey and New York intervened and filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. DOJ and the Commonwealth of Pennsylvania and the states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth of Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals which affirmed the dismissal on August 21, 2013. PN believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International. PN is unable to predict the outcome of this matter or estimate the loss or possible range of loss. | |||||||||||||||||
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations, at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically, opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. FG intends to comply with the CAA and Ohio regulations, but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss. | |||||||||||||||||
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. 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. On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued additional 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. AE intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss. | |||||||||||||||||
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Allegheny Utilities in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. The parties are awaiting a decision from the District Court, but there is no deadline for that decision. FirstEnergy is unable to predict the outcome or estimate the possible loss or range of loss. | |||||||||||||||||
National Ambient Air Quality Standards | |||||||||||||||||
The EPA's CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court's decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 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 SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit and was ultimately vacated by the Court on August 21, 2012. The Court has ordered EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR. On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the District of Columbia Circuit. On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR. Oral argument is scheduled for December 10, 2013. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result. | |||||||||||||||||
Hazardous Air Pollutant Emissions | |||||||||||||||||
On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants stations. On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Mansfield stations. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. Oral argument is scheduled for December 10, 2013. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS. Depending on the outcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS is currently estimated to be approximately $465 million. | |||||||||||||||||
As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated. FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated. As of October 9, 2013, the Hatfield's Ferry and Mitchell stations were also deactivated. | |||||||||||||||||
FirstEnergy and FES have various long-term coal transportation agreements, some of which run through 2025 and certain of which are related to the plants described above. We have asserted force majeure defenses for delivery shortfalls under certain agreements, and we are in discussion with the applicable counterparties. Under one agreement, we have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately $45 million, and agreed to pay liquidated damages for delivery shortfalls, if any, for 2013 and 2014. As to another agreement, based on the state of current negotiations, penalties of approximately $25 million for delivery shortfalls for 2012 were recorded in the third quarter of 2013, and we could incur additional penalties for any delivery shortfalls in 2013 and 2014. If we fail to reach a resolution with applicable counterparties for the unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to our belief, the force majeure provisions or other defenses do not excuse delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted. | |||||||||||||||||
Climate Change | |||||||||||||||||
There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs to control emissions of certain GHGs. In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act. In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including EPA carbon pollution standards for both new and existing power plants by 17% by 2020 (from 2005 levels), (2) prepare the United States for the impacts of climate change, and (3) lead international efforts to combat global climate change and prepare for its impacts. | |||||||||||||||||
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of GHG emissions commencing in 2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA's finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when NSR pre-construction permits would be required including an emissions applicability threshold of 75,000 tons per year of CO2 equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than 25 MW, which were ultimately withdrawn. On June 25, 2013, a Presidential memorandum directed EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013, and propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units. On September 20, 2013, EPA proposed a new source performance standard of 1,000 lbs. CO2/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO2/MWH for fossil fuel fired units which would require partial carbon capture and storage. On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" Depending on the outcome of these proceedings and how any final rules are ultimately implemented, future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result. | |||||||||||||||||
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching $30 billion over three years with a goal of increasing to $100 billion by 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification. In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world. In December 2011 the U.N. Climate Change Conference in Durban, South Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020. In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020. The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective. | |||||||||||||||||
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 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-CO2 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 operate have water quality standards applicable to FirstEnergy's operations. | |||||||||||||||||
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a 12% annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. The period for finalizing the Section 316(b) regulation has been extended to November 20, 2013 under a Settlement Agreement between EPA and certain NGOs. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures. | |||||||||||||||||
On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423). The EPA proposed eight treatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency. The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements. The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a 5-year cycle from 2017 to 2022. Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures. | |||||||||||||||||
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 in excess of $150 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 these appeals or estimate the possible loss or range of loss. | |||||||||||||||||
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years. However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013. | |||||||||||||||||
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss. | |||||||||||||||||
Regulation of Waste Disposal | |||||||||||||||||
Federal and state hazardous waste regulations have been promulgated as a result of the RCRA of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel 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 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. On April 19, 2013, the EPA stated it would "align" its proposed coal combustion residuals regulations with revised waste water discharge effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) that were proposed on that date. On July 25, 2013, the House of Representatives passed H.R. 221 that would require CCRs to be regulated under Subtitle D of RCRA, as non-hazardous. Depending on the content of the EPA's final effluent limitations rule and the specifics of any "alignment", the future costs of compliance with such standards may require material capital expenditures. | |||||||||||||||||
On July 27, 2012, the PA DEP filed a complaint against FG in the U.S. District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FG to resolve those claims. On December 14, 2012, a modified Consent Decree that addresses public comments received by PA DEP was entered by the court, requiring FG to conduct monitoring studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The modified Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. On February 1, 2013, FG submitted a Feasibility Study analyzing various technical issues relevant to the closure of LBR. On March 28, 2013, FG submitted to the PA DEP a Closure Plan Major Permit Modification Application which provides for placing a final cap over LBR that would require 15 years to fully implement following the closure of LBR. The estimated cost for the proposed closure plan is $234 million, including environmental and other post closure costs. On October 3, 2013, the PA DEP issued a technical deficiency letter citing four main deficiencies with the Closure Plan: (1) seeking to accelerate the 15 year period proposed by FG for closure activities to complete closure in 9 years by commencing closure activities prior to 2017 as proposed by FG; (2) seeking to extend bond closure and post closure activities beyond the 45 years proposed by FG; (3) seeking active dewatering of the CCBs in areas where there are seeps impacted by the Impoundment; and (4) seeking an abatement plan for groundwater impacted by arsenic. The Bruce Mansfield Plant is pursuing several options for its CCBs following December 31, 2016, and on January 23, 2013, announced a plan for beneficial use of its CCBs for mine reclamation in LaBelle, Pennsylvania. In June 2013, a complaint filed in the U.S. District Court for the Western District of Pennsylvania, alleges the LaBelle site is in violation of RCRA and state laws. On December 20, 2012, the Environmental Integrity Project and others served FG with a citizen suit notice alleging CWA and PA Clean Streams Law Violations at LBR. | |||||||||||||||||
On October 10, 2013, a complaint was filed on behalf of approximately 50 individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment. The complaint states claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment. FE, FG and FES believe the claims are without merit and intend to vigorously defend themselves against the allegations made in this complaint, but, at this time, are unable to predict the outcome of the above matter or estimate the possible loss or range of loss. | |||||||||||||||||
FirstEnergy's future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition. | |||||||||||||||||
Certain of FirstEnergy's utilities 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 Sheet as of September 30, 2013 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 $124 million have been accrued through September 30, 2013. Included in the total are accrued liabilities of approximately $82 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 possible losses or range of losses 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 September 30, 2013, FirstEnergy had approximately $2.2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranty, as appropriate. The values of FirstEnergy's NDT 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 NDT. FE maintains a $125 million parental guaranty relating to a potential shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry. FE also maintains an $11 million parental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities. | |||||||||||||||||
On October 4, 2013, during a refueling outage for Beaver Valley Unit 1, FENOC conducted a planned visual examination of the interior containment liner and coatings. The containment design for Beaver Valley includes an interior steel liner that is surrounded by reinforced concrete. A penetration through the containment steel liner plate of approximately 0.4 inches by 0.28 inches was discovered. A detailed investigation was initiated, including laboratory analysis that has indicated that the degraded area was initiated by foreign material inadvertently left in the concrete during construction. An assessment has been performed which concluded that any postulated leakage through the affected area was within overall allowable limits for the containment building. The structural integrity of the containment building is not affected. Repair of the containment liner has been completed and is not expected to impact the restart of the Unit. | |||||||||||||||||
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. An NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. On July 9, 2012, the petitioners' proposed a contention on the environmental impacts of spent fuel storage in the Davis-Besse license renewal proceeding. In an order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the challenges to the NRC Waste Confidence Decision and Temporary Storage Rule and all pending contentions on this topic should be held in abeyance. The ASLB has suspended further consideration of the petitioners' proposed contention on the environmental impacts of spent fuel storage at Davis-Besse. The NRC Staff issued Waste Confidence Draft Generic Environmental Impact Statement and published a proposed rule on this subject in September of 2013. | |||||||||||||||||
In May 2013, four petitioners requested a hearing on an NRC LAR submitted by FENOC to amend the Technical Specifications for the Davis-Besse plant to support plant operations following replacement of the steam generators, which is scheduled to be completed in April 2014. The petitioners also challenged FENOC's ability to replace the steam generators at the Davis-Besse plant under the NRC regulations, 10 CFR §50.59 without submitting a formal LAR. By an order dated August 12, 2013, the NRC denied the request for a hearing. | |||||||||||||||||
As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station FENOC identified changes to the laminar cracking condition discovered in 2011. FENOC expanded its sample size to include all of the existing core bores in the shield building. These inspections are now complete. FENOC identified additional subsurface cracking that determined to be pre-existing, but not previously identified, due to improved inspection technology. In addition, these inspections revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions. | |||||||||||||||||
By a letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff conducted several supplemental inspections, including inspections using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues were understood, the extent of condition was identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence. On August 12, 2013, the NRC issued an inspection report for the final 95002 Supplemental Inspection for Perry and returned Perry to the Licensee Response Column (Column 1) of the NRC's ROP Action Matrix. | |||||||||||||||||
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities. | |||||||||||||||||
ICG Litigation | |||||||||||||||||
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants' past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, the defendants posted bond and filed a Notice of Appeal with the Superior Court. On August 13, 2012, the Superior Court affirmed the $14 million past damages award but vacated the $90 million future damages award. While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court. The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court. On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012. AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012. On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of $15.5 million (including interest) was recognized. The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase. | |||||||||||||||||
Other Legal Matters | |||||||||||||||||
In 2010, a lawsuit was filed in Allegheny County Court of Common Pleas by Michael Goretzka, for wrongful death and negligence after his wife was fatally electrocuted when she contacted a downed power line. The trial resulted in a verdict against WP and the parties settled this matter. WP's portion of the settlement was covered by insurance subject to the remainder of its deductible. On May 30, 2012, the PPUC's Bureau of Investigation and Enforcement (I&E) filed a Formal Complaint at the PPUC regarding this matter. On February 13, 2013, WP and I&E filed a Joint Petition for Full Settlement that includes, among other things, WP's agreement to conduct an infrared inspection of its primary distribution system, modify certain training programs, and pay an $86,000 civil penalty, which settlement is subject to PPUC approval. On August 29, 2013, the PPUC entered an Order granting the Goretzka family limited party status for the sole purpose of submitting comments to the settlement and issuing the settlement for comment by the parties. On September 16, 2013, the Goretzka family filed Limited Objections to the settlement. Reply comments were filed by WP on September 30, 2013. | |||||||||||||||||
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, Regulatory Matters of the Combined Notes to Consolidated Financial Statements. | |||||||||||||||||
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows. |
Supplemental_Guarantor_Informa
Supplemental Guarantor Information | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
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 under GAAP for FES and FirstEnergy and as a financing lease for FG. | |||||||||||||||||||||
The Consolidating Statements of Income and Comprehensive Income for the three months and nine months ended September 30, 2013 and 2012, Consolidating Balance Sheets as of September 30, 2013 and December 31, 2012, and Consolidating Statements of Cash Flows for the nine months ended September 30, 2013 and 2012, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG are, therefore, reflected in FES’ 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 AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 1,654 | $ | 528 | $ | 440 | $ | (943 | ) | $ | 1,679 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 249 | 55 | — | 304 | ||||||||||||||||
Purchased power from affiliates | 1,009 | — | 65 | (942 | ) | 132 | |||||||||||||||
Purchased power from non-affiliates | 720 | 4 | — | — | 724 | ||||||||||||||||
Other operating expenses | 147 | 65 | 114 | 13 | 339 | ||||||||||||||||
Provision for depreciation | 1 | 33 | 46 | — | 80 | ||||||||||||||||
General taxes | 21 | 9 | 5 | — | 35 | ||||||||||||||||
Total operating expenses | 1,898 | 360 | 285 | (929 | ) | 1,614 | |||||||||||||||
OPERATING INCOME (LOSS) | (244 | ) | 168 | 155 | (14 | ) | 65 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Loss on debt redemptions | — | — | — | — | — | ||||||||||||||||
Investment income (loss) | 2 | — | (1 | ) | (4 | ) | (3 | ) | |||||||||||||
Miscellaneous income, including net income from equity investees | 180 | 19 | — | (178 | ) | 21 | |||||||||||||||
Interest expense — affiliates | (3 | ) | (2 | ) | (1 | ) | 5 | (1 | ) | ||||||||||||
Interest expense — other | (13 | ) | (24 | ) | (13 | ) | 15 | (35 | ) | ||||||||||||
Capitalized interest | — | 1 | 8 | — | 9 | ||||||||||||||||
Total other income (expense) | 166 | (6 | ) | (7 | ) | (162 | ) | (9 | ) | ||||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (78 | ) | 162 | 148 | (176 | ) | 56 | ||||||||||||||
INCOME TAXES (BENEFITS) | (118 | ) | 111 | 28 | 2 | 23 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 40 | 51 | 120 | (178 | ) | 33 | |||||||||||||||
Discontinued operations (net of income taxes of $5) | — | 7 | — | — | 7 | ||||||||||||||||
NET INCOME | $ | 40 | $ | 58 | $ | 120 | $ | (178 | ) | $ | 40 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 40 | $ | 58 | $ | 120 | $ | (178 | ) | $ | 40 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (5 | ) | (5 | ) | — | 5 | (5 | ) | |||||||||||||
Amortized gain on derivative hedges | (1 | ) | — | — | — | (1 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 5 | — | 5 | (5 | ) | 5 | |||||||||||||||
Other comprehensive income (loss) | (1 | ) | (5 | ) | 5 | — | (1 | ) | |||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (1 | ) | (2 | ) | 3 | (1 | ) | (1 | ) | ||||||||||||
Other comprehensive income (loss), net of tax | — | (3 | ) | 2 | 1 | — | |||||||||||||||
COMPREHENSIVE INCOME | $ | 40 | $ | 55 | $ | 122 | $ | (177 | ) | $ | 40 | ||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 4,575 | $ | 1,612 | $ | 1,337 | $ | (2,869 | ) | $ | 4,655 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 782 | 154 | — | 936 | ||||||||||||||||
Purchased power from affiliates | 3,072 | — | 197 | (2,868 | ) | 401 | |||||||||||||||
Purchased power from non-affiliates | 1,749 | 6 | — | — | 1,755 | ||||||||||||||||
Other operating expenses | 484 | 208 | 376 | 37 | 1,105 | ||||||||||||||||
Provision for depreciation | 4 | 96 | 134 | (3 | ) | 231 | |||||||||||||||
General taxes | 60 | 28 | 18 | — | 106 | ||||||||||||||||
Total operating expenses | 5,369 | 1,120 | 879 | (2,834 | ) | 4,534 | |||||||||||||||
OPERATING INCOME (LOSS) | (794 | ) | 492 | 458 | (35 | ) | 121 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Loss on debt redemptions | (103 | ) | — | — | — | (103 | ) | ||||||||||||||
Investment income | 4 | — | 3 | (11 | ) | (4 | ) | ||||||||||||||
Miscellaneous income, including net income from equity investees | 543 | 23 | — | (537 | ) | 29 | |||||||||||||||
Interest expense — affiliates | (10 | ) | (4 | ) | (5 | ) | 12 | (7 | ) | ||||||||||||
Interest expense — other | (50 | ) | (79 | ) | (42 | ) | 45 | (126 | ) | ||||||||||||
Capitalized interest | 1 | 1 | 26 | — | 28 | ||||||||||||||||
Total other income (expense) | 385 | (59 | ) | (18 | ) | (491 | ) | (183 | ) | ||||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (409 | ) | 433 | 440 | (526 | ) | (62 | ) | |||||||||||||
INCOME TAXES (BENEFITS) | (380 | ) | 215 | 138 | 8 | (19 | ) | ||||||||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (29 | ) | 218 | 302 | (534 | ) | (43 | ) | |||||||||||||
Discontinued operations (net of income taxes of $8) | — | 14 | — | — | 14 | ||||||||||||||||
NET INCOME (LOSS) | $ | (29 | ) | $ | 232 | $ | 302 | $ | (534 | ) | $ | (29 | ) | ||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |||||||||||||||||||||
NET INCOME (LOSS) | $ | (29 | ) | $ | 232 | $ | 302 | $ | (534 | ) | $ | (29 | ) | ||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (16 | ) | (15 | ) | — | 15 | (16 | ) | |||||||||||||
Amortized gain on derivative hedges | (3 | ) | — | — | — | (3 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 2 | — | 2 | (2 | ) | 2 | |||||||||||||||
Other comprehensive income (loss) | (17 | ) | (15 | ) | 2 | 13 | (17 | ) | |||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (7 | ) | (6 | ) | 1 | 5 | (7 | ) | |||||||||||||
Other comprehensive income (loss), net of tax | (10 | ) | (9 | ) | 1 | 8 | (10 | ) | |||||||||||||
COMPREHENSIVE INCOME (LOSS) | $ | (39 | ) | $ | 223 | $ | 303 | $ | (526 | ) | $ | (39 | ) | ||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 1,523 | $ | 610 | $ | 395 | $ | (978 | ) | $ | 1,550 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 248 | 55 | — | 303 | ||||||||||||||||
Purchased power from affiliates | 1,042 | — | 67 | (978 | ) | 131 | |||||||||||||||
Purchased power from non-affiliates | 499 | 3 | — | — | 502 | ||||||||||||||||
Other operating expenses | 130 | 78 | 122 | 12 | 342 | ||||||||||||||||
Provision for depreciation | 1 | 29 | 41 | (1 | ) | 70 | |||||||||||||||
General taxes | 20 | 10 | 5 | — | 35 | ||||||||||||||||
Total operating expenses | 1,692 | 368 | 290 | (967 | ) | 1,383 | |||||||||||||||
OPERATING INCOME (LOSS) | (169 | ) | 242 | 105 | (11 | ) | 167 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Investment income | 1 | 5 | 37 | (5 | ) | 38 | |||||||||||||||
Miscellaneous income, including net income from equity investees | 317 | — | — | (316 | ) | 1 | |||||||||||||||
Interest expense — affiliates | (5 | ) | (2 | ) | (1 | ) | 5 | (3 | ) | ||||||||||||
Interest expense — other | (25 | ) | (27 | ) | (15 | ) | 16 | (51 | ) | ||||||||||||
Capitalized interest | — | 1 | 8 | — | 9 | ||||||||||||||||
Total other income (expense) | 288 | (23 | ) | 29 | (300 | ) | (6 | ) | |||||||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 119 | 219 | 134 | (311 | ) | 161 | |||||||||||||||
INCOME TAXES (BENEFITS) | 18 | (14 | ) | 59 | 2 | 65 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 101 | 233 | 75 | (313 | ) | 96 | |||||||||||||||
Discontinued operations (net of income taxes of $3) | — | 5 | — | — | 5 | ||||||||||||||||
NET INCOME | $ | 101 | $ | 238 | $ | 75 | $ | (313 | ) | $ | 101 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 101 | $ | 238 | $ | 75 | $ | (313 | ) | $ | 101 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (5 | ) | (4 | ) | — | 4 | (5 | ) | |||||||||||||
Amortized gain on derivative hedges | (2 | ) | — | — | — | (2 | ) | ||||||||||||||
Change in unrealized gain on available for sale securities | (2 | ) | — | (1 | ) | 1 | (2 | ) | |||||||||||||
Other comprehensive loss | (9 | ) | (4 | ) | (1 | ) | 5 | (9 | ) | ||||||||||||
Income tax benefits on other comprehensive loss | (3 | ) | (2 | ) | — | 2 | (3 | ) | |||||||||||||
Other comprehensive loss, net of tax | (6 | ) | (2 | ) | (1 | ) | 3 | (6 | ) | ||||||||||||
COMPREHENSIVE INCOME | $ | 95 | $ | 236 | $ | 74 | $ | (310 | ) | $ | 95 | ||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 4,443 | $ | 1,777 | $ | 1,262 | $ | (2,971 | ) | $ | 4,511 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 824 | 154 | — | 978 | ||||||||||||||||
Purchased power from affiliates | 3,163 | — | 189 | (2,971 | ) | 381 | |||||||||||||||
Purchased power from non-affiliates | 1,420 | 5 | — | — | 1,425 | ||||||||||||||||
Other operating expenses | 313 | 268 | 410 | 37 | 1,028 | ||||||||||||||||
Provision for depreciation | 3 | 87 | 114 | (4 | ) | 200 | |||||||||||||||
General taxes | 60 | 28 | 16 | — | 104 | ||||||||||||||||
Total operating expenses | 4,959 | 1,212 | 883 | (2,938 | ) | 4,116 | |||||||||||||||
OPERATING INCOME (LOSS) | (516 | ) | 565 | 379 | (33 | ) | 395 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Investment income | 2 | 14 | 49 | (15 | ) | 50 | |||||||||||||||
Miscellaneous income, including net income from equity investees | 854 | 19 | — | (848 | ) | 25 | |||||||||||||||
Interest expense — affiliates | (14 | ) | (5 | ) | (3 | ) | 15 | (7 | ) | ||||||||||||
Interest expense — other | (72 | ) | (79 | ) | (36 | ) | 47 | (140 | ) | ||||||||||||
Capitalized interest | — | 3 | 24 | — | 27 | ||||||||||||||||
Total other income (expense) | 770 | (48 | ) | 34 | (801 | ) | (45 | ) | |||||||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 254 | 517 | 413 | (834 | ) | 350 | |||||||||||||||
INCOME TAXES (BENEFITS) | 32 | (25 | ) | 124 | 8 | 139 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 222 | 542 | 289 | (842 | ) | 211 | |||||||||||||||
Discontinued operations (net of income taxes of $6) | — | 11 | — | — | 11 | ||||||||||||||||
NET INCOME | $ | 222 | $ | 553 | $ | 289 | $ | (842 | ) | $ | 222 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 222 | $ | 553 | $ | 289 | $ | (842 | ) | $ | 222 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (2 | ) | (1 | ) | — | 1 | (2 | ) | |||||||||||||
Amortized gain on derivative hedges | (6 | ) | — | — | — | (6 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 11 | — | 12 | (12 | ) | 11 | |||||||||||||||
Other comprehensive income (loss) | 3 | (1 | ) | 12 | (11 | ) | 3 | ||||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | 1 | (1 | ) | 5 | (4 | ) | 1 | ||||||||||||||
Other comprehensive income, net of tax | 2 | — | 7 | (7 | ) | 2 | |||||||||||||||
COMPREHENSIVE INCOME | $ | 224 | $ | 553 | $ | 296 | $ | (849 | ) | $ | 224 | ||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
As of September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
CURRENT ASSETS: | |||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||
Receivables- | |||||||||||||||||||||
Customers | 524 | — | — | — | 524 | ||||||||||||||||
Affiliated companies | 420 | 445 | 285 | (631 | ) | 519 | |||||||||||||||
Other | 76 | 22 | 25 | — | 123 | ||||||||||||||||
Notes receivable from affiliated companies | 337 | 163 | 764 | (1,010 | ) | 254 | |||||||||||||||
Materials and supplies | 64 | 161 | 214 | — | 439 | ||||||||||||||||
Derivatives | 139 | — | — | — | 139 | ||||||||||||||||
Prepayments and other | 61 | 37 | 6 | 1 | 105 | ||||||||||||||||
1,621 | 830 | 1,294 | (1,640 | ) | 2,105 | ||||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||||||||||||||||
In service | 104 | 6,068 | 6,719 | (383 | ) | 12,508 | |||||||||||||||
Less — Accumulated provision for depreciation | 26 | 1,928 | 2,882 | (187 | ) | 4,649 | |||||||||||||||
78 | 4,140 | 3,837 | (196 | ) | 7,859 | ||||||||||||||||
Construction work in progress | 21 | 115 | 980 | — | 1,116 | ||||||||||||||||
99 | 4,255 | 4,817 | (196 | ) | 8,975 | ||||||||||||||||
INVESTMENTS: | |||||||||||||||||||||
Nuclear plant decommissioning trusts | — | — | 1,270 | — | 1,270 | ||||||||||||||||
Investment in affiliated companies | 5,503 | — | — | (5,503 | ) | — | |||||||||||||||
Other | 1 | 10 | — | — | 11 | ||||||||||||||||
5,504 | 10 | 1,270 | (5,503 | ) | 1,281 | ||||||||||||||||
ASSETS HELD FOR SALE (NOTE 16) | — | 121 | — | — | 121 | ||||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | |||||||||||||||||||||
Accumulated deferred income tax benefits | 16 | 169 | — | (185 | ) | — | |||||||||||||||
Customer intangibles | 99 | — | — | — | 99 | ||||||||||||||||
Goodwill | 23 | — | — | — | 23 | ||||||||||||||||
Property taxes | — | 14 | 22 | — | 36 | ||||||||||||||||
Unamortized sale and leaseback costs | — | — | — | 161 | 161 | ||||||||||||||||
Derivatives | 65 | — | — | — | 65 | ||||||||||||||||
Other | 174 | 242 | 14 | (162 | ) | 268 | |||||||||||||||
377 | 425 | 36 | (186 | ) | 652 | ||||||||||||||||
$ | 7,601 | $ | 5,641 | $ | 7,417 | $ | (7,525 | ) | $ | 13,134 | |||||||||||
LIABILITIES AND CAPITALIZATION | |||||||||||||||||||||
CURRENT LIABILITIES: | |||||||||||||||||||||
Currently payable long-term debt | $ | 1 | $ | 366 | $ | 514 | $ | (22 | ) | $ | 859 | ||||||||||
Short-term borrowings- | |||||||||||||||||||||
Affiliated companies | 696 | 314 | — | (1,010 | ) | — | |||||||||||||||
Other | — | 4 | — | — | 4 | ||||||||||||||||
Accounts payable- | |||||||||||||||||||||
Affiliated companies | 643 | 386 | 378 | (631 | ) | 776 | |||||||||||||||
Other | 88 | 125 | — | — | 213 | ||||||||||||||||
Accrued taxes | 7 | 17 | 37 | (19 | ) | 42 | |||||||||||||||
Derivatives | 103 | — | — | — | 103 | ||||||||||||||||
Other | 46 | 72 | 22 | 36 | 176 | ||||||||||||||||
1,584 | 1,284 | 951 | (1,646 | ) | 2,173 | ||||||||||||||||
CAPITALIZATION: | |||||||||||||||||||||
Total equity | 5,229 | 2,010 | 3,469 | (5,479 | ) | 5,229 | |||||||||||||||
Long-term debt and other long-term obligations | 712 | 1,873 | 789 | (1,196 | ) | 2,178 | |||||||||||||||
5,941 | 3,883 | 4,258 | (6,675 | ) | 7,407 | ||||||||||||||||
NONCURRENT LIABILITIES: | |||||||||||||||||||||
Deferred gain on sale and leaseback transaction | — | — | — | 866 | 866 | ||||||||||||||||
Accumulated deferred income taxes | — | — | 770 | (71 | ) | 699 | |||||||||||||||
Asset retirement obligations | — | 176 | 983 | — | 1,159 | ||||||||||||||||
Retirement benefits | 27 | 228 | — | — | 255 | ||||||||||||||||
Derivatives | 22 | — | — | — | 22 | ||||||||||||||||
Other | 27 | 70 | 455 | 1 | 553 | ||||||||||||||||
76 | 474 | 2,208 | 796 | 3,554 | |||||||||||||||||
$ | 7,601 | $ | 5,641 | $ | 7,417 | $ | (7,525 | ) | $ | 13,134 | |||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
As of December 31, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
CURRENT ASSETS: | |||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||||
Receivables- | |||||||||||||||||||||
Customers | 483 | — | — | — | 483 | ||||||||||||||||
Affiliated companies | 232 | 417 | 478 | (748 | ) | 379 | |||||||||||||||
Other | 56 | 19 | 16 | — | 91 | ||||||||||||||||
Notes receivable from affiliated companies | 366 | 7 | 607 | (704 | ) | 276 | |||||||||||||||
Materials and supplies | 66 | 231 | 208 | — | 505 | ||||||||||||||||
Derivatives | 158 | — | — | — | 158 | ||||||||||||||||
Prepayments and other | 38 | 39 | 10 | — | 87 | ||||||||||||||||
1,399 | 716 | 1,319 | (1,452 | ) | 1,982 | ||||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||||||||||||||||
In service | 91 | 5,899 | 6,391 | (384 | ) | 11,997 | |||||||||||||||
Less — Accumulated provision for depreciation | 32 | 1,915 | 2,646 | (185 | ) | 4,408 | |||||||||||||||
59 | 3,984 | 3,745 | (199 | ) | 7,589 | ||||||||||||||||
Construction work in progress | 34 | 230 | 877 | — | 1,141 | ||||||||||||||||
93 | 4,214 | 4,622 | (199 | ) | 8,730 | ||||||||||||||||
INVESTMENTS: | |||||||||||||||||||||
Nuclear plant decommissioning trusts | — | — | 1,283 | — | 1,283 | ||||||||||||||||
Investment in affiliated companies | 4,972 | — | — | (4,972 | ) | — | |||||||||||||||
Other | — | 12 | — | — | 12 | ||||||||||||||||
4,972 | 12 | 1,283 | (4,972 | ) | 1,295 | ||||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | |||||||||||||||||||||
Accumulated deferred income tax benefits | — | 313 | — | (313 | ) | — | |||||||||||||||
Customer intangibles | 110 | — | — | — | 110 | ||||||||||||||||
Goodwill | 24 | — | — | — | 24 | ||||||||||||||||
Property taxes | — | 14 | 22 | — | 36 | ||||||||||||||||
Unamortized sale and leaseback costs | — | — | — | 119 | 119 | ||||||||||||||||
Derivatives | 99 | — | — | — | 99 | ||||||||||||||||
Other | 160 | 194 | 5 | (106 | ) | 253 | |||||||||||||||
393 | 521 | 27 | (300 | ) | 641 | ||||||||||||||||
$ | 6,857 | $ | 5,463 | $ | 7,251 | $ | (6,923 | ) | $ | 12,648 | |||||||||||
LIABILITIES AND CAPITALIZATION | |||||||||||||||||||||
CURRENT LIABILITIES: | |||||||||||||||||||||
Currently payable long-term debt | $ | 1 | $ | 586 | $ | 537 | $ | (22 | ) | $ | 1,102 | ||||||||||
Short-term borrowings- | |||||||||||||||||||||
Affiliated companies | 358 | 346 | — | (704 | ) | — | |||||||||||||||
Other | — | 4 | — | — | 4 | ||||||||||||||||
Accounts payable- | |||||||||||||||||||||
Affiliated companies | 748 | 143 | 583 | (748 | ) | 726 | |||||||||||||||
Other | 63 | 96 | — | — | 159 | ||||||||||||||||
Accrued taxes | 126 | 25 | 20 | — | 171 | ||||||||||||||||
Derivatives | 124 | — | — | — | 124 | ||||||||||||||||
Other | 71 | 148 | 15 | 46 | 280 | ||||||||||||||||
1,491 | 1,348 | 1,155 | (1,428 | ) | 2,566 | ||||||||||||||||
CAPITALIZATION: | |||||||||||||||||||||
Total equity | 3,763 | 1,787 | 3,165 | (4,952 | ) | 3,763 | |||||||||||||||
Long-term debt and other long-term obligations | 1,482 | 2,009 | 834 | (1,207 | ) | 3,118 | |||||||||||||||
5,245 | 3,796 | 3,999 | (6,159 | ) | 6,881 | ||||||||||||||||
NONCURRENT LIABILITIES: | |||||||||||||||||||||
Deferred gain on sale and leaseback transaction | — | — | — | 892 | 892 | ||||||||||||||||
Accumulated deferred income taxes | 28 | — | 714 | (227 | ) | 515 | |||||||||||||||
Asset retirement obligations | — | 29 | 936 | — | 965 | ||||||||||||||||
Retirement benefits | 26 | 215 | — | — | 241 | ||||||||||||||||
Derivatives | 37 | — | — | — | 37 | ||||||||||||||||
Other | 30 | 75 | 447 | (1 | ) | 551 | |||||||||||||||
121 | 319 | 2,097 | 664 | 3,201 | |||||||||||||||||
$ | 6,857 | $ | 5,463 | $ | 7,251 | $ | (6,923 | ) | $ | 12,648 | |||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (1,018 | ) | $ | 712 | $ | 705 | $ | (10 | ) | $ | 389 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||||
New Financing- | |||||||||||||||||||||
Short-term borrowings, net | 338 | — | — | (338 | ) | — | |||||||||||||||
Equity contribution from parent | 1,500 | — | — | — | 1,500 | ||||||||||||||||
Redemptions and Repayments- | |||||||||||||||||||||
Long-term debt | (769 | ) | (352 | ) | (68 | ) | 10 | (1,179 | ) | ||||||||||||
Short-term borrowings, net | — | (32 | ) | — | 32 | — | |||||||||||||||
Tender premiums | (67 | ) | — | — | — | (67 | ) | ||||||||||||||
Other | (3 | ) | (4 | ) | — | — | (7 | ) | |||||||||||||
Net cash provided from (used for) financing activities | 999 | (388 | ) | (68 | ) | (296 | ) | 247 | |||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||||
Property additions | (9 | ) | (192 | ) | (276 | ) | — | (477 | ) | ||||||||||||
Nuclear fuel | — | — | (159 | ) | — | (159 | ) | ||||||||||||||
Proceeds from asset sales | — | 21 | — | — | 21 | ||||||||||||||||
Sales of investment securities held in trusts | — | — | 650 | — | 650 | ||||||||||||||||
Purchases of investment securities held in trusts | — | — | (694 | ) | — | (694 | ) | ||||||||||||||
Loans to affiliated companies, net | 28 | (156 | ) | (156 | ) | 306 | 22 | ||||||||||||||
Other | — | 2 | (2 | ) | — | — | |||||||||||||||
Net cash provided from (used for) investing activities | 19 | (325 | ) | (637 | ) | 306 | (637 | ) | |||||||||||||
Net change in cash and cash equivalents | — | (1 | ) | — | — | (1 | ) | ||||||||||||||
Cash and cash equivalents at beginning of period | — | 3 | — | — | 3 | ||||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (971 | ) | $ | 683 | $ | 799 | $ | (10 | ) | $ | 501 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||||
New Financing- | |||||||||||||||||||||
Long-term debt | — | 317 | 243 | — | 560 | ||||||||||||||||
Short-term borrowings, net | 982 | 49 | — | (1,028 | ) | 3 | |||||||||||||||
Redemptions and Repayments- | |||||||||||||||||||||
Long-term debt | — | (169 | ) | (87 | ) | 10 | (246 | ) | |||||||||||||
Short-term borrowings, net | — | — | (32 | ) | 32 | — | |||||||||||||||
Other | (1 | ) | (6 | ) | (2 | ) | — | (9 | ) | ||||||||||||
Net cash provided from financing activities | 981 | 191 | 122 | (986 | ) | 308 | |||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||||
Property additions | (10 | ) | (175 | ) | (350 | ) | — | (535 | ) | ||||||||||||
Nuclear fuel | — | — | (207 | ) | — | (207 | ) | ||||||||||||||
Proceeds from asset sales | — | 17 | — | — | 17 | ||||||||||||||||
Sales of investment securities held in trusts | — | — | 1,167 | — | 1,167 | ||||||||||||||||
Purchases of investment securities held in trusts | — | — | (1,194 | ) | — | (1,194 | ) | ||||||||||||||
Loans to affiliated companies, net | 1 | (715 | ) | (337 | ) | 996 | (55 | ) | |||||||||||||
Other | (1 | ) | (5 | ) | — | — | (6 | ) | |||||||||||||
Net cash used for investing activities | (10 | ) | (878 | ) | (921 | ) | 996 | (813 | ) | ||||||||||||
Net change in cash and cash equivalents | — | (4 | ) | — | — | (4 | ) | ||||||||||||||
Cash and cash equivalents at beginning of period | — | 7 | — | — | 7 | ||||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||||
Segment_Information
Segment Information | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||||||
SEGMENT INFORMATION | ' | ||||||||||||||||||||||||
SEGMENT INFORMATION | |||||||||||||||||||||||||
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does not have separate reportable operating segments. | |||||||||||||||||||||||||
The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes regulated electric generation facilities in West Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. This business segment currently controls approximately 4,000 MWs of capacity, including the net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013. | |||||||||||||||||||||||||
The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). The segment's revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are derived from transmission services provided pursuant to the PJM open access transmission tariff to LSEs. Its results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. | |||||||||||||||||||||||||
The Competitive Energy Services segment, through FES and AE Supply, 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. This business segment currently controls approximately 14,500 MWs of capacity, including 885 MWs of capacity subject to RMR arrangements with PJM and excluding 2,080 MWs of capacity deactivated on October 9, 2013 and a net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013. This segment also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM to deliver energy to the segment’s customers. | |||||||||||||||||||||||||
The Other/Corporate Segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. Reconciling adjustments primarily consist of elimination of intersegment transactions. | |||||||||||||||||||||||||
Segment Financial Information | |||||||||||||||||||||||||
Three Months Ended | Regulated Distribution | Regulated Transmission | Competitive Energy Services | Other/Corporate | Reconciling Adjustments | Consolidated | |||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
September 30, 2013 | |||||||||||||||||||||||||
External revenues | $ | 2,340 | $ | 190 | $ | 1,573 | $ | (31 | ) | $ | (36 | ) | $ | 4,036 | |||||||||||
Internal revenues | — | — | 196 | — | (196 | ) | — | ||||||||||||||||||
Total revenues | 2,340 | 190 | 1,769 | (31 | ) | (232 | ) | 4,036 | |||||||||||||||||
Depreciation, amortization and deferrals | 460 | 31 | 125 | 12 | — | 628 | |||||||||||||||||||
Investment income (loss) | 14 | — | (5 | ) | 3 | (7 | ) | 5 | |||||||||||||||||
Interest expense | 134 | 23 | 53 | 47 | — | 257 | |||||||||||||||||||
Income taxes (benefits) | 50 | 32 | 47 | (44 | ) | (8 | ) | 77 | |||||||||||||||||
Income from continuing operations | 85 | 54 | 68 | — | 2 | 209 | |||||||||||||||||||
Discontinued operations, net of tax | — | — | 9 | — | — | 9 | |||||||||||||||||||
Net income (loss) | 85 | 54 | 77 | (10 | ) | 12 | 218 | ||||||||||||||||||
Total assets | 27,030 | 4,953 | 17,809 | 591 | — | 50,383 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 867 | — | — | 6,418 | |||||||||||||||||||
Property additions | 261 | 105 | 162 | 20 | — | 548 | |||||||||||||||||||
September 30, 2012 | |||||||||||||||||||||||||
External revenues | $ | 2,483 | $ | 187 | $ | 1,462 | $ | (31 | ) | $ | (49 | ) | $ | 4,052 | |||||||||||
Internal revenues | — | — | 209 | — | (209 | ) | — | ||||||||||||||||||
Total revenues | 2,483 | 187 | 1,671 | (31 | ) | (258 | ) | 4,052 | |||||||||||||||||
Depreciation, amortization and deferrals | 193 | 28 | 102 | 9 | 1 | 333 | |||||||||||||||||||
Investment income | 20 | — | 36 | (2 | ) | (15 | ) | 39 | |||||||||||||||||
Interest expense | 136 | 24 | 73 | (3 | ) | — | 230 | ||||||||||||||||||
Income taxes (benefits) | 168 | 35 | 74 | (8 | ) | 38 | 307 | ||||||||||||||||||
Income from continuing operations | 286 | 59 | 126 | — | (49 | ) | 422 | ||||||||||||||||||
Discontinued operations, net of tax | — | — | 3 | — | — | 3 | |||||||||||||||||||
Net income (loss) | 286 | 59 | 129 | (13 | ) | (36 | ) | 425 | |||||||||||||||||
Total assets | 26,122 | 4,519 | 16,846 | 1,251 | — | 48,738 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 893 | — | — | 6,444 | |||||||||||||||||||
Property additions | 308 | 47 | 412 | 8 | — | 775 | |||||||||||||||||||
Nine Months Ended | |||||||||||||||||||||||||
September 30, 2013 | |||||||||||||||||||||||||
External revenues | $ | 6,593 | $ | 546 | $ | 4,350 | $ | (89 | ) | $ | (130 | ) | $ | 11,270 | |||||||||||
Internal revenues | — | — | 588 | — | (588 | ) | — | ||||||||||||||||||
Total revenues | 6,593 | 546 | 4,938 | (89 | ) | (718 | ) | 11,270 | |||||||||||||||||
Depreciation, amortization and deferrals | 882 | 91 | 347 | 32 | — | 1,352 | |||||||||||||||||||
Investment income (loss) | 41 | — | (6 | ) | 6 | (33 | ) | 8 | |||||||||||||||||
Interest expense | 404 | 68 | 187 | 112 | — | 771 | |||||||||||||||||||
Income taxes (benefits) | 284 | 93 | (189 | ) | (55 | ) | (4 | ) | 129 | ||||||||||||||||
Income (loss) from continuing operations | 474 | 156 | (317 | ) | — | (80 | ) | 233 | |||||||||||||||||
Discontinued operations, net of tax | — | — | 17 | — | — | 17 | |||||||||||||||||||
Net income (loss) | 474 | 156 | (300 | ) | (92 | ) | 12 | 250 | |||||||||||||||||
Total assets | 27,030 | 4,953 | 17,809 | 591 | — | 50,383 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 867 | — | — | 6,418 | |||||||||||||||||||
Property additions | 980 | 291 | 630 | 59 | — | 1,960 | |||||||||||||||||||
September 30, 2012 | |||||||||||||||||||||||||
External revenues | $ | 6,976 | $ | 557 | $ | 4,465 | $ | (78 | ) | $ | (142 | ) | $ | 11,778 | |||||||||||
Internal revenues | — | — | 686 | — | (684 | ) | 2 | ||||||||||||||||||
Total revenues | 6,976 | 557 | 5,151 | (78 | ) | (826 | ) | 11,780 | |||||||||||||||||
Depreciation, amortization and deferrals | 618 | 86 | 303 | 25 | — | 1,032 | |||||||||||||||||||
Investment income | 62 | 1 | 48 | (1 | ) | (47 | ) | 63 | |||||||||||||||||
Interest expense | 405 | 70 | 209 | 66 | — | 750 | |||||||||||||||||||
Income taxes | 355 | 101 | 165 | (49 | ) | 78 | 650 | ||||||||||||||||||
Income from continuing operations | 603 | 171 | 284 | — | (150 | ) | 908 | ||||||||||||||||||
Discontinued operations, net of tax | — | — | 11 | — | — | 11 | |||||||||||||||||||
Net income (loss) | 603 | 171 | 295 | (82 | ) | (68 | ) | 919 | |||||||||||||||||
Total assets | 26,122 | 4,519 | 16,846 | 1,251 | — | 48,738 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 893 | — | — | 6,444 | |||||||||||||||||||
Property additions | 751 | 169 | 715 | 51 | — | 1,686 | |||||||||||||||||||
Discontinued_Operations_and_As
Discontinued Operations and Assets Held for Sale | 9 Months Ended |
Sep. 30, 2013 | |
Discontinued Operations and Disposal Groups [Abstract] | ' |
Discontinued Operations and Assets Held for Sale | ' |
DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE | |
On September 4, 2013, certain of FirstEnergy subsidiaries applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power, for approximately $400 million. The asset purchase agreement was entered into on August 23, 2013, as amended and restated as of September 4, 2013. The proposed transaction is expected to close in the fourth quarter of 2013. The asset purchase agreement is subject to customary and other closing conditions, including, without limitation, the resolution of a potential competing license application, and receipt of approvals by FERC and the VSCC, which is pending. On September 27, 2013, the Federal Trade Commission advised that the Hart-Scott-Rodino waiting period was terminated, meaning this item is complete. As of September 30, 2013, FirstEnergy classified the hydroelectric power stations, with a carrying value of $234 million (FES - $121 million) as Assets held for sale in the Consolidated Balance Sheets. Included in the carrying value of the assets held for sale is goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold. Net pre-tax results for the hydroelectric facilities of $12 million and $26 million (FES - $12 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $5 million and $19 million (FES - $8 million and $17 million) for three and nine months ended September 30, 2012, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Revenues for the hydroelectric facilities of $11 million and $24 million (FES - $10 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $6 million and $24 million (FES - $8 million and $18 million) for the three and nine months ended September 30, 2012 respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. |
Organization_and_Basis_of_Pres1
Organization and Basis of Presentation (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ' |
NEW ACCOUNTING PRONOUNCEMENTS | ' |
New Accounting Pronouncements | |
New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries. | |
EARNINGS PER SHARE OF COMMON STOCK | ' |
Basic earnings per share of common stock are computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. | |
VARIABLE INTEREST ENTITIES | ' |
FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 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. |
Goodwill_Details_Tables
Goodwill Details (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Goodwill [Line Items] | ' | ||||||||||||||||||||
Schedule of Goodwill | ' | ||||||||||||||||||||
Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows: | |||||||||||||||||||||
Goodwill | Regulated Distribution | Regulated Transmission | Competitive Energy Services | Other/Corporate | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 5,025 | $ | 526 | $ | 896 | $ | — | $ | 6,447 | |||||||||||
Classification to Assets Held for Sale(1) | — | — | (29 | ) | — | (29 | ) | ||||||||||||||
Balance as of September 30, 2013 | $ | 5,025 | $ | 526 | $ | 867 | $ | — | $ | 6,418 | |||||||||||
-1 | See Note 16, Discontinued Operations and Assets Held for Sale. |
Impairment_of_Longlived_Assets1
Impairment of Long-lived Assets (Tables) | 9 Months Ended | ||
Sep. 30, 2013 | |||
Property, Plant and Equipment [Abstract] | ' | ||
Schedule of Generating Plant Retirements | ' | ||
On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013: | |||
Generating Units | MW Capacity | Location | |
Hatfield's Ferry, Units 1-3 | 1,710 | Masontown, Pennsylvania | |
Mitchell, Units 2-3 | 370 | Courtney, Pennsylvania |
Earnings_Per_Share_of_Common_S1
Earnings Per Share of Common Stock (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Earnings Per Share [Abstract] | ' | ||||||||||||||||
Reconciliation of basic and diluted earnings per share | ' | ||||||||||||||||
The following table reconciles basic and diluted earnings per share of common stock: | |||||||||||||||||
Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||||||||||
Reconciliation of Basic and Diluted Earnings per Share of Common Stock | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions, except per share amounts) | |||||||||||||||||
Net income from continuing operations | $ | 209 | $ | 422 | $ | 233 | $ | 908 | |||||||||
Less: Income attributable to noncontrolling interest | — | — | — | 1 | |||||||||||||
Income from continuing operations available to common shareholders | 209 | 422 | 233 | 907 | |||||||||||||
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 | |||||||||||||
Earnings available to FirstEnergy Corp. | $ | 218 | $ | 425 | $ | 250 | $ | 918 | |||||||||
Weighted average number of basic shares outstanding | 418 | 417 | 418 | 418 | |||||||||||||
Assumed exercise of dilutive stock options and awards(1) | 1 | 2 | 1 | 1 | |||||||||||||
Weighted average number of diluted shares outstanding | 419 | 419 | 419 | 419 | |||||||||||||
Earnings per share: | |||||||||||||||||
Basic earnings per share: | |||||||||||||||||
Net income from continuing operations | $ | 0.5 | $ | 1.01 | $ | 0.56 | $ | 2.17 | |||||||||
Discontinued operations (Note 16) | 0.02 | 0.01 | 0.04 | 0.03 | |||||||||||||
Net earnings per basic share | $ | 0.52 | $ | 1.02 | $ | 0.6 | $ | 2.2 | |||||||||
Diluted earnings per share: | |||||||||||||||||
Net income from continuing operations | $ | 0.5 | $ | 1 | $ | 0.56 | $ | 2.16 | |||||||||
Discontinued operations (Note 16) | 0.02 | 0.01 | 0.04 | 0.03 | |||||||||||||
Net earnings per diluted share | $ | 0.52 | $ | 1.01 | $ | 0.6 | $ | 2.19 | |||||||||
(1) | For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. |
Pension_and_Other_Postemployme1
Pension and Other Postemployment Benefits (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ' | ||||||||||||||||
Components of Net Periodic Benefit Costs | ' | ||||||||||||||||
The components of the consolidated net periodic cost for pensions and OPEB (including amounts capitalized) were as follows: | |||||||||||||||||
Components of Net Periodic Benefit Costs (Credits) | Pensions | OPEB | |||||||||||||||
For the Three Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
Service costs | $ | 49 | $ | 40 | $ | 3 | $ | 3 | |||||||||
Interest costs | 93 | 97 | 9 | 12 | |||||||||||||
Expected return on plan assets | (125 | ) | (121 | ) | (8 | ) | (9 | ) | |||||||||
Amortization of prior service costs (credits) | 3 | 3 | (50 | ) | (50 | ) | |||||||||||
Net periodic costs (credits) | $ | 20 | $ | 19 | $ | (46 | ) | $ | (44 | ) | |||||||
Components of Net Periodic Benefit Costs (Credits) | Pensions | OPEB | |||||||||||||||
For the Nine Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
Service costs | $ | 147 | $ | 120 | $ | 9 | $ | 9 | |||||||||
Interest costs | 279 | 291 | 27 | 36 | |||||||||||||
Expected return on plan assets | (375 | ) | (363 | ) | (24 | ) | (27 | ) | |||||||||
Amortization of prior service costs (credits) | 9 | 9 | (157 | ) | (152 | ) | |||||||||||
Net periodic costs (credits) | $ | 60 | $ | 57 | $ | (145 | ) | $ | (134 | ) | |||||||
Net Periodic Pension and OPEB Costs | ' | ||||||||||||||||
The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and FES were as follows: | |||||||||||||||||
Net Periodic Benefit Expense (Credit) | Pensions | OPEB | |||||||||||||||
For the Three Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
FirstEnergy | $ | 16 | $ | 14 | $ | (31 | ) | $ | (30 | ) | |||||||
FES | 5 | 5 | (4 | ) | (4 | ) | |||||||||||
Net Periodic Benefit Expense (Credit) | Pensions | OPEB | |||||||||||||||
For the Nine Months Ended September 30, | 2013 | 2012 | 2013 | 2012 | |||||||||||||
(In millions) | |||||||||||||||||
FirstEnergy | $ | 41 | $ | 41 | $ | (95 | ) | $ | (92 | ) | |||||||
FES | 13 | 13 | (12 | ) | (12 | ) | |||||||||||
Accumulated_Other_Comprehensiv1
Accumulated Other Comprehensive Income (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Statement of Other Comprehensive Income [Abstract] | ' | ||||||||||||||||
Schedule of Accumulated Other Comprehensive Income | ' | ||||||||||||||||
The changes in AOCI, net of tax, in the three and nine months ended September 30, 2013 and 2012, for FirstEnergy and FES are shown in the following tables: | |||||||||||||||||
FirstEnergy | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of July 1, 2013 | $ | (37 | ) | $ | 13 | $ | 347 | $ | 323 | ||||||||
Other comprehensive income before reclassifications | — | 5 | — | 5 | |||||||||||||
Amounts reclassified from AOCI | 1 | (1 | ) | (29 | ) | (29 | ) | ||||||||||
Net other comprehensive income (loss) | 1 | 4 | (29 | ) | (24 | ) | |||||||||||
AOCI Balance as of September 30, 2013 | $ | (36 | ) | $ | 17 | $ | 318 | $ | 299 | ||||||||
AOCI Balance as of July 1, 2012 | $ | (39 | ) | $ | 27 | $ | 401 | $ | 389 | ||||||||
Other comprehensive income before reclassifications | — | 25 | — | 25 | |||||||||||||
Amounts reclassified from AOCI | — | (25 | ) | (22 | ) | (47 | ) | ||||||||||
Net other comprehensive loss | — | — | (22 | ) | (22 | ) | |||||||||||
AOCI Balance as of September 30, 2012 | $ | (39 | ) | $ | 27 | $ | 379 | $ | 367 | ||||||||
FES | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of July 1, 2013 | $ | 1 | $ | 12 | $ | 49 | $ | 62 | |||||||||
Other comprehensive income before reclassifications | — | 4 | — | 4 | |||||||||||||
Amounts reclassified from AOCI | — | (1 | ) | (3 | ) | (4 | ) | ||||||||||
Net other comprehensive income (loss) | — | 3 | (3 | ) | — | ||||||||||||
AOCI Balance as of September 30, 2013 | $ | 1 | $ | 15 | $ | 46 | $ | 62 | |||||||||
AOCI Balance as of July 1, 2012 | $ | 6 | $ | 25 | $ | 53 | $ | 84 | |||||||||
Other comprehensive income (loss) before reclassifications | (1 | ) | 24 | — | 23 | ||||||||||||
Amounts reclassified from AOCI | (1 | ) | (25 | ) | (3 | ) | (29 | ) | |||||||||
Net other comprehensive loss | (2 | ) | (1 | ) | (3 | ) | (6 | ) | |||||||||
AOCI Balance as of September 30, 2012 | $ | 4 | $ | 24 | $ | 50 | $ | 78 | |||||||||
FirstEnergy | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of January 1, 2013 | $ | (38 | ) | $ | 15 | $ | 408 | $ | 385 | ||||||||
Other comprehensive income before reclassifications | — | 19 | — | 19 | |||||||||||||
Amounts reclassified from AOCI | 2 | (17 | ) | (90 | ) | (105 | ) | ||||||||||
Net other comprehensive income (loss) | 2 | 2 | (90 | ) | (86 | ) | |||||||||||
AOCI Balance as of September 30, 2013 | $ | (36 | ) | $ | 17 | $ | 318 | $ | 299 | ||||||||
AOCI Balance as of January 1, 2012 | $ | (39 | ) | $ | 19 | $ | 446 | $ | 426 | ||||||||
Other comprehensive income before reclassifications | 1 | 38 | 5 | 44 | |||||||||||||
Amounts reclassified from AOCI | (1 | ) | (30 | ) | (72 | ) | (103 | ) | |||||||||
Net other comprehensive income (loss) | — | 8 | (67 | ) | (59 | ) | |||||||||||
AOCI Balance as of September 30, 2012 | $ | (39 | ) | $ | 27 | $ | 379 | $ | 367 | ||||||||
FES | |||||||||||||||||
Gains & Losses on Cash Flow Hedges | Unrealized Gains on AFS Securities | Defined Benefit Pension & OPEB Plans | Total | ||||||||||||||
(In millions) | |||||||||||||||||
AOCI Balance as of January 1, 2013 | $ | 3 | $ | 13 | $ | 56 | $ | 72 | |||||||||
Other comprehensive income before reclassifications | — | 17 | — | 17 | |||||||||||||
Amounts reclassified from AOCI | (2 | ) | (15 | ) | (10 | ) | (27 | ) | |||||||||
Net other comprehensive income (loss) | (2 | ) | 2 | (10 | ) | (10 | ) | ||||||||||
AOCI Balance as of September 30, 2013 | $ | 1 | $ | 15 | $ | 46 | $ | 62 | |||||||||
AOCI Balance as of January 1, 2012 | $ | 8 | $ | 16 | $ | 52 | $ | 76 | |||||||||
Other comprehensive income before reclassifications | — | 37 | 8 | 45 | |||||||||||||
Amounts reclassified from AOCI | (4 | ) | (29 | ) | (10 | ) | (43 | ) | |||||||||
Net other comprehensive income (loss) | (4 | ) | 8 | (2 | ) | 2 | |||||||||||
AOCI Balance as of September 30, 2012 | $ | 4 | $ | 24 | $ | 50 | $ | 78 | |||||||||
Reclassification out of Accumulated Other Comprehensive Income | ' | ||||||||||||||||
The following amounts were reclassified from AOCI in the three months ended September 30, 2013 and 2012: | |||||||||||||||||
FE | Three Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (1 | ) | $ | (2 | ) | Other operating expenses | ||||||||||
Long-term debt | 3 | 2 | Interest expense | ||||||||||||||
2 | — | Total before taxes | |||||||||||||||
(1 | ) | — | Income taxes | ||||||||||||||
$ | 1 | $ | — | Net of tax | |||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (2 | ) | $ | (40 | ) | Investment income | ||||||||||
1 | 15 | Income taxes | |||||||||||||||
$ | (1 | ) | $ | (25 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (47 | ) | $ | (47 | ) | (a) | ||||||||||
18 | 25 | Income taxes | |||||||||||||||
$ | (29 | ) | $ | (22 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
FES | Three Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (1 | ) | $ | (2 | ) | Other operating expenses | ||||||||||
1 | 1 | Income taxes (benefits) | |||||||||||||||
$ | — | $ | (1 | ) | Net of tax | ||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (2 | ) | $ | (40 | ) | Investment income (loss) | ||||||||||
1 | 15 | Income taxes (benefits) | |||||||||||||||
$ | (1 | ) | $ | (25 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (5 | ) | $ | (5 | ) | (a) | ||||||||||
2 | 2 | Income taxes (benefits) | |||||||||||||||
$ | (3 | ) | $ | (3 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
The following amounts were reclassified from AOCI in the nine months ended September 30, 2013 and 2012: | |||||||||||||||||
FE | Nine Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (5 | ) | $ | (7 | ) | Other operating expenses | ||||||||||
Long-term debt | 9 | 6 | Interest expense | ||||||||||||||
4 | (1 | ) | Total before taxes | ||||||||||||||
(2 | ) | — | Income taxes | ||||||||||||||
$ | 2 | $ | (1 | ) | Net of tax | ||||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (27 | ) | $ | (48 | ) | Investment income | ||||||||||
10 | 18 | Income taxes | |||||||||||||||
$ | (17 | ) | $ | (30 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (148 | ) | $ | (143 | ) | (a) | ||||||||||
58 | 71 | Income taxes | |||||||||||||||
$ | (90 | ) | $ | (72 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. | |||||||||||||||||
FES | Nine Months Ended September 30 | Affected Line Item in Consolidated Statements of Income | |||||||||||||||
Reclassifications from AOCI (b) | 2013 | 2012 | |||||||||||||||
(In millions) | |||||||||||||||||
Gains & losses on cash flow hedges | |||||||||||||||||
Commodity contracts | $ | (5 | ) | $ | (6 | ) | Other operating expenses | ||||||||||
Long-term debt | 2 | — | Interest expense | ||||||||||||||
(3 | ) | (6 | ) | Total before taxes | |||||||||||||
1 | 2 | Income taxes (benefits) | |||||||||||||||
$ | (2 | ) | $ | (4 | ) | Net of tax | |||||||||||
Unrealized gains on AFS securities | |||||||||||||||||
Realized gains on sales of securities | $ | (24 | ) | $ | (46 | ) | Investment income (loss) | ||||||||||
9 | 17 | Income taxes (benefits) | |||||||||||||||
$ | (15 | ) | $ | (29 | ) | Net of tax | |||||||||||
Defined benefit pension and OPEB plans | |||||||||||||||||
Prior-service costs | $ | (16 | ) | $ | (15 | ) | (a) | ||||||||||
6 | 5 | Income taxes (benefits) | |||||||||||||||
$ | (10 | ) | $ | (10 | ) | Net of tax | |||||||||||
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. | |||||||||||||||||
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI. |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
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 September 30, 2013: | ||||||||||||
Maximum | Discounted Lease | Net | ||||||||||
Exposure | Payments, net(1) | Exposure | ||||||||||
(In millions) | ||||||||||||
FES | $ | 1,288 | $ | 1,079 | $ | 209 | ||||||
Other FE subsidiaries | 762 | 329 | 433 | |||||||||
(1) | The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion. |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 9 Months Ended | |||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||||||||||||
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 | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||
Assets | (In millions) | |||||||||||||||||||||||||||||||||||
Corporate debt securities | $ | — | $ | 1,299 | $ | — | $ | 1,299 | $ | — | $ | 1,259 | $ | — | $ | 1,259 | ||||||||||||||||||||
Derivative assets - commodity contracts | 4 | 197 | — | 201 | — | 252 | — | 252 | ||||||||||||||||||||||||||||
Derivative assets - FTRs | — | — | 3 | 3 | — | — | 8 | 8 | ||||||||||||||||||||||||||||
Derivative assets - NUG contracts(1) | — | — | 23 | 23 | — | — | 36 | 36 | ||||||||||||||||||||||||||||
Equity securities(2) | 461 | — | — | 461 | 310 | — | — | 310 | ||||||||||||||||||||||||||||
Foreign government debt securities | — | 101 | — | 101 | — | 126 | — | 126 | ||||||||||||||||||||||||||||
U.S. government debt securities | — | 171 | — | 171 | — | 179 | — | 179 | ||||||||||||||||||||||||||||
U.S. state debt securities | — | 226 | — | 226 | — | 299 | — | 299 | ||||||||||||||||||||||||||||
Other(3) | 160 | 157 | — | 317 | 126 | 227 | — | 353 | ||||||||||||||||||||||||||||
Total assets | $ | 625 | $ | 2,151 | $ | 26 | $ | 2,802 | $ | 436 | $ | 2,342 | $ | 44 | $ | 2,822 | ||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Derivative liabilities - commodity contracts | $ | (5 | ) | $ | (107 | ) | $ | — | $ | (112 | ) | $ | (3 | ) | $ | (151 | ) | $ | — | $ | (154 | ) | ||||||||||||||
Derivative liabilities - FTRs | — | — | (14 | ) | (14 | ) | — | — | (9 | ) | (9 | ) | ||||||||||||||||||||||||
Derivative liabilities - NUG contracts(1) | — | — | (233 | ) | (233 | ) | — | — | (290 | ) | (290 | ) | ||||||||||||||||||||||||
Derivative liabilities - LCAPP contracts(1) | — | — | (166 | ) | (166 | ) | — | — | (144 | ) | (144 | ) | ||||||||||||||||||||||||
Total liabilities | $ | (5 | ) | $ | (107 | ) | $ | (413 | ) | $ | (525 | ) | $ | (3 | ) | $ | (151 | ) | $ | (443 | ) | $ | (597 | ) | ||||||||||||
Net assets (liabilities)(4) | $ | 620 | $ | 2,044 | $ | (387 | ) | $ | 2,277 | $ | 433 | $ | 2,191 | $ | (399 | ) | $ | 2,225 | ||||||||||||||||||
(1) | NUG and LCAPP contracts are generally 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 short-term cash investments. | |||||||||||||||||||||||||||||||||||
(4) | Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, 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 and LCAPP contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
NUG Contracts(1) | LCAPP Contracts(1) | FTRs | ||||||||||||||||||||||||||||||||||
Derivative Assets | Derivative Liabilities | Net | Derivative Assets | Derivative Liabilities | Net | Derivative Assets | Derivative Liabilities | Net | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
January 1, 2012 Balance | $ | 57 | $ | (349 | ) | $ | (292 | ) | $ | — | $ | — | $ | — | $ | 1 | $ | (23 | ) | $ | (22 | ) | ||||||||||||||
Unrealized gain (loss) | (20 | ) | (180 | ) | (200 | ) | — | 1 | 1 | 6 | (6 | ) | — | |||||||||||||||||||||||
Purchases | — | — | — | — | (145 | ) | (145 | ) | 13 | (10 | ) | 3 | ||||||||||||||||||||||||
Settlements | (1 | ) | 239 | 238 | — | — | — | (12 | ) | 30 | 18 | |||||||||||||||||||||||||
December 31, 2012 Balance | $ | 36 | $ | (290 | ) | $ | (254 | ) | $ | — | $ | (144 | ) | $ | (144 | ) | $ | 8 | $ | (9 | ) | $ | (1 | ) | ||||||||||||
Unrealized gain (loss) | (6 | ) | (6 | ) | (12 | ) | — | (22 | ) | (22 | ) | 1 | 2 | 3 | ||||||||||||||||||||||
Purchases | — | — | — | — | — | — | 5 | (15 | ) | (10 | ) | |||||||||||||||||||||||||
Settlements | (7 | ) | 63 | 56 | — | — | — | (11 | ) | 8 | (3 | ) | ||||||||||||||||||||||||
September 30, 2013 Balance | $ | 23 | $ | (233 | ) | $ | (210 | ) | $ | — | $ | (166 | ) | $ | (166 | ) | $ | 3 | $ | (14 | ) | $ | (11 | ) | ||||||||||||
(1) | Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. | |||||||||||||||||||||||||||||||||||
Quantitative information for level 3 valuation | ' | |||||||||||||||||||||||||||||||||||
The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended September 30, 2013: | ||||||||||||||||||||||||||||||||||||
Fair Value, Net (In millions) | Valuation | Significant Input | Range | Weighted Average | Units | |||||||||||||||||||||||||||||||
Technique | ||||||||||||||||||||||||||||||||||||
FTRs | $ | (11 | ) | Model | RTO auction clearing prices | ($5.60) to $5.40 | $0.62 | Dollars/MWH | ||||||||||||||||||||||||||||
NUG Contracts | $ | (210 | ) | Model | Generation | 600 to 5,864,000 | 1,421,000 | MWH | ||||||||||||||||||||||||||||
Electricity regional prices | $41.40 to $57.30 | $49.40 | Dollars/MWH | |||||||||||||||||||||||||||||||||
LCAPP Contracts | $ | (166 | ) | Model | Regional capacity prices | $158.60 to $187.60 | $171.20 | Dollars/MW-Day | ||||||||||||||||||||||||||||
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, nuclear fuel disposal and NUG trusts as of September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
September 30, 2013(1) | December 31, 2012(2) | |||||||||||||||||||||||||||||||||||
Cost Basis | Unrealized Gains | Fair Value | Cost Basis | Unrealized Gains | Fair Value | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Debt securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,825 | $ | 21 | $ | 1,846 | $ | 1,827 | $ | 34 | $ | 1,861 | ||||||||||||||||||||||||
FES | 868 | 9 | 877 | 778 | 14 | 792 | ||||||||||||||||||||||||||||||
Equity securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 433 | $ | 28 | $ | 461 | $ | 293 | $ | 16 | $ | 309 | ||||||||||||||||||||||||
FES | 317 | 21 | 338 | 281 | 13 | 294 | ||||||||||||||||||||||||||||||
(1) | Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million. | |||||||||||||||||||||||||||||||||||
(2) | Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 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 months and nine months ended September 30, 2013 and 2012 were as follows: | ||||||||||||||||||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and | |||||||||||||||||||||||||||||||
Dividend Income | ||||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 368 | $ | 9 | $ | (15 | ) | $ | (21 | ) | $ | 26 | ||||||||||||||||||||||||
FES | 164 | 5 | (3 | ) | (21 | ) | 16 | |||||||||||||||||||||||||||||
September 30, 2012 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and Dividend Income | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,751 | $ | 81 | $ | (30 | ) | $ | (2 | ) | $ | 18 | ||||||||||||||||||||||||
FES | 1,059 | 60 | (21 | ) | (2 | ) | 10 | |||||||||||||||||||||||||||||
Nine Months Ended | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and | |||||||||||||||||||||||||||||||
Dividend Income | ||||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 1,545 | $ | 49 | $ | (31 | ) | $ | (74 | ) | $ | 74 | ||||||||||||||||||||||||
FES | 650 | 38 | (14 | ) | (66 | ) | 44 | |||||||||||||||||||||||||||||
September 30, 2012 | Sale Proceeds | Realized Gains | Realized Losses | OTTI | Interest and Dividend Income | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 2,133 | $ | 118 | $ | (58 | ) | $ | (9 | ) | $ | 51 | ||||||||||||||||||||||||
FES | 1,167 | 85 | (40 | ) | (8 | ) | 27 | |||||||||||||||||||||||||||||
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities | ' | |||||||||||||||||||||||||||||||||||
The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||||||
Cost Basis | Unrealized Gains | Fair Value | Cost Basis | Unrealized Gains | Fair Value | |||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Debt Securities | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 46 | $ | 1 | $ | 47 | $ | 54 | $ | 30 | $ | 84 | ||||||||||||||||||||||||
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 and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts: | ||||||||||||||||||||||||||||||||||||
September 30, 2013 | December 31, 2012 | |||||||||||||||||||||||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||||||||||||||||||||||
Value | Value | Value | Value | |||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
FirstEnergy | $ | 17,007 | $ | 17,721 | $ | 16,957 | $ | 19,460 | ||||||||||||||||||||||||||||
FES | 3,015 | 3,082 | 4,194 | 4,524 | ||||||||||||||||||||||||||||||||
FES | ' | |||||||||||||||||||||||||||||||||||
Fair Value of Financial Instruments [Line Items] | ' | |||||||||||||||||||||||||||||||||||
Assets and liabilities measured on recurring basis | ' | |||||||||||||||||||||||||||||||||||
FES | ||||||||||||||||||||||||||||||||||||
Recurring Fair Value Measurements | September 30, 2013 | December 31, 2012 | ||||||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||||||
Assets | (In millions) | |||||||||||||||||||||||||||||||||||
Corporate debt securities | $ | — | $ | 742 | $ | — | $ | 742 | $ | — | $ | 703 | $ | — | $ | 703 | ||||||||||||||||||||
Derivative assets - commodity contracts | 4 | 197 | — | 201 | — | 252 | — | 252 | ||||||||||||||||||||||||||||
Derivative assets - FTRs | — | — | 2 | 2 | — | — | 6 | 6 | ||||||||||||||||||||||||||||
Equity securities(1) | 338 | — | — | 338 | 294 | — | — | 294 | ||||||||||||||||||||||||||||
Foreign government debt securities | — | 58 | — | 58 | — | 61 | — | 61 | ||||||||||||||||||||||||||||
U.S. government debt securities | — | 26 | — | 26 | — | 27 | — | 27 | ||||||||||||||||||||||||||||
Other(2) | — | 94 | — | 94 | — | 104 | — | 104 | ||||||||||||||||||||||||||||
Total assets | $ | 342 | $ | 1,117 | $ | 2 | $ | 1,461 | $ | 294 | $ | 1,147 | $ | 6 | $ | 1,447 | ||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Derivative liabilities - commodity contracts | $ | (5 | ) | $ | (107 | ) | $ | — | $ | (112 | ) | $ | (3 | ) | $ | (151 | ) | $ | — | $ | (154 | ) | ||||||||||||||
Derivative liabilities - FTRs | — | — | (13 | ) | (13 | ) | — | — | (6 | ) | (6 | ) | ||||||||||||||||||||||||
Total liabilities | $ | (5 | ) | $ | (107 | ) | $ | (13 | ) | $ | (125 | ) | $ | (3 | ) | $ | (151 | ) | $ | (6 | ) | $ | (160 | ) | ||||||||||||
Net assets (liabilities)(3) | $ | 337 | $ | 1,010 | $ | (11 | ) | $ | 1,336 | $ | 291 | $ | 996 | $ | — | $ | 1,287 | |||||||||||||||||||
(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 $12 million and $94 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with the 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 September 30, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
Derivative Asset FTRs | Derivative Liability FTRs | Net FTRs | ||||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
January 1, 2012 Balance | $ | 1 | $ | (7 | ) | $ | (6 | ) | ||||||||||||||||||||||||||||
Unrealized gain (loss) | 4 | (4 | ) | — | ||||||||||||||||||||||||||||||||
Purchases | 9 | (7 | ) | 2 | ||||||||||||||||||||||||||||||||
Settlements | (8 | ) | 12 | 4 | ||||||||||||||||||||||||||||||||
December 31, 2012 Balance | $ | 6 | $ | (6 | ) | $ | — | |||||||||||||||||||||||||||||
Unrealized loss | (1 | ) | (1 | ) | (2 | ) | ||||||||||||||||||||||||||||||
Purchases | 4 | (12 | ) | (8 | ) | |||||||||||||||||||||||||||||||
Settlements | (7 | ) | 6 | (1 | ) | |||||||||||||||||||||||||||||||
September 30, 2013 Balance | $ | 2 | $ | (13 | ) | $ | (11 | ) | ||||||||||||||||||||||||||||
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 September 30, 2013: | ||||||||||||||||||||||||||||||||||||
Fair Value, Net (In millions) | Valuation | Significant Input | Range | Weighted Average | Units | |||||||||||||||||||||||||||||||
Technique | ||||||||||||||||||||||||||||||||||||
FTRs | $ | (11 | ) | Model | RTO auction clearing prices | ($5.60) to $5.40 | $0.40 | Dollars/MWH |
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ' | ||||||||||||||||
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 | ||||||||||||||||
September 30, | December 31, | September 30, | December 31, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||
(In millions) | (In millions) | ||||||||||||||||
Current Assets - Derivatives | Current Liabilities - Derivatives | ||||||||||||||||
Commodity Contracts | $ | 137 | $ | 153 | Commodity Contracts | $ | (94 | ) | $ | (119 | ) | ||||||
FTRs | 3 | 7 | FTRs | (11 | ) | (7 | ) | ||||||||||
140 | 160 | (105 | ) | (126 | ) | ||||||||||||
Noncurrent Liabilities - Adverse Power Contract Liability | |||||||||||||||||
NUGs | (233 | ) | (290 | ) | |||||||||||||
Deferred Charges and Other Assets - Other | LCAAP | (166 | ) | (144 | ) | ||||||||||||
Commodity Contracts | 64 | 99 | Noncurrent Liabilities - Other | ||||||||||||||
FTRs | — | 1 | Commodity Contracts | (18 | ) | (36 | ) | ||||||||||
NUGs | 23 | 36 | FTRs | (3 | ) | (2 | ) | ||||||||||
87 | 136 | (420 | ) | (472 | ) | ||||||||||||
Derivative Assets | $ | 227 | $ | 296 | Derivative Liabilities | $ | (525 | ) | $ | (598 | ) | ||||||
Offsetting assets and liabilities | ' | ||||||||||||||||
The following tables summarize the fair value of derivative instruments 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 | |||||||||||||||||
September 30, 2013 | Fair Value | Derivative Instruments | Cash Collateral (Received)/Pledged | Net Fair Value | |||||||||||||
(In millions) | |||||||||||||||||
Derivative Assets | |||||||||||||||||
Commodity contracts | $ | 201 | $ | (104 | ) | $ | (11 | ) | $ | 86 | |||||||
FTRs | 3 | (3 | ) | — | — | ||||||||||||
NUG contracts | 23 | — | — | 23 | |||||||||||||
$ | 227 | $ | (107 | ) | $ | (11 | ) | $ | 109 | ||||||||
Derivative Liabilities | |||||||||||||||||
Commodity contracts | $ | (112 | ) | $ | 104 | $ | 5 | $ | (3 | ) | |||||||
FTRs | (14 | ) | 3 | 6 | (5 | ) | |||||||||||
NUG contracts | (233 | ) | — | — | (233 | ) | |||||||||||
LCAPP contracts | (166 | ) | — | — | (166 | ) | |||||||||||
$ | (525 | ) | $ | 107 | $ | 11 | $ | (407 | ) | ||||||||
Amounts Not Offset in Consolidated Balance Sheet | |||||||||||||||||
December 31, 2012 | Fair Value | Derivative Instruments | Cash Collateral (Received)/Pledged | Net Fair Value | |||||||||||||
(In millions) | |||||||||||||||||
Derivative Assets | |||||||||||||||||
Commodity contracts | $ | 252 | $ | (142 | ) | $ | (5 | ) | $ | 105 | |||||||
FTRs | 8 | (8 | ) | — | — | ||||||||||||
NUG contracts | 36 | — | — | 36 | |||||||||||||
$ | 296 | $ | (150 | ) | $ | (5 | ) | $ | 141 | ||||||||
Derivative Liabilities | |||||||||||||||||
Commodity contracts | $ | (155 | ) | $ | 142 | $ | 12 | $ | (1 | ) | |||||||
FTRs | (9 | ) | 8 | 1 | — | ||||||||||||
NUG contracts | (290 | ) | — | — | (290 | ) | |||||||||||
LCAPP contracts | (144 | ) | — | — | (144 | ) | |||||||||||
$ | (598 | ) | $ | 150 | $ | 13 | $ | (435 | ) | ||||||||
Volume of First Energy's outstanding derivative transactions | ' | ||||||||||||||||
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2013: | |||||||||||||||||
Purchases | Sales | Net | Units | ||||||||||||||
(In millions, except for LCAPP) | |||||||||||||||||
Power Contracts | 32 | 37 | (5 | ) | MWH | ||||||||||||
FTRs | 59 | — | 59 | MWH | |||||||||||||
NUGs | 11 | — | 11 | MWH | |||||||||||||
LCAPP | 408 | — | 408 | MW | |||||||||||||
Natural Gas | 64 | — | 64 | mmBTU | |||||||||||||
Effect of derivative instruments on statements of income and comprehensive income | ' | ||||||||||||||||
The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months and nine months ended September 30, 2013 and 2012, are summarized in the following tables: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Commodity Contracts | FTRs | Interest Rate Swaps | Total | ||||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 11 | $ | (8 | ) | $ | — | $ | 3 | ||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 14 | $ | 6 | $ | — | $ | 20 | |||||||||
Purchased Power Expense | (17 | ) | — | — | (17 | ) | |||||||||||
Other Operating Expense | — | (10 | ) | — | (10 | ) | |||||||||||
Fuel Expense | (2 | ) | — | — | (2 | ) | |||||||||||
2012 | |||||||||||||||||
Unrealized Gain (Loss) Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 7 | $ | (5 | ) | $ | — | $ | 2 | ||||||||
Interest Expense | — | — | 20 | 20 | |||||||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 46 | $ | 6 | $ | — | $ | 52 | |||||||||
Purchased Power Expense | (27 | ) | — | — | (27 | ) | |||||||||||
Other Operating Expense | — | (10 | ) | — | (10 | ) | |||||||||||
Fuel Expense | 3 | — | — | 3 | |||||||||||||
Interest Expense | — | — | 6 | 6 | |||||||||||||
Nine Months Ended September 30 | |||||||||||||||||
Commodity | FTRs | Interest Rate Swaps | Total | ||||||||||||||
Contracts | |||||||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Loss Recognized in: | |||||||||||||||||
Other Operating Expense | $ | (5 | ) | $ | (10 | ) | $ | — | $ | (15 | ) | ||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 29 | $ | 19 | $ | — | $ | 48 | |||||||||
Purchased Power Expense | (30 | ) | — | — | (30 | ) | |||||||||||
Other Operating Expense | — | (28 | ) | — | (28 | ) | |||||||||||
2012 | |||||||||||||||||
Unrealized Gain Recognized in: | |||||||||||||||||
Other Operating Expense | $ | 72 | $ | 12 | $ | — | $ | 84 | |||||||||
Realized Gain (Loss) Reclassified to: | |||||||||||||||||
Revenues | $ | 260 | $ | 18 | $ | — | $ | 278 | |||||||||
Purchased Power Expense | (248 | ) | — | — | (248 | ) | |||||||||||
Other Operating Expense | — | (51 | ) | — | (51 | ) | |||||||||||
Fuel Expense | 2 | — | — | 2 | |||||||||||||
Interest Expense | — | — | 6 | 6 | |||||||||||||
Derivative instruments subject to regulatory accounting | ' | ||||||||||||||||
The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2013 and 2012, are summarized in the following tables: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | 7 | $ | (8 | ) | $ | 1 | $ | — | ||||||||
Realized Gain (Loss) on Derivative Instrument | 14 | — | (1 | ) | 13 | ||||||||||||
2012 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | (50 | ) | $ | 3 | $ | — | $ | (47 | ) | |||||||
Realized Gain (Loss) on Derivative Instrument | 61 | — | (1 | ) | 60 | ||||||||||||
Nine Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
2013 | |||||||||||||||||
Unrealized Gain (Loss) on Derivative Instrument | $ | (13 | ) | $ | (22 | ) | $ | 1 | $ | (34 | ) | ||||||
Realized Gain (Loss) on Derivative Instrument | 57 | — | (1 | ) | 56 | ||||||||||||
2012 | |||||||||||||||||
Unrealized Loss on Derivative Instrument | $ | (183 | ) | $ | (142 | ) | $ | — | $ | (325 | ) | ||||||
Realized Gain on Derivative Instrument | 194 | — | 7 | 201 | |||||||||||||
Reconciliation of changes in the fair value of certain contracts that are deferred | ' | ||||||||||||||||
The following tables provide a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months and nine months ended September 30, 2013 and 2012: | |||||||||||||||||
Three Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
Outstanding net liability as of July 1, 2013 | $ | (231 | ) | $ | (158 | ) | $ | — | $ | (389 | ) | ||||||
Additions/Change in value of existing contracts | 7 | (8 | ) | 1 | — | ||||||||||||
Settled contracts | 14 | — | (1 | ) | 13 | ||||||||||||
Outstanding net liability as of September 30, 2013 | $ | (210 | ) | $ | (166 | ) | $ | — | $ | (376 | ) | ||||||
Outstanding net liability as of July 1, 2012 | $ | (293 | ) | $ | (145 | ) | $ | — | $ | (438 | ) | ||||||
Additions/Change in value of existing contracts | (50 | ) | 3 | — | (47 | ) | |||||||||||
Settled contracts | 61 | — | (1 | ) | 60 | ||||||||||||
Outstanding net liability as of September 30, 2012 | $ | (282 | ) | $ | (142 | ) | $ | (1 | ) | $ | (425 | ) | |||||
Nine Months Ended September 30 | |||||||||||||||||
Derivatives Not in a Hedging Relationship with Regulatory Offset | NUGs | LCAPP | Regulated FTRs | Total | |||||||||||||
(In millions) | |||||||||||||||||
Outstanding net liability as of January 1, 2013 | $ | (254 | ) | $ | (144 | ) | $ | — | $ | (398 | ) | ||||||
Additions/Change in value of existing contracts | (13 | ) | (22 | ) | 1 | (34 | ) | ||||||||||
Settled contracts | 57 | — | (1 | ) | 56 | ||||||||||||
Outstanding net liability as of September 30, 2013 | $ | (210 | ) | $ | (166 | ) | $ | — | $ | (376 | ) | ||||||
Outstanding net liability as of January 1, 2012 | $ | (293 | ) | $ | — | $ | (8 | ) | $ | (301 | ) | ||||||
Additions/Change in value of existing contracts | (183 | ) | (142 | ) | — | (325 | ) | ||||||||||
Settled contracts | 194 | — | 7 | 201 | |||||||||||||
Outstanding net liability as of September 30, 2012 | $ | (282 | ) | $ | (142 | ) | $ | (1 | ) | $ | (425 | ) |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 9 Months Ended | ||||||||
Sep. 30, 2013 | |||||||||
Asset Retirement Obligations (Tables) [Abstract] | ' | ||||||||
Changes to the asset retirement obligations | ' | ||||||||
The following table summarizes the changes to the ARO balances during 2013: | |||||||||
ARO Reconciliation | FirstEnergy | FES | |||||||
(In millions) | |||||||||
Balance, December 31, 2012 | $ | 1,599 | $ | 965 | |||||
Liabilities settled | (13 | ) | (14 | ) | |||||
Accretion | 85 | 52 | |||||||
Revisions in estimated cash flows | 163 | 156 | |||||||
Balance, September 30, 2013 | $ | 1,834 | $ | 1,159 | |||||
Commitments_Guarantees_and_Con1
Commitments, Guarantees and Contingencies (Tables) | 9 Months Ended | ||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ' | ||||||||||||||||
Schedule of Guarantor Obligations | ' | ||||||||||||||||
The following table discloses the additional credit contingent contractual obligations as of September 30, 2013: | |||||||||||||||||
Collateral Provisions | FES | AE Supply | Utilities | Total | |||||||||||||
(In millions) | |||||||||||||||||
Split Rating (One rating agency's rating below investment grade) | $ | 440 | $ | 6 | $ | 55 | $ | 501 | |||||||||
BB+/Ba1 Credit Ratings | $ | 484 | $ | 6 | $ | 55 | $ | 545 | |||||||||
Full impact of credit contingent contractual obligations | $ | 755 | $ | 58 | $ | 90 | $ | 903 | |||||||||
Supplemental_Guarantor_Informa1
Supplemental Guarantor Information (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Supplemental Guarantor Information [Abstract] | ' | ||||||||||||||||||||
Condensed Consolidating Statements of Income and Comprehensive Income | ' | ||||||||||||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 1,654 | $ | 528 | $ | 440 | $ | (943 | ) | $ | 1,679 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 249 | 55 | — | 304 | ||||||||||||||||
Purchased power from affiliates | 1,009 | — | 65 | (942 | ) | 132 | |||||||||||||||
Purchased power from non-affiliates | 720 | 4 | — | — | 724 | ||||||||||||||||
Other operating expenses | 147 | 65 | 114 | 13 | 339 | ||||||||||||||||
Provision for depreciation | 1 | 33 | 46 | — | 80 | ||||||||||||||||
General taxes | 21 | 9 | 5 | — | 35 | ||||||||||||||||
Total operating expenses | 1,898 | 360 | 285 | (929 | ) | 1,614 | |||||||||||||||
OPERATING INCOME (LOSS) | (244 | ) | 168 | 155 | (14 | ) | 65 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Loss on debt redemptions | — | — | — | — | — | ||||||||||||||||
Investment income (loss) | 2 | — | (1 | ) | (4 | ) | (3 | ) | |||||||||||||
Miscellaneous income, including net income from equity investees | 180 | 19 | — | (178 | ) | 21 | |||||||||||||||
Interest expense — affiliates | (3 | ) | (2 | ) | (1 | ) | 5 | (1 | ) | ||||||||||||
Interest expense — other | (13 | ) | (24 | ) | (13 | ) | 15 | (35 | ) | ||||||||||||
Capitalized interest | — | 1 | 8 | — | 9 | ||||||||||||||||
Total other income (expense) | 166 | (6 | ) | (7 | ) | (162 | ) | (9 | ) | ||||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (78 | ) | 162 | 148 | (176 | ) | 56 | ||||||||||||||
INCOME TAXES (BENEFITS) | (118 | ) | 111 | 28 | 2 | 23 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 40 | 51 | 120 | (178 | ) | 33 | |||||||||||||||
Discontinued operations (net of income taxes of $5) | — | 7 | — | — | 7 | ||||||||||||||||
NET INCOME | $ | 40 | $ | 58 | $ | 120 | $ | (178 | ) | $ | 40 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 40 | $ | 58 | $ | 120 | $ | (178 | ) | $ | 40 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (5 | ) | (5 | ) | — | 5 | (5 | ) | |||||||||||||
Amortized gain on derivative hedges | (1 | ) | — | — | — | (1 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 5 | — | 5 | (5 | ) | 5 | |||||||||||||||
Other comprehensive income (loss) | (1 | ) | (5 | ) | 5 | — | (1 | ) | |||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (1 | ) | (2 | ) | 3 | (1 | ) | (1 | ) | ||||||||||||
Other comprehensive income (loss), net of tax | — | (3 | ) | 2 | 1 | — | |||||||||||||||
COMPREHENSIVE INCOME | $ | 40 | $ | 55 | $ | 122 | $ | (177 | ) | $ | 40 | ||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 4,575 | $ | 1,612 | $ | 1,337 | $ | (2,869 | ) | $ | 4,655 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 782 | 154 | — | 936 | ||||||||||||||||
Purchased power from affiliates | 3,072 | — | 197 | (2,868 | ) | 401 | |||||||||||||||
Purchased power from non-affiliates | 1,749 | 6 | — | — | 1,755 | ||||||||||||||||
Other operating expenses | 484 | 208 | 376 | 37 | 1,105 | ||||||||||||||||
Provision for depreciation | 4 | 96 | 134 | (3 | ) | 231 | |||||||||||||||
General taxes | 60 | 28 | 18 | — | 106 | ||||||||||||||||
Total operating expenses | 5,369 | 1,120 | 879 | (2,834 | ) | 4,534 | |||||||||||||||
OPERATING INCOME (LOSS) | (794 | ) | 492 | 458 | (35 | ) | 121 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Loss on debt redemptions | (103 | ) | — | — | — | (103 | ) | ||||||||||||||
Investment income | 4 | — | 3 | (11 | ) | (4 | ) | ||||||||||||||
Miscellaneous income, including net income from equity investees | 543 | 23 | — | (537 | ) | 29 | |||||||||||||||
Interest expense — affiliates | (10 | ) | (4 | ) | (5 | ) | 12 | (7 | ) | ||||||||||||
Interest expense — other | (50 | ) | (79 | ) | (42 | ) | 45 | (126 | ) | ||||||||||||
Capitalized interest | 1 | 1 | 26 | — | 28 | ||||||||||||||||
Total other income (expense) | 385 | (59 | ) | (18 | ) | (491 | ) | (183 | ) | ||||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (409 | ) | 433 | 440 | (526 | ) | (62 | ) | |||||||||||||
INCOME TAXES (BENEFITS) | (380 | ) | 215 | 138 | 8 | (19 | ) | ||||||||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (29 | ) | 218 | 302 | (534 | ) | (43 | ) | |||||||||||||
Discontinued operations (net of income taxes of $8) | — | 14 | — | — | 14 | ||||||||||||||||
NET INCOME (LOSS) | $ | (29 | ) | $ | 232 | $ | 302 | $ | (534 | ) | $ | (29 | ) | ||||||||
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |||||||||||||||||||||
NET INCOME (LOSS) | $ | (29 | ) | $ | 232 | $ | 302 | $ | (534 | ) | $ | (29 | ) | ||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (16 | ) | (15 | ) | — | 15 | (16 | ) | |||||||||||||
Amortized gain on derivative hedges | (3 | ) | — | — | — | (3 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 2 | — | 2 | (2 | ) | 2 | |||||||||||||||
Other comprehensive income (loss) | (17 | ) | (15 | ) | 2 | 13 | (17 | ) | |||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | (7 | ) | (6 | ) | 1 | 5 | (7 | ) | |||||||||||||
Other comprehensive income (loss), net of tax | (10 | ) | (9 | ) | 1 | 8 | (10 | ) | |||||||||||||
COMPREHENSIVE INCOME (LOSS) | $ | (39 | ) | $ | 223 | $ | 303 | $ | (526 | ) | $ | (39 | ) | ||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 1,523 | $ | 610 | $ | 395 | $ | (978 | ) | $ | 1,550 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 248 | 55 | — | 303 | ||||||||||||||||
Purchased power from affiliates | 1,042 | — | 67 | (978 | ) | 131 | |||||||||||||||
Purchased power from non-affiliates | 499 | 3 | — | — | 502 | ||||||||||||||||
Other operating expenses | 130 | 78 | 122 | 12 | 342 | ||||||||||||||||
Provision for depreciation | 1 | 29 | 41 | (1 | ) | 70 | |||||||||||||||
General taxes | 20 | 10 | 5 | — | 35 | ||||||||||||||||
Total operating expenses | 1,692 | 368 | 290 | (967 | ) | 1,383 | |||||||||||||||
OPERATING INCOME (LOSS) | (169 | ) | 242 | 105 | (11 | ) | 167 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Investment income | 1 | 5 | 37 | (5 | ) | 38 | |||||||||||||||
Miscellaneous income, including net income from equity investees | 317 | — | — | (316 | ) | 1 | |||||||||||||||
Interest expense — affiliates | (5 | ) | (2 | ) | (1 | ) | 5 | (3 | ) | ||||||||||||
Interest expense — other | (25 | ) | (27 | ) | (15 | ) | 16 | (51 | ) | ||||||||||||
Capitalized interest | — | 1 | 8 | — | 9 | ||||||||||||||||
Total other income (expense) | 288 | (23 | ) | 29 | (300 | ) | (6 | ) | |||||||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 119 | 219 | 134 | (311 | ) | 161 | |||||||||||||||
INCOME TAXES (BENEFITS) | 18 | (14 | ) | 59 | 2 | 65 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 101 | 233 | 75 | (313 | ) | 96 | |||||||||||||||
Discontinued operations (net of income taxes of $3) | — | 5 | — | — | 5 | ||||||||||||||||
NET INCOME | $ | 101 | $ | 238 | $ | 75 | $ | (313 | ) | $ | 101 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 101 | $ | 238 | $ | 75 | $ | (313 | ) | $ | 101 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (5 | ) | (4 | ) | — | 4 | (5 | ) | |||||||||||||
Amortized gain on derivative hedges | (2 | ) | — | — | — | (2 | ) | ||||||||||||||
Change in unrealized gain on available for sale securities | (2 | ) | — | (1 | ) | 1 | (2 | ) | |||||||||||||
Other comprehensive loss | (9 | ) | (4 | ) | (1 | ) | 5 | (9 | ) | ||||||||||||
Income tax benefits on other comprehensive loss | (3 | ) | (2 | ) | — | 2 | (3 | ) | |||||||||||||
Other comprehensive loss, net of tax | (6 | ) | (2 | ) | (1 | ) | 3 | (6 | ) | ||||||||||||
COMPREHENSIVE INCOME | $ | 95 | $ | 236 | $ | 74 | $ | (310 | ) | $ | 95 | ||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
STATEMENTS OF INCOME | |||||||||||||||||||||
REVENUES | $ | 4,443 | $ | 1,777 | $ | 1,262 | $ | (2,971 | ) | $ | 4,511 | ||||||||||
OPERATING EXPENSES: | |||||||||||||||||||||
Fuel | — | 824 | 154 | — | 978 | ||||||||||||||||
Purchased power from affiliates | 3,163 | — | 189 | (2,971 | ) | 381 | |||||||||||||||
Purchased power from non-affiliates | 1,420 | 5 | — | — | 1,425 | ||||||||||||||||
Other operating expenses | 313 | 268 | 410 | 37 | 1,028 | ||||||||||||||||
Provision for depreciation | 3 | 87 | 114 | (4 | ) | 200 | |||||||||||||||
General taxes | 60 | 28 | 16 | — | 104 | ||||||||||||||||
Total operating expenses | 4,959 | 1,212 | 883 | (2,938 | ) | 4,116 | |||||||||||||||
OPERATING INCOME (LOSS) | (516 | ) | 565 | 379 | (33 | ) | 395 | ||||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||||
Investment income | 2 | 14 | 49 | (15 | ) | 50 | |||||||||||||||
Miscellaneous income, including net income from equity investees | 854 | 19 | — | (848 | ) | 25 | |||||||||||||||
Interest expense — affiliates | (14 | ) | (5 | ) | (3 | ) | 15 | (7 | ) | ||||||||||||
Interest expense — other | (72 | ) | (79 | ) | (36 | ) | 47 | (140 | ) | ||||||||||||
Capitalized interest | — | 3 | 24 | — | 27 | ||||||||||||||||
Total other income (expense) | 770 | (48 | ) | 34 | (801 | ) | (45 | ) | |||||||||||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 254 | 517 | 413 | (834 | ) | 350 | |||||||||||||||
INCOME TAXES (BENEFITS) | 32 | (25 | ) | 124 | 8 | 139 | |||||||||||||||
NET INCOME FROM CONTINUING OPERATIONS | 222 | 542 | 289 | (842 | ) | 211 | |||||||||||||||
Discontinued operations (net of income taxes of $6) | — | 11 | — | — | 11 | ||||||||||||||||
NET INCOME | $ | 222 | $ | 553 | $ | 289 | $ | (842 | ) | $ | 222 | ||||||||||
STATEMENTS OF COMPREHENSIVE INCOME | |||||||||||||||||||||
NET INCOME | $ | 222 | $ | 553 | $ | 289 | $ | (842 | ) | $ | 222 | ||||||||||
OTHER COMPREHENSIVE INCOME (LOSS): | |||||||||||||||||||||
Pensions and OPEB prior service costs | (2 | ) | (1 | ) | — | 1 | (2 | ) | |||||||||||||
Amortized gain on derivative hedges | (6 | ) | — | — | — | (6 | ) | ||||||||||||||
Change in unrealized gain on available-for-sale securities | 11 | — | 12 | (12 | ) | 11 | |||||||||||||||
Other comprehensive income (loss) | 3 | (1 | ) | 12 | (11 | ) | 3 | ||||||||||||||
Income taxes (benefits) on other comprehensive income (loss) | 1 | (1 | ) | 5 | (4 | ) | 1 | ||||||||||||||
Other comprehensive income, net of tax | 2 | — | 7 | (7 | ) | 2 | |||||||||||||||
COMPREHENSIVE INCOME | $ | 224 | $ | 553 | $ | 296 | $ | (849 | ) | $ | 224 | ||||||||||
Condensed Consolidating Balance Sheets | ' | ||||||||||||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
As of September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
CURRENT ASSETS: | |||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||
Receivables- | |||||||||||||||||||||
Customers | 524 | — | — | — | 524 | ||||||||||||||||
Affiliated companies | 420 | 445 | 285 | (631 | ) | 519 | |||||||||||||||
Other | 76 | 22 | 25 | — | 123 | ||||||||||||||||
Notes receivable from affiliated companies | 337 | 163 | 764 | (1,010 | ) | 254 | |||||||||||||||
Materials and supplies | 64 | 161 | 214 | — | 439 | ||||||||||||||||
Derivatives | 139 | — | — | — | 139 | ||||||||||||||||
Prepayments and other | 61 | 37 | 6 | 1 | 105 | ||||||||||||||||
1,621 | 830 | 1,294 | (1,640 | ) | 2,105 | ||||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||||||||||||||||
In service | 104 | 6,068 | 6,719 | (383 | ) | 12,508 | |||||||||||||||
Less — Accumulated provision for depreciation | 26 | 1,928 | 2,882 | (187 | ) | 4,649 | |||||||||||||||
78 | 4,140 | 3,837 | (196 | ) | 7,859 | ||||||||||||||||
Construction work in progress | 21 | 115 | 980 | — | 1,116 | ||||||||||||||||
99 | 4,255 | 4,817 | (196 | ) | 8,975 | ||||||||||||||||
INVESTMENTS: | |||||||||||||||||||||
Nuclear plant decommissioning trusts | — | — | 1,270 | — | 1,270 | ||||||||||||||||
Investment in affiliated companies | 5,503 | — | — | (5,503 | ) | — | |||||||||||||||
Other | 1 | 10 | — | — | 11 | ||||||||||||||||
5,504 | 10 | 1,270 | (5,503 | ) | 1,281 | ||||||||||||||||
ASSETS HELD FOR SALE (NOTE 16) | — | 121 | — | — | 121 | ||||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | |||||||||||||||||||||
Accumulated deferred income tax benefits | 16 | 169 | — | (185 | ) | — | |||||||||||||||
Customer intangibles | 99 | — | — | — | 99 | ||||||||||||||||
Goodwill | 23 | — | — | — | 23 | ||||||||||||||||
Property taxes | — | 14 | 22 | — | 36 | ||||||||||||||||
Unamortized sale and leaseback costs | — | — | — | 161 | 161 | ||||||||||||||||
Derivatives | 65 | — | — | — | 65 | ||||||||||||||||
Other | 174 | 242 | 14 | (162 | ) | 268 | |||||||||||||||
377 | 425 | 36 | (186 | ) | 652 | ||||||||||||||||
$ | 7,601 | $ | 5,641 | $ | 7,417 | $ | (7,525 | ) | $ | 13,134 | |||||||||||
LIABILITIES AND CAPITALIZATION | |||||||||||||||||||||
CURRENT LIABILITIES: | |||||||||||||||||||||
Currently payable long-term debt | $ | 1 | $ | 366 | $ | 514 | $ | (22 | ) | $ | 859 | ||||||||||
Short-term borrowings- | |||||||||||||||||||||
Affiliated companies | 696 | 314 | — | (1,010 | ) | — | |||||||||||||||
Other | — | 4 | — | — | 4 | ||||||||||||||||
Accounts payable- | |||||||||||||||||||||
Affiliated companies | 643 | 386 | 378 | (631 | ) | 776 | |||||||||||||||
Other | 88 | 125 | — | — | 213 | ||||||||||||||||
Accrued taxes | 7 | 17 | 37 | (19 | ) | 42 | |||||||||||||||
Derivatives | 103 | — | — | — | 103 | ||||||||||||||||
Other | 46 | 72 | 22 | 36 | 176 | ||||||||||||||||
1,584 | 1,284 | 951 | (1,646 | ) | 2,173 | ||||||||||||||||
CAPITALIZATION: | |||||||||||||||||||||
Total equity | 5,229 | 2,010 | 3,469 | (5,479 | ) | 5,229 | |||||||||||||||
Long-term debt and other long-term obligations | 712 | 1,873 | 789 | (1,196 | ) | 2,178 | |||||||||||||||
5,941 | 3,883 | 4,258 | (6,675 | ) | 7,407 | ||||||||||||||||
NONCURRENT LIABILITIES: | |||||||||||||||||||||
Deferred gain on sale and leaseback transaction | — | — | — | 866 | 866 | ||||||||||||||||
Accumulated deferred income taxes | — | — | 770 | (71 | ) | 699 | |||||||||||||||
Asset retirement obligations | — | 176 | 983 | — | 1,159 | ||||||||||||||||
Retirement benefits | 27 | 228 | — | — | 255 | ||||||||||||||||
Derivatives | 22 | — | — | — | 22 | ||||||||||||||||
Other | 27 | 70 | 455 | 1 | 553 | ||||||||||||||||
76 | 474 | 2,208 | 796 | 3,554 | |||||||||||||||||
$ | 7,601 | $ | 5,641 | $ | 7,417 | $ | (7,525 | ) | $ | 13,134 | |||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING BALANCE SHEETS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
As of December 31, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
ASSETS | |||||||||||||||||||||
CURRENT ASSETS: | |||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||||
Receivables- | |||||||||||||||||||||
Customers | 483 | — | — | — | 483 | ||||||||||||||||
Affiliated companies | 232 | 417 | 478 | (748 | ) | 379 | |||||||||||||||
Other | 56 | 19 | 16 | — | 91 | ||||||||||||||||
Notes receivable from affiliated companies | 366 | 7 | 607 | (704 | ) | 276 | |||||||||||||||
Materials and supplies | 66 | 231 | 208 | — | 505 | ||||||||||||||||
Derivatives | 158 | — | — | — | 158 | ||||||||||||||||
Prepayments and other | 38 | 39 | 10 | — | 87 | ||||||||||||||||
1,399 | 716 | 1,319 | (1,452 | ) | 1,982 | ||||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | |||||||||||||||||||||
In service | 91 | 5,899 | 6,391 | (384 | ) | 11,997 | |||||||||||||||
Less — Accumulated provision for depreciation | 32 | 1,915 | 2,646 | (185 | ) | 4,408 | |||||||||||||||
59 | 3,984 | 3,745 | (199 | ) | 7,589 | ||||||||||||||||
Construction work in progress | 34 | 230 | 877 | — | 1,141 | ||||||||||||||||
93 | 4,214 | 4,622 | (199 | ) | 8,730 | ||||||||||||||||
INVESTMENTS: | |||||||||||||||||||||
Nuclear plant decommissioning trusts | — | — | 1,283 | — | 1,283 | ||||||||||||||||
Investment in affiliated companies | 4,972 | — | — | (4,972 | ) | — | |||||||||||||||
Other | — | 12 | — | — | 12 | ||||||||||||||||
4,972 | 12 | 1,283 | (4,972 | ) | 1,295 | ||||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | |||||||||||||||||||||
Accumulated deferred income tax benefits | — | 313 | — | (313 | ) | — | |||||||||||||||
Customer intangibles | 110 | — | — | — | 110 | ||||||||||||||||
Goodwill | 24 | — | — | — | 24 | ||||||||||||||||
Property taxes | — | 14 | 22 | — | 36 | ||||||||||||||||
Unamortized sale and leaseback costs | — | — | — | 119 | 119 | ||||||||||||||||
Derivatives | 99 | — | — | — | 99 | ||||||||||||||||
Other | 160 | 194 | 5 | (106 | ) | 253 | |||||||||||||||
393 | 521 | 27 | (300 | ) | 641 | ||||||||||||||||
$ | 6,857 | $ | 5,463 | $ | 7,251 | $ | (6,923 | ) | $ | 12,648 | |||||||||||
LIABILITIES AND CAPITALIZATION | |||||||||||||||||||||
CURRENT LIABILITIES: | |||||||||||||||||||||
Currently payable long-term debt | $ | 1 | $ | 586 | $ | 537 | $ | (22 | ) | $ | 1,102 | ||||||||||
Short-term borrowings- | |||||||||||||||||||||
Affiliated companies | 358 | 346 | — | (704 | ) | — | |||||||||||||||
Other | — | 4 | — | — | 4 | ||||||||||||||||
Accounts payable- | |||||||||||||||||||||
Affiliated companies | 748 | 143 | 583 | (748 | ) | 726 | |||||||||||||||
Other | 63 | 96 | — | — | 159 | ||||||||||||||||
Accrued taxes | 126 | 25 | 20 | — | 171 | ||||||||||||||||
Derivatives | 124 | — | — | — | 124 | ||||||||||||||||
Other | 71 | 148 | 15 | 46 | 280 | ||||||||||||||||
1,491 | 1,348 | 1,155 | (1,428 | ) | 2,566 | ||||||||||||||||
CAPITALIZATION: | |||||||||||||||||||||
Total equity | 3,763 | 1,787 | 3,165 | (4,952 | ) | 3,763 | |||||||||||||||
Long-term debt and other long-term obligations | 1,482 | 2,009 | 834 | (1,207 | ) | 3,118 | |||||||||||||||
5,245 | 3,796 | 3,999 | (6,159 | ) | 6,881 | ||||||||||||||||
NONCURRENT LIABILITIES: | |||||||||||||||||||||
Deferred gain on sale and leaseback transaction | — | — | — | 892 | 892 | ||||||||||||||||
Accumulated deferred income taxes | 28 | — | 714 | (227 | ) | 515 | |||||||||||||||
Asset retirement obligations | — | 29 | 936 | — | 965 | ||||||||||||||||
Retirement benefits | 26 | 215 | — | — | 241 | ||||||||||||||||
Derivatives | 37 | — | — | — | 37 | ||||||||||||||||
Other | 30 | 75 | 447 | (1 | ) | 551 | |||||||||||||||
121 | 319 | 2,097 | 664 | 3,201 | |||||||||||||||||
$ | 6,857 | $ | 5,463 | $ | 7,251 | $ | (6,923 | ) | $ | 12,648 | |||||||||||
Condensed Consolidating Statements of Cash Flows | ' | ||||||||||||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (1,018 | ) | $ | 712 | $ | 705 | $ | (10 | ) | $ | 389 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||||
New Financing- | |||||||||||||||||||||
Short-term borrowings, net | 338 | — | — | (338 | ) | — | |||||||||||||||
Equity contribution from parent | 1,500 | — | — | — | 1,500 | ||||||||||||||||
Redemptions and Repayments- | |||||||||||||||||||||
Long-term debt | (769 | ) | (352 | ) | (68 | ) | 10 | (1,179 | ) | ||||||||||||
Short-term borrowings, net | — | (32 | ) | — | 32 | — | |||||||||||||||
Tender premiums | (67 | ) | — | — | — | (67 | ) | ||||||||||||||
Other | (3 | ) | (4 | ) | — | — | (7 | ) | |||||||||||||
Net cash provided from (used for) financing activities | 999 | (388 | ) | (68 | ) | (296 | ) | 247 | |||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||||
Property additions | (9 | ) | (192 | ) | (276 | ) | — | (477 | ) | ||||||||||||
Nuclear fuel | — | — | (159 | ) | — | (159 | ) | ||||||||||||||
Proceeds from asset sales | — | 21 | — | — | 21 | ||||||||||||||||
Sales of investment securities held in trusts | — | — | 650 | — | 650 | ||||||||||||||||
Purchases of investment securities held in trusts | — | — | (694 | ) | — | (694 | ) | ||||||||||||||
Loans to affiliated companies, net | 28 | (156 | ) | (156 | ) | 306 | 22 | ||||||||||||||
Other | — | 2 | (2 | ) | — | — | |||||||||||||||
Net cash provided from (used for) investing activities | 19 | (325 | ) | (637 | ) | 306 | (637 | ) | |||||||||||||
Net change in cash and cash equivalents | — | (1 | ) | — | — | (1 | ) | ||||||||||||||
Cash and cash equivalents at beginning of period | — | 3 | — | — | 3 | ||||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 2 | $ | — | $ | — | $ | 2 | |||||||||||
FIRSTENERGY SOLUTIONS CORP. | |||||||||||||||||||||
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |||||||||||||||||||||
(Unaudited) | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | FES | FG | NG | Eliminations | Consolidated | ||||||||||||||||
(In millions) | |||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (971 | ) | $ | 683 | $ | 799 | $ | (10 | ) | $ | 501 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||||
New Financing- | |||||||||||||||||||||
Long-term debt | — | 317 | 243 | — | 560 | ||||||||||||||||
Short-term borrowings, net | 982 | 49 | — | (1,028 | ) | 3 | |||||||||||||||
Redemptions and Repayments- | |||||||||||||||||||||
Long-term debt | — | (169 | ) | (87 | ) | 10 | (246 | ) | |||||||||||||
Short-term borrowings, net | — | — | (32 | ) | 32 | — | |||||||||||||||
Other | (1 | ) | (6 | ) | (2 | ) | — | (9 | ) | ||||||||||||
Net cash provided from financing activities | 981 | 191 | 122 | (986 | ) | 308 | |||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||||
Property additions | (10 | ) | (175 | ) | (350 | ) | — | (535 | ) | ||||||||||||
Nuclear fuel | — | — | (207 | ) | — | (207 | ) | ||||||||||||||
Proceeds from asset sales | — | 17 | — | — | 17 | ||||||||||||||||
Sales of investment securities held in trusts | — | — | 1,167 | — | 1,167 | ||||||||||||||||
Purchases of investment securities held in trusts | — | — | (1,194 | ) | — | (1,194 | ) | ||||||||||||||
Loans to affiliated companies, net | 1 | (715 | ) | (337 | ) | 996 | (55 | ) | |||||||||||||
Other | (1 | ) | (5 | ) | — | — | (6 | ) | |||||||||||||
Net cash used for investing activities | (10 | ) | (878 | ) | (921 | ) | 996 | (813 | ) | ||||||||||||
Net change in cash and cash equivalents | — | (4 | ) | — | — | (4 | ) | ||||||||||||||
Cash and cash equivalents at beginning of period | — | 7 | — | — | 7 | ||||||||||||||||
Cash and cash equivalents at end of period | $ | — | $ | 3 | $ | — | $ | — | $ | 3 | |||||||||||
Segment_Information_Tables
Segment Information (Tables) | 9 Months Ended | ||||||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||||||
Segment Reporting [Abstract] | ' | ||||||||||||||||||||||||
Segment Financial Information | ' | ||||||||||||||||||||||||
Segment Financial Information | |||||||||||||||||||||||||
Three Months Ended | Regulated Distribution | Regulated Transmission | Competitive Energy Services | Other/Corporate | Reconciling Adjustments | Consolidated | |||||||||||||||||||
(In millions) | |||||||||||||||||||||||||
September 30, 2013 | |||||||||||||||||||||||||
External revenues | $ | 2,340 | $ | 190 | $ | 1,573 | $ | (31 | ) | $ | (36 | ) | $ | 4,036 | |||||||||||
Internal revenues | — | — | 196 | — | (196 | ) | — | ||||||||||||||||||
Total revenues | 2,340 | 190 | 1,769 | (31 | ) | (232 | ) | 4,036 | |||||||||||||||||
Depreciation, amortization and deferrals | 460 | 31 | 125 | 12 | — | 628 | |||||||||||||||||||
Investment income (loss) | 14 | — | (5 | ) | 3 | (7 | ) | 5 | |||||||||||||||||
Interest expense | 134 | 23 | 53 | 47 | — | 257 | |||||||||||||||||||
Income taxes (benefits) | 50 | 32 | 47 | (44 | ) | (8 | ) | 77 | |||||||||||||||||
Income from continuing operations | 85 | 54 | 68 | — | 2 | 209 | |||||||||||||||||||
Discontinued operations, net of tax | — | — | 9 | — | — | 9 | |||||||||||||||||||
Net income (loss) | 85 | 54 | 77 | (10 | ) | 12 | 218 | ||||||||||||||||||
Total assets | 27,030 | 4,953 | 17,809 | 591 | — | 50,383 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 867 | — | — | 6,418 | |||||||||||||||||||
Property additions | 261 | 105 | 162 | 20 | — | 548 | |||||||||||||||||||
September 30, 2012 | |||||||||||||||||||||||||
External revenues | $ | 2,483 | $ | 187 | $ | 1,462 | $ | (31 | ) | $ | (49 | ) | $ | 4,052 | |||||||||||
Internal revenues | — | — | 209 | — | (209 | ) | — | ||||||||||||||||||
Total revenues | 2,483 | 187 | 1,671 | (31 | ) | (258 | ) | 4,052 | |||||||||||||||||
Depreciation, amortization and deferrals | 193 | 28 | 102 | 9 | 1 | 333 | |||||||||||||||||||
Investment income | 20 | — | 36 | (2 | ) | (15 | ) | 39 | |||||||||||||||||
Interest expense | 136 | 24 | 73 | (3 | ) | — | 230 | ||||||||||||||||||
Income taxes (benefits) | 168 | 35 | 74 | (8 | ) | 38 | 307 | ||||||||||||||||||
Income from continuing operations | 286 | 59 | 126 | — | (49 | ) | 422 | ||||||||||||||||||
Discontinued operations, net of tax | — | — | 3 | — | — | 3 | |||||||||||||||||||
Net income (loss) | 286 | 59 | 129 | (13 | ) | (36 | ) | 425 | |||||||||||||||||
Total assets | 26,122 | 4,519 | 16,846 | 1,251 | — | 48,738 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 893 | — | — | 6,444 | |||||||||||||||||||
Property additions | 308 | 47 | 412 | 8 | — | 775 | |||||||||||||||||||
Nine Months Ended | |||||||||||||||||||||||||
September 30, 2013 | |||||||||||||||||||||||||
External revenues | $ | 6,593 | $ | 546 | $ | 4,350 | $ | (89 | ) | $ | (130 | ) | $ | 11,270 | |||||||||||
Internal revenues | — | — | 588 | — | (588 | ) | — | ||||||||||||||||||
Total revenues | 6,593 | 546 | 4,938 | (89 | ) | (718 | ) | 11,270 | |||||||||||||||||
Depreciation, amortization and deferrals | 882 | 91 | 347 | 32 | — | 1,352 | |||||||||||||||||||
Investment income (loss) | 41 | — | (6 | ) | 6 | (33 | ) | 8 | |||||||||||||||||
Interest expense | 404 | 68 | 187 | 112 | — | 771 | |||||||||||||||||||
Income taxes (benefits) | 284 | 93 | (189 | ) | (55 | ) | (4 | ) | 129 | ||||||||||||||||
Income (loss) from continuing operations | 474 | 156 | (317 | ) | — | (80 | ) | 233 | |||||||||||||||||
Discontinued operations, net of tax | — | — | 17 | — | — | 17 | |||||||||||||||||||
Net income (loss) | 474 | 156 | (300 | ) | (92 | ) | 12 | 250 | |||||||||||||||||
Total assets | 27,030 | 4,953 | 17,809 | 591 | — | 50,383 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 867 | — | — | 6,418 | |||||||||||||||||||
Property additions | 980 | 291 | 630 | 59 | — | 1,960 | |||||||||||||||||||
September 30, 2012 | |||||||||||||||||||||||||
External revenues | $ | 6,976 | $ | 557 | $ | 4,465 | $ | (78 | ) | $ | (142 | ) | $ | 11,778 | |||||||||||
Internal revenues | — | — | 686 | — | (684 | ) | 2 | ||||||||||||||||||
Total revenues | 6,976 | 557 | 5,151 | (78 | ) | (826 | ) | 11,780 | |||||||||||||||||
Depreciation, amortization and deferrals | 618 | 86 | 303 | 25 | — | 1,032 | |||||||||||||||||||
Investment income | 62 | 1 | 48 | (1 | ) | (47 | ) | 63 | |||||||||||||||||
Interest expense | 405 | 70 | 209 | 66 | — | 750 | |||||||||||||||||||
Income taxes | 355 | 101 | 165 | (49 | ) | 78 | 650 | ||||||||||||||||||
Income from continuing operations | 603 | 171 | 284 | — | (150 | ) | 908 | ||||||||||||||||||
Discontinued operations, net of tax | — | — | 11 | — | — | 11 | |||||||||||||||||||
Net income (loss) | 603 | 171 | 295 | (82 | ) | (68 | ) | 919 | |||||||||||||||||
Total assets | 26,122 | 4,519 | 16,846 | 1,251 | — | 48,738 | |||||||||||||||||||
Total goodwill | 5,025 | 526 | 893 | — | — | 6,444 | |||||||||||||||||||
Property additions | 751 | 169 | 715 | 51 | — | 1,686 | |||||||||||||||||||
Organization_and_Basis_of_Pres2
Organization and Basis of Presentation (Details) (FES, USD $) | 3 Months Ended | 9 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 |
FES | ' | ' | ' |
Organization, Basis of Presentation and Significant Accounting Policies [Line Items] | ' | ' | ' |
Equity contribution from parent | $1,500 | $1,500 | $0 |
Goodwill_Details
Goodwill (Details) (USD $) | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Oct. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | ||
Subsequent Event | Regulated Distribution | Regulated Distribution | Regulated Independent Transmission | Competitive Energy Services | Competitive Energy Services | Corporate and Other | |||||
Goodwill [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Goodwill, Other Changes | ' | ' | $67 | ' | ' | ' | ' | ' | ' | ||
Goodwill [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Goodwill | 6,447 | 6,444 | ' | 5,025 | 5,025 | 526 | 896 | 893 | 0 | ||
Classification to Assets Held for Sale | -29 | [1] | ' | ' | 0 | ' | 0 | -29 | [1] | ' | 0 |
Goodwill | $6,418 | $6,444 | ' | $5,025 | $5,025 | $526 | $867 | $893 | $0 | ||
[1] | See Note 16, Discontinued Operations and Assets Held for Sale. |
Impairment_of_Longlived_Assets2
Impairment of Long-lived Assets (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Oct. 09, 2013 | Jun. 30, 2013 | Sep. 30, 2013 | Jul. 08, 2013 | Jul. 08, 2013 |
employees | FES | Subsequent Event | Excessive Inventories | Long-Lived Assets to be Abandoned, Total | Hatfield's Ferry, Units 1-3 | Mitchell, Units 2-3 | ||||
AE Supply | employees | MW | MW | |||||||
Schedule of Generating Plant Retirements [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Plant Capacity | ' | ' | ' | ' | ' | ' | ' | ' | 1,710 | 370 |
Asset Impairment Charges | ' | $473 | $473 | $0 | ' | ' | $13 | ' | ' | ' |
Restructuring and Related Cost, Expected Number of Positions Eliminated (in employees) | 250 | ' | ' | ' | ' | ' | ' | 240 | ' | ' |
Severance Costs | 2 | ' | ' | 14 | 10 | ' | ' | 7 | ' | ' |
Face amount of debt redeemed | ' | ' | ' | ' | ' | $235 | ' | ' | ' | ' |
Earnings_Per_Share_of_Common_S2
Earnings Per Share of Common Stock (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, except Per Share data, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ' | ' | ' | ' | ||||
Income from continuing operations | $209 | $422 | $233 | $908 | ||||
Less: Income attributable to noncontrolling interest | 0 | 0 | 0 | 1 | ||||
Income (Loss) from Continuing Operations Attributable to Parent | 209 | 422 | 233 | 907 | ||||
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 | ||||
EARNINGS AVAILABLE TO FIRSTENERGY CORP. | $218 | $425 | $250 | $918 | ||||
Weighted average number of basic shares outstanding | 418 | 417 | 418 | 418 | ||||
Assumed exercise of dilutive stock options and awards | 1 | [1] | 2 | [1] | 1 | [1] | 1 | [1] |
Weighted average number of diluted shares outstanding | 419 | 419 | 419 | 419 | ||||
Basic earnings per share: | ' | ' | ' | ' | ||||
Income from continuing operations, in dollars per share | $0.50 | $1.01 | $0.56 | $2.17 | ||||
Discontinued operations (Note 16), in dollars per share | $0.02 | $0.01 | $0.04 | $0.03 | ||||
Basic - Earnings Available to FirstEnergy Corp., in dollars per share | $0.52 | $1.02 | $0.60 | $2.20 | ||||
Diluted earnings per share: | ' | ' | ' | ' | ||||
Income from continuing operations, in dollars per share | $0.50 | $1 | $0.56 | $2.16 | ||||
Discontinued operations (Note 16), in dollars per share | $0.02 | $0.01 | $0.04 | $0.03 | ||||
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share | $0.52 | $1.01 | $0.60 | $2.19 | ||||
Shares excluded from the calculation of diluted shares outstanding, in shares | 2 | ' | 2 | ' | ||||
Maximum | ' | ' | ' | ' | ||||
Diluted earnings per share: | ' | ' | ' | ' | ||||
Shares excluded from the calculation of diluted shares outstanding, in shares | ' | 1 | ' | 1 | ||||
[1] | For the three months and nine ended SeptemberB 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended SeptemberB 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. |
Pension_and_Other_Postemployme2
Pension and Other Postemployment Benefits (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Pensions | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Service costs | $49 | $40 | $147 | $120 |
Interest costs | 93 | 97 | 279 | 291 |
Expected return on plan assets | -125 | -121 | -375 | -363 |
Amortization of prior service cost (credit) | 3 | 3 | 9 | 9 |
Net periodic cost (credits) | 20 | 19 | 60 | 57 |
OPEB | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Service costs | 3 | 3 | 9 | 9 |
Interest costs | 9 | 12 | 27 | 36 |
Expected return on plan assets | -8 | -9 | -24 | -27 |
Amortization of prior service cost (credit) | -50 | -50 | -157 | -152 |
Net periodic cost (credits) | -46 | -44 | -145 | -134 |
FirstEnergy | Pensions | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Net periodic cost (credits) | 16 | 14 | 41 | 41 |
FirstEnergy | OPEB | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Net periodic cost (credits) | -31 | -30 | -95 | -92 |
FES | Pensions | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Net periodic cost (credits) | 5 | 5 | 13 | 13 |
FES | OPEB | ' | ' | ' | ' |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ' | ' | ' | ' |
Net periodic cost (credits) | ($4) | ($4) | ($12) | ($12) |
Accumulated_Other_Comprehensiv2
Accumulated Other Comprehensive Income (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | $323 | $389 | $385 | $426 |
Other comprehensive income (loss) before reclassifications | 5 | 25 | 19 | 44 |
Amounts reclassified from AOCI | -29 | -47 | -105 | -103 |
Net other comprehensive income (loss) | -24 | -22 | -86 | -59 |
AOCI Ending Balance | 299 | 367 | 299 | 367 |
FES | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 62 | 84 | 72 | 76 |
Other comprehensive income (loss) before reclassifications | 4 | 23 | 17 | 45 |
Amounts reclassified from AOCI | -4 | -29 | -27 | -43 |
Net other comprehensive income (loss) | 0 | -6 | -10 | 2 |
AOCI Ending Balance | 62 | 78 | 62 | 78 |
Gains & Losses on Cash Flow Hedges | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | -37 | -39 | -38 | -39 |
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 | 1 |
Amounts reclassified from AOCI | 1 | 0 | 2 | -1 |
Net other comprehensive income (loss) | 1 | 0 | 2 | 0 |
AOCI Ending Balance | -36 | -39 | -36 | -39 |
Gains & Losses on Cash Flow Hedges | FES | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 1 | 6 | 3 | 8 |
Other comprehensive income (loss) before reclassifications | 0 | -1 | 0 | 0 |
Amounts reclassified from AOCI | 0 | -1 | -2 | -4 |
Net other comprehensive income (loss) | 0 | -2 | -2 | -4 |
AOCI Ending Balance | 1 | 4 | 1 | 4 |
Unrealized Gains on AFS Securities | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 13 | 27 | 15 | 19 |
Other comprehensive income (loss) before reclassifications | 5 | 25 | 19 | 38 |
Amounts reclassified from AOCI | -1 | -25 | -17 | -30 |
Net other comprehensive income (loss) | 4 | 0 | 2 | 8 |
AOCI Ending Balance | 17 | 27 | 17 | 27 |
Unrealized Gains on AFS Securities | FES | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 12 | 25 | 13 | 16 |
Other comprehensive income (loss) before reclassifications | 4 | 24 | 17 | 37 |
Amounts reclassified from AOCI | -1 | -25 | -15 | -29 |
Net other comprehensive income (loss) | 3 | -1 | 2 | 8 |
AOCI Ending Balance | 15 | 24 | 15 | 24 |
Defined Benefit Pension & OPEB Plans | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 347 | 401 | 408 | 446 |
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 | 5 |
Amounts reclassified from AOCI | -29 | -22 | -90 | -72 |
Net other comprehensive income (loss) | -29 | -22 | -90 | -67 |
AOCI Ending Balance | 318 | 379 | 318 | 379 |
Defined Benefit Pension & OPEB Plans | FES | ' | ' | ' | ' |
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | ' | ' | ' | ' |
AOCI Beginning Balance | 49 | 53 | 56 | 52 |
Other comprehensive income (loss) before reclassifications | 0 | 0 | 0 | 8 |
Amounts reclassified from AOCI | -3 | -3 | -10 | -10 |
Net other comprehensive income (loss) | -3 | -3 | -10 | -2 |
AOCI Ending Balance | $46 | $50 | $46 | $50 |
Accumulated_Other_Comprehensiv3
Accumulated Other Comprehensive Income (Details 1) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Other operating expenses | $877 | $861 | $2,645 | $2,597 | ||||
Interest expense | 257 | 230 | 771 | 750 | ||||
Investment income (loss) | -5 | -39 | -8 | -63 | ||||
Total before taxes | -286 | -729 | -362 | -1,558 | ||||
Income taxes (benefits) | 77 | 307 | 129 | 650 | ||||
Net of tax | -218 | -425 | -250 | -919 | ||||
FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Other operating expenses | 339 | 342 | 1,105 | 1,028 | ||||
Investment income (loss) | 3 | -38 | 4 | -50 | ||||
Total before taxes | -56 | -161 | 62 | -350 | ||||
Income taxes (benefits) | 23 | 65 | -19 | 139 | ||||
Net of tax | -40 | -101 | 29 | -222 | ||||
Reclassifications from AOCI | Gains & losses on cash flow hedges | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Total before taxes | 2 | [1] | 0 | [1] | 4 | [1] | -1 | [1] |
Income taxes (benefits) | -1 | [1] | 0 | [1] | -2 | [1] | 0 | [1] |
Net of tax | 1 | [1] | 0 | [1] | 2 | [1] | -1 | [1] |
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Total before taxes | ' | ' | -3 | [1] | -6 | [1] | ||
Income taxes (benefits) | 1 | [1] | 1 | [1] | 1 | [1] | 2 | [1] |
Net of tax | 0 | [1] | -1 | [1] | -2 | [1] | -4 | [1] |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Other operating expenses | -1 | [1] | -2 | [1] | -5 | [1] | -7 | [1] |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Other operating expenses | -1 | [1] | -2 | [1] | -5 | [1] | -6 | [1] |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest expense | 3 | [1] | 2 | [1] | 9 | [1] | 6 | [1] |
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Interest expense | ' | ' | 2 | [1] | 0 | [1] | ||
Reclassifications from AOCI | Unrealized gains on AFS securities | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Investment income (loss) | -2 | [1] | -40 | [1] | -27 | [1] | -48 | [1] |
Income taxes (benefits) | 1 | [1] | 15 | [1] | 10 | [1] | 18 | [1] |
Net of tax | -1 | [1] | -25 | [1] | -17 | [1] | -30 | [1] |
Reclassifications from AOCI | Unrealized gains on AFS securities | FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Investment income (loss) | -2 | [1] | -40 | [1] | -24 | [1] | -46 | [1] |
Income taxes (benefits) | 1 | [1] | 15 | [1] | 9 | [1] | 17 | [1] |
Net of tax | -1 | [1] | -25 | [1] | -15 | [1] | -29 | [1] |
Reclassifications from AOCI | Defined benefit pension and OPEB plans | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Prior-service costs | -47 | [1],[2] | -47 | [1],[2] | -148 | [1],[2] | -143 | [1],[2] |
Income taxes (benefits) | 18 | [1] | 25 | [1] | 58 | [1] | 71 | [1] |
Net of tax | -29 | [1] | -22 | [1] | -90 | [1] | -72 | [1] |
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES | ' | ' | ' | ' | ||||
Reclassification Out of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ||||
Prior-service costs | -5 | [1],[2] | -5 | [1],[2] | -16 | [1],[2] | -15 | [1],[2] |
Income taxes (benefits) | 2 | [1] | 2 | [1] | 6 | [1] | 5 | [1] |
Net of tax | ($3) | [1] | ($3) | [1] | ($10) | [1] | ($10) | [1] |
[1] | Parenthesis represent credits from AOCI to the Consolidated Statements of Income. | |||||||
[2] | These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | ||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Jul. 08, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Jul. 09, 2013 | Jul. 09, 2013 |
FirstEnergy and AE Supply | FES | FES | FES | FES | FirstEnergy and FES | Operating Loss Carryforward [Member] | Operating Loss Carryforward [Member] | Federal | State and local | State and local | State and local | ||||||
plant | FirstEnergy and AE Supply | FES | PENNSYLVANIA | PENNSYLVANIA | |||||||||||||
After December 31, 2013 | After December 31, 2014 | ||||||||||||||||
Income Taxes (Textuals) [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase in unrecognized tax benefits | $5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unrecognized tax benefits | 4 | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrued interest | 10 | ' | 10 | ' | 9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Deferred tax assets, current | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 319 | ' | ' | ' |
Deferred tax assets, long-term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 466 | 389 | ' | ' |
Deferred tax assets, portion not expected to be recognized in next fiscal year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 319 | ' | ' | ' |
Deferred tax asset, current, net operating loss carryforward | 290 | ' | 290 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Impairment of Long-lived Assets, Number of Plants to be Deactivated | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Valuation Allowance, Deferred Tax Asset, Change in Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20 | 4 | ' | ' | ' | ' |
Operating Loss Carryforward, Limitations on Use, Percent of Taxable Income | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25.00% | 30.00% |
Operating Loss Carryforward, Limitations on Use, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 5 |
Valuation Allowance, Deferred Tax Asset, Change in Amount, Next Fiscal Quarter | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Deferred Tax Liabilities, Decreases Resulting from Changes to State Apportionment Factors | 9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Deferred Tax Liabilities, Decreases Resulting from Changes in Assessment of Business Operations | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Effective tax rate | 26.90% | 42.10% | 35.60% | 41.70% | ' | ' | 41.10% | 40.50% | 30.60% | 39.70% | 37.00% | ' | ' | ' | ' | ' | ' |
Loss on debt redemptions | ($9) | $0 | $132 | $0 | ' | ' | $0 | $0 | $103 | $0 | ' | ' | ' | ' | ' | ' | ' |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | Sep. 30, 2013 | |
In Millions, unless otherwise specified | ||
FES | ' | |
Net exposure to loss based upon the casualty value provisions | ' | |
Maximum Exposure | $1,288 | |
Discounted Lease Payments, net | 1,079 | [1] |
Net Exposure | 209 | |
Other FE subsidiaries | ' | |
Net exposure to loss based upon the casualty value provisions | ' | |
Maximum Exposure | 762 | |
Discounted Lease Payments, net | 329 | [1] |
Net Exposure | $433 | |
[1] | The net present value of FirstEnergybs consolidated sale and leaseback operating lease commitments is $1.2 billion. |
Variable_Interest_Entities_Det1
Variable Interest Entities (Details Textuals) (USD $) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 1 Months Ended | ||||||||||||||||
Mar. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Aug. 31, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | |
entities | Power Purchase Agreements | OE | Other FE subsidiaries | Other FE subsidiaries | Other FE subsidiaries | Other FE subsidiaries | Other FE subsidiaries | Nuclear Generation Corp | FGCO | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Signal Peak | Path-WV | |||||
agreements | Power Purchase Agreements | Power Purchase Agreements | Power Purchase Agreements | Power Purchase Agreements | Beaver Valley Unit 2 | Bruce Mansfield Plant | Existing Taxable Bonds | Existing Taxable Bonds | Existing Taxable Bonds | Existing Taxable Bonds | Phase In Recovery Bonds | FEV | |||||||||||
Year 2013 | Year 2015 | Year 2020 | Global Holding | ||||||||||||||||||||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt Instrument, Face Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $410,000,000 | $225,000,000 | $150,000,000 | $35,000,000 | $445,000,000 | ' | ' |
Weighted average interest rate on debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.71% | ' | ' | ' | 2.48% | ' | ' |
Make-whole premiums paid on debt redemptions | ' | ' | ' | 181,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' |
Distributions to owners | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity interest by unaffiliated third party in PNBV | ' | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity interest by OES Ventures in PNBV | ' | ' | ' | ' | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Ownership interest | ' | ' | ' | ' | ' | ' | ' | 0.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33.33% | ' |
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% |
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | ' | ' | ' | ' | ' | 21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of contracts that may contain variable interest | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Purchased power | ' | 1,120,000,000 | 1,063,000,000 | 2,932,000,000 | 3,367,000,000 | ' | ' | ' | 48,000,000 | 65,000,000 | 139,000,000 | 184,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Purchase of lessor equity interests in sale and leaseback, value | 221,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 129,000,000 | 262,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments | ' | $1,200,000,000 | ' | $1,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair_Value_Measurements_Detail
Fair Value Measurements (Details) (Recurring, USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Assets | ' | ' | ||
Fair value, assets | $2,802 | $2,822 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -525 | -597 | ||
Net assets (liabilities) | 2,277 | [1] | 2,225 | [1] |
FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 1,461 | 1,447 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -125 | -160 | ||
Net assets (liabilities) | 1,336 | [2] | 1,287 | [2] |
Commodity contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -112 | -154 | ||
Commodity contracts | Derivative Liabilities | FES | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -112 | -154 | ||
FTRs | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -14 | -9 | ||
FTRs | Derivative Liabilities | FES | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -13 | -6 | ||
NUG contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -233 | [3] | -290 | [3] |
LCAPP Contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -166 | [3] | -144 | [3] |
Corporate debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 1,299 | 1,259 | ||
Corporate debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 742 | 703 | ||
Commodity contracts | Derivative Assets | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 201 | 252 | ||
Commodity contracts | Derivative Assets | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 201 | 252 | ||
FTRs | Derivative Assets | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 3 | 8 | ||
FTRs | Derivative Assets | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 2 | 6 | ||
NUG contracts | Derivative Assets | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 23 | [3] | 36 | [3] |
Equity securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 461 | [4] | 310 | [4] |
Equity securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 338 | [4] | 294 | [4] |
Foreign government debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 101 | 126 | ||
Foreign government debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 58 | 61 | ||
U.S. government debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 171 | 179 | ||
U.S. government debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 26 | 27 | ||
U.S. state debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 226 | 299 | ||
Other | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 317 | [5] | 353 | [5] |
Other | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 94 | [5] | 104 | [5] |
Level 1 | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 625 | 436 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -5 | -3 | ||
Net assets (liabilities) | 620 | [1] | 433 | [1] |
Level 1 | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 342 | 294 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -5 | -3 | ||
Net assets (liabilities) | 337 | [2] | 291 | [2] |
Level 1 | Commodity contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -5 | -3 | ||
Level 1 | Commodity contracts | Derivative Liabilities | FES | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -5 | -3 | ||
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 | [3] | 0 | [3] |
Level 1 | LCAPP Contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | 0 | [3] | 0 | [3] |
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 | 4 | 0 | ||
Level 1 | Commodity contracts | Derivative Assets | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 4 | 0 | ||
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 | [3] | 0 | [3] |
Level 1 | Equity securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 461 | [4] | 310 | [4] |
Level 1 | Equity securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 338 | [4] | 294 | [4] |
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 | Other | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 160 | [5] | 126 | [5] |
Level 1 | Other | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [5] | 0 | [5] |
Level 2 | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 2,151 | 2,342 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -107 | -151 | ||
Net assets (liabilities) | 2,044 | [1] | 2,191 | [1] |
Level 2 | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 1,117 | 1,147 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -107 | -151 | ||
Net assets (liabilities) | 1,010 | [2] | 996 | [2] |
Level 2 | Commodity contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -107 | -151 | ||
Level 2 | Commodity contracts | Derivative Liabilities | FES | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -107 | -151 | ||
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 | [3] | 0 | [3] |
Level 2 | LCAPP Contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | 0 | [3] | 0 | [3] |
Level 2 | Corporate debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 1,299 | 1,259 | ||
Level 2 | Corporate debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 742 | 703 | ||
Level 2 | Commodity contracts | Derivative Assets | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 197 | 252 | ||
Level 2 | Commodity contracts | Derivative Assets | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 197 | 252 | ||
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 | [3] | 0 | [3] |
Level 2 | Equity securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [4] | 0 | [4] |
Level 2 | Equity securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [4] | 0 | [4] |
Level 2 | Foreign government debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 101 | 126 | ||
Level 2 | Foreign government debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 58 | 61 | ||
Level 2 | U.S. government debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 171 | 179 | ||
Level 2 | U.S. government debt securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 26 | 27 | ||
Level 2 | U.S. state debt securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 226 | 299 | ||
Level 2 | Other | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 157 | [5] | 227 | [5] |
Level 2 | Other | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 94 | [5] | 104 | [5] |
Level 3 | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 26 | 44 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -413 | -443 | ||
Net assets (liabilities) | -387 | [1] | -399 | [1] |
Level 3 | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 2 | 6 | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -13 | -6 | ||
Net assets (liabilities) | -11 | [2] | 0 | [2] |
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 | -14 | -9 | ||
Level 3 | FTRs | Derivative Liabilities | FES | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -13 | -6 | ||
Level 3 | NUG contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -233 | [3] | -290 | [3] |
Level 3 | LCAPP Contracts | Derivative Liabilities | ' | ' | ||
Liabilities | ' | ' | ||
Fair value, liabilities | -166 | [3] | -144 | [3] |
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 | 3 | 8 | ||
Level 3 | FTRs | Derivative Assets | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 2 | 6 | ||
Level 3 | NUG contracts | Derivative Assets | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 23 | [3] | 36 | [3] |
Level 3 | Equity securities | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [4] | 0 | [4] |
Level 3 | Equity securities | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [4] | 0 | [4] |
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 | Other | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | 0 | [5] | 0 | [5] |
Level 3 | Other | FES | ' | ' | ||
Assets | ' | ' | ||
Fair value, assets | $0 | [5] | $0 | [5] |
[1] | Excludes $13 million and $110 million as of SeptemberB 30, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. | |||
[2] | Excludes $12 million and $94 million as of SeptemberB 30, 2013 and DecemberB 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table. | |||
[3] | NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. | |||
[4] | NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index. | |||
[5] | Primarily consists of short-term cash investments. |
Fair_Value_Measurements_Detail1
Fair Value Measurements (Details 1) (Level 3, USD $) | 9 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 | ||
Non Utility Generation Contract | ' | ' | ||
Reconciliation of changes in the fair value of NUG contracts | ' | ' | ||
Beginning Balance, Derivative Assets | $36 | [1] | $57 | [1] |
Beginning Balance, Derivative Liabilities | -290 | [1] | -349 | [1] |
Beginning Balance, Net | -254 | [1] | -292 | [1] |
Unrealized gain (loss), Derivative Assets | -6 | [1] | -20 | [1] |
Unrealized gain (loss), Derivative Liabilities | -6 | [1] | -180 | [1] |
Unrealized gain (loss), Net | -12 | [1] | -200 | [1] |
Purchases, Derivative Assets | 0 | [1] | 0 | [1] |
Purchases, Derivative Liabilities | 0 | [1] | 0 | [1] |
Purchases, Net | 0 | [1] | 0 | [1] |
Settlements, Derivative Assets | -7 | [1] | -1 | [1] |
Settlements, Derivative Liabilities | 63 | [1] | 239 | [1] |
Settlements, Net | 56 | [1] | 238 | [1] |
Ending Balance, Derivative Assets | 23 | [1] | 36 | [1] |
Ending Balance, Derivative Liabilities | -233 | [1] | -290 | [1] |
Ending Balance, Net | -210 | [1] | -254 | [1] |
LCAPP Contracts | ' | ' | ||
Reconciliation of changes in the fair value of NUG contracts | ' | ' | ||
Beginning Balance, Derivative Assets | 0 | [1] | 0 | [1] |
Beginning Balance, Derivative Liabilities | -144 | [1] | 0 | [1] |
Beginning Balance, Net | -144 | [1] | 0 | [1] |
Unrealized gain (loss), Derivative Assets | 0 | [1] | 0 | [1] |
Unrealized gain (loss), Derivative Liabilities | -22 | [1] | 1 | [1] |
Unrealized gain (loss), Net | -22 | [1] | 1 | [1] |
Purchases, Derivative Assets | 0 | [1] | 0 | [1] |
Purchases, Derivative Liabilities | 0 | [1] | -145 | [1] |
Purchases, Net | 0 | [1] | -145 | [1] |
Settlements, Derivative Assets | 0 | [1] | 0 | [1] |
Settlements, Derivative Liabilities | 0 | [1] | 0 | [1] |
Settlements, Net | 0 | [1] | 0 | [1] |
Ending Balance, Derivative Assets | 0 | [1] | 0 | [1] |
Ending Balance, Derivative Liabilities | -166 | [1] | -144 | [1] |
Ending Balance, Net | -166 | [1] | -144 | [1] |
FTRs | ' | ' | ||
Reconciliation of changes in the fair value of NUG contracts | ' | ' | ||
Beginning Balance, Derivative Assets | 8 | 1 | ||
Beginning Balance, Derivative Liabilities | -9 | -23 | ||
Beginning Balance, Net | -1 | -22 | ||
Unrealized gain (loss), Derivative Assets | 1 | 6 | ||
Unrealized gain (loss), Derivative Liabilities | 2 | -6 | ||
Unrealized gain (loss), Net | 3 | 0 | ||
Purchases, Derivative Assets | 5 | 13 | ||
Purchases, Derivative Liabilities | -15 | -10 | ||
Purchases, Net | -10 | 3 | ||
Settlements, Derivative Assets | -11 | -12 | ||
Settlements, Derivative Liabilities | 8 | 30 | ||
Settlements, Net | -3 | 18 | ||
Ending Balance, Derivative Assets | 3 | 8 | ||
Ending Balance, Derivative Liabilities | -14 | -9 | ||
Ending Balance, Net | -11 | -1 | ||
FTRs | FES | ' | ' | ||
Reconciliation of changes in the fair value of NUG contracts | ' | ' | ||
Beginning Balance, Derivative Assets | 6 | 1 | ||
Beginning Balance, Derivative Liabilities | -6 | -7 | ||
Beginning Balance, Net | 0 | -6 | ||
Unrealized gain (loss), Derivative Assets | -1 | 4 | ||
Unrealized gain (loss), Derivative Liabilities | -1 | -4 | ||
Unrealized gain (loss), Net | -2 | 0 | ||
Purchases, Derivative Assets | 4 | 9 | ||
Purchases, Derivative Liabilities | -12 | -7 | ||
Purchases, Net | -8 | 2 | ||
Settlements, Derivative Assets | -7 | -8 | ||
Settlements, Derivative Liabilities | 6 | 12 | ||
Settlements, Net | -1 | 4 | ||
Ending Balance, Derivative Assets | 2 | 6 | ||
Ending Balance, Derivative Liabilities | -13 | -6 | ||
Ending Balance, Net | ($11) | $0 | ||
[1] | Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. |
Fair_Value_Measurements_Detail2
Fair Value Measurements (Details 2) (Level 3, USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | ||||||
In Millions, unless otherwise specified | FTRs | FTRs | FTRs | FTRs | FTRs | FTRs | Non Utility Generation Contract | Non Utility Generation Contract | Non Utility Generation Contract | LCAPP Contracts | LCAPP Contracts | LCAPP Contracts | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | Model | ||||||
FES | FES | FES | FTRs | FTRs | Non Utility Generation Contract | LCAPP Contracts | Minimum | Minimum | Minimum | Minimum | Maximum | Maximum | Maximum | Maximum | Weighted Average | Weighted Average | Weighted Average | Weighted Average | ||||||||||||||||
FES | FTRs | FTRs | Non Utility Generation Contract | LCAPP Contracts | FTRs | FTRs | Non Utility Generation Contract | LCAPP Contracts | FTRs | FTRs | Non Utility Generation Contract | LCAPP Contracts | ||||||||||||||||||||||
FES | MWh | FES | MWh | FES | MWh | |||||||||||||||||||||||||||||
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||
Fair Value | ($11) | ($1) | ($22) | ($11) | $0 | ($6) | ($210) | [1] | ($254) | [1] | ($292) | [1] | ($166) | [1] | ($144) | [1] | $0 | [1] | ($11) | ($11) | ($210) | ($166) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair Value Inputs, RTO Auction Clearing Prices | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -5.6 | -5.6 | ' | ' | 5.4 | 5.4 | ' | ' | 0.62 | 0.4 | ' | ' | ||||||
Fair Value Inputs, Power | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600 | ' | ' | ' | 5,864,000 | ' | ' | ' | 1,421,000 | ' | ||||||
Fair Value Inputs, Power, Regional Prices | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 41.4 | 158.6 | ' | ' | 57.3 | 187.6 | ' | ' | 49.4 | 171.2 | ||||||
[1] | Changes in the fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. |
Fair_Value_Measurements_Detail3
Fair Value Measurements (Details 3) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Debt Securities | ' | ' | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ' | ' | ||
Cost Basis | $1,825 | [1] | $1,827 | [2] |
Unrealized Gains | 21 | [1] | 34 | [2] |
Fair Value | 1,846 | [1] | 1,861 | [2] |
Equity securities | ' | ' | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ' | ' | ||
Cost Basis | 433 | [1] | 293 | [2] |
Unrealized Gains | 28 | [1] | 16 | [2] |
Fair Value | 461 | [1] | 309 | [2] |
FES | Debt Securities | ' | ' | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ' | ' | ||
Cost Basis | 868 | [1] | 778 | [2] |
Unrealized Gains | 9 | [1] | 14 | [2] |
Fair Value | 877 | [1] | 792 | [2] |
FES | Equity securities | ' | ' | ||
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities | ' | ' | ||
Cost Basis | 317 | [1] | 281 | [2] |
Unrealized Gains | 21 | [1] | 13 | [2] |
Fair Value | $338 | [1] | $294 | [2] |
[1] | Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million | |||
[2] | Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million |
Fair_Value_Measurements_Detail4
Fair Value Measurements (Details 4) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | ' | ' | ' | ' |
Sales Proceeds | $368 | $1,751 | $1,545 | $2,133 |
Realized Gains | 9 | 81 | 49 | 118 |
Realized Losses | -15 | -30 | -31 | -58 |
OTTI | -21 | -2 | -74 | -9 |
Interest and Dividend Income | 26 | 18 | 74 | 51 |
FES | ' | ' | ' | ' |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income | ' | ' | ' | ' |
Sales Proceeds | 164 | 1,059 | 650 | 1,167 |
Realized Gains | 5 | 60 | 38 | 85 |
Realized Losses | -3 | -21 | -14 | -40 |
OTTI | -21 | -2 | -66 | -8 |
Interest and Dividend Income | $16 | $10 | $44 | $27 |
Fair_Value_Measurements_Detail5
Fair Value Measurements (Details 5) (Debt Securities, USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Debt Securities | ' | ' |
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities | ' | ' |
Cost Basis | $46 | $54 |
Unrealized Gains | 1 | 30 |
Fair Value | $47 | $84 |
Fair_Value_Measurements_Detail6
Fair Value Measurements (Details 6) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
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 | $17,007 | $16,957 |
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 | 17,721 | 19,460 |
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 | 3,015 | 4,194 |
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 | $3,082 | $4,524 |
Fair_Value_Measurements_Detail7
Fair Value Measurements (Details Textuals) (USD $) | 3 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | 3 Months Ended | 9 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 1 Months Ended | 0 Months Ended | ||||||||||||||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | 8-May-13 | Oct. 31, 2013 | Sep. 30, 2013 | 8-May-13 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | 8-May-13 | Oct. 31, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Jun. 03, 2013 | Aug. 31, 2013 | Jun. 30, 2013 | Aug. 31, 2013 | Aug. 31, 2013 | 8-May-13 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Mar. 31, 2013 | Apr. 15, 2013 | Mar. 31, 2013 | Jun. 30, 2013 | Aug. 31, 2013 | Mar. 31, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | Jun. 30, 2013 | |
Revolving Credit Facility | Revolving Credit Facility | NUG contracts | FE | FES | FES | FES | FES | FES | FES | FES Corp and Allegheny Energy Inc | FGCO | FGCO | FGCO | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | JCP&L | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes, 2.75% Due 2018 | Senior Notes, 4.25% Due 2023 | Senior Notes, 3.50% Due 2023 | Senior Notes, 4.80% Due 2015 | Senior Notes, 4.80% Due 2015 | Phase In Recovery Bonds | Notes, 4.7% Due 2024 | Senior Notes, 4.95% Due 2013 | Existing Taxable Bonds | Existing Taxable Bonds | Existing Taxable Bonds | Existing Taxable Bonds | ||||||
credit_facility | Subsequent Event | Revolving Credit Facility | Revolving Credit Facility | Revolving Credit Facility | Minimum | Maximum | Revolving Credit Facility | FE | FES | FES | FES | Allegheny Energy Inc | Allegheny Energy Inc | Allegheny Energy Inc | FES Corp and Allegheny Energy Inc | FES Corp and Allegheny Energy Inc | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Senior Notes | Ohio Funding Companies | Unsecured Debt | Senior Notes, 3.50% Due 2023 | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | Ohio Funding Companies | |||||||||||||||||
Subsequent Event | Year 2021 | Year 2039 | Year 2019 | Year 2039 | Minimum | Maximum | FE | FE | Met-Ed | FES | FES | JCP&L | Senior Notes | Year 2013 | Year 2015 | Year 2020 | |||||||||||||||||||||||||||||
Met-Ed | |||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Instruments [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of future observable data to determine contract price | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Investment excludes Receivables, Payables and Accrued income | $13,000,000 | ' | $13,000,000 | ' | $110,000,000 | ' | ' | ' | ' | $12,000,000 | ' | $12,000,000 | ' | $94,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash balance excluded from available for sale securities | 106,000,000 | ' | 106,000,000 | ' | 326,000,000 | ' | ' | ' | ' | 55,000,000 | ' | 55,000,000 | ' | 196,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Investments not required to be disclosed | 646,000,000 | ' | 646,000,000 | ' | 644,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Debt instrument, face amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | 850,000,000 | 300,000,000 | ' | ' | 445,000,000 | 500,000,000 | ' | 410,000,000 | 225,000,000 | 150,000,000 | 35,000,000 |
Stated interest rate percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.65% | 7.25% | ' | ' | ' | ' | ' | ' | ' | ' | 5.75% | 6.80% | 2.75% | 4.25% | 3.50% | 4.80% | 4.80% | ' | 4.70% | 4.95% | ' | ' | ' | ' |
Debt repurchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 369,000,000 | 252,000,000 | 117,000,000 | 294,000,000 | 194,000,000 | 100,000,000 | ' | ' | ' | ' | ' | 400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Face amount of debt repurchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 235,000,000 | 660,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150,000,000 | ' | ' | ' | ' |
Payments of debt redemption premiums | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 67,000,000 | ' | ' | 43,000,000 | ' | ' | ' | ' | ' | ' | ' | 31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Debt repurchase notice amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | ' | ' | ' | ' | ' | ' | ' |
Loss on debt redemptions | 9,000,000 | 0 | -132,000,000 | 0 | ' | ' | ' | ' | ' | 0 | 0 | -103,000,000 | 0 | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | 119,000,000 | 71,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Number of Credit Facilities Extended | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Term, Extension Period | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Increase, Borrowing Capacity | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 175,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Current Borrowing Capacity | ' | ' | ' | ' | ' | ' | 2,500,000,000 | ' | 2,500,000,000 | ' | ' | ' | ' | ' | 2,500,000,000 | 2,500,000,000 | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Amounts Excluded From Debt to Capital Ratio Calculation | ' | ' | ' | ' | ' | ' | 1,400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 785,700,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Line of Credit Facility, Increase, Amounts Excluded From Debt to Capital Ratio Calculation | ' | ' | ' | ' | ' | ' | 1,350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Weighted average interest rate on debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.48% | ' | ' | 5.71% | ' | ' | ' |
Make-whole premiums paid on debt redemptions | ' | ' | $181,000,000 | $0 | ' | ' | ' | ' | ' | ' | ' | $31,000,000 | $0 | ' | ' | ' | ' | ' | ' | $120,000,000 | $30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative_Instruments_Details
Derivative Instruments (Details) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Fair value of commodity derivatives | ' | ' |
Derivative Assets | $227 | $296 |
Derivative Liabilities | -525 | -598 |
Current Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 140 | 160 |
Noncurrent Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 87 | 136 |
Current Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -105 | -126 |
Noncurrent Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -420 | -472 |
Power Contracts | Current Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 137 | 153 |
Power Contracts | Noncurrent Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 64 | 99 |
Power Contracts | Current Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -94 | -119 |
Power Contracts | Noncurrent Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -18 | -36 |
FTRs | Current Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 3 | 7 |
FTRs | Noncurrent Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 0 | 1 |
FTRs | Current Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -11 | -7 |
FTRs | Noncurrent Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -3 | -2 |
NUGs | Noncurrent Assets | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Assets | 23 | 36 |
NUGs | Noncurrent Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | -233 | -290 |
LCAPP | Noncurrent Liabilities | ' | ' |
Fair value of commodity derivatives | ' | ' |
Derivative Liabilities | ($166) | ($144) |
Derivative_Instruments_Details1
Derivative Instruments (Details 1) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Derivative Assets | ' | ' |
Fair Value | $227 | $296 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | -107 | -150 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | -11 | -5 |
Net Fair Value | 109 | 141 |
Derivative Liabilities | ' | ' |
Fair Value | -525 | -598 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 107 | 150 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 11 | 13 |
Net Fair Value | -407 | -435 |
Power Contracts | ' | ' |
Derivative Assets | ' | ' |
Fair Value | 201 | 252 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | -104 | -142 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | -11 | -5 |
Net Fair Value | 86 | 105 |
Derivative Liabilities | ' | ' |
Fair Value | -112 | -155 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 104 | 142 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 5 | 12 |
Net Fair Value | -3 | -1 |
FTRs | ' | ' |
Derivative Assets | ' | ' |
Fair Value | 3 | 8 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | -3 | -8 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 0 | 0 |
Net Fair Value | 0 | 0 |
Derivative Liabilities | ' | ' |
Fair Value | -14 | -9 |
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments | 3 | 8 |
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged | 6 | 1 |
Net Fair Value | -5 | 0 |
NUGs | ' | ' |
Derivative Assets | ' | ' |
Fair Value | 23 | 36 |
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 | 23 | 36 |
Derivative Liabilities | ' | ' |
Fair Value | -233 | -290 |
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 | -233 | -290 |
LCAPP | ' | ' |
Derivative Liabilities | ' | ' |
Fair Value | -166 | -144 |
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 | ($166) | ($144) |
Derivative_Instruments_Details2
Derivative Instruments (Details 2) | Sep. 30, 2013 |
MWh | |
Power Contracts | ' |
Volume of First Energy's outstanding derivative transactions | ' |
Purchases (in MWH or mmBTUs) | 32,000,000 |
Sales (in MWH or mmBTUs) | 37,000,000 |
Net (in MWH or mmBTUs) | -5,000,000 |
FTRs | ' |
Volume of First Energy's outstanding derivative transactions | ' |
Purchases (in MWH or mmBTUs) | 59,000,000 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 59,000,000 |
NUGs | ' |
Volume of First Energy's outstanding derivative transactions | ' |
Purchases (in MWH or mmBTUs) | 11,000,000 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 11,000,000 |
LCAPP | ' |
Volume of First Energy's outstanding derivative transactions | ' |
Volume of Derivatives, Purchases (in MW) | 408,000,000 |
Volume of Derivatives, Sales (in MW) | 0 |
Volume of Derivatives, Net (in MW) | 408,000,000 |
Natural Gas | ' |
Volume of First Energy's outstanding derivative transactions | ' |
Purchases (in MWH or mmBTUs) | 64,000,000 |
Sales (in MWH or mmBTUs) | 0 |
Net (in MWH or mmBTUs) | 64,000,000 |
Derivative_Instruments_Details3
Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Revenue | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | $20 | $52 | $48 | $278 |
Purchase Power Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | -17 | -27 | -30 | -248 |
Other Operating Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | 3 | 2 | -15 | 84 |
Realized Gain (Loss) Reclassified | -10 | -10 | -28 | -51 |
Fuel Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | -2 | 3 | ' | 2 |
Interest Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | ' | 20 | ' | ' |
Realized Gain (Loss) Reclassified | ' | 6 | ' | 6 |
Power Contracts | Revenue | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 14 | 46 | 29 | 260 |
Power Contracts | Purchase Power Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | -17 | -27 | -30 | -248 |
Power Contracts | Other Operating Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | 11 | 7 | -5 | 72 |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 | 0 |
Power Contracts | Fuel Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | -2 | 3 | ' | 2 |
Power Contracts | Interest Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | ' | 0 | ' | ' |
Realized Gain (Loss) Reclassified | ' | 0 | ' | 0 |
FTRs | Revenue | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 6 | 6 | 19 | 18 |
FTRs | Purchase Power Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 | 0 |
FTRs | Other Operating Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | -8 | -5 | -10 | 12 |
Realized Gain (Loss) Reclassified | -10 | -10 | -28 | -51 |
FTRs | Fuel Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and 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 designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | ' | 0 | ' | ' |
Realized Gain (Loss) Reclassified | ' | 0 | ' | 0 |
Interest rate swaps | Revenue | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 | 0 |
Interest rate swaps | Purchase Power Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 | 0 |
Interest rate swaps | Other Operating Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | 0 | 0 | 0 | 0 |
Realized Gain (Loss) Reclassified | 0 | 0 | 0 | 0 |
Interest rate swaps | Fuel Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Realized Gain (Loss) Reclassified | 0 | 0 | ' | 0 |
Interest rate swaps | Interest Expense | ' | ' | ' | ' |
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships | ' | ' | ' | ' |
Unrealized Gain (Loss) Recognized | ' | 20 | ' | ' |
Realized Gain (Loss) Reclassified | ' | $6 | ' | $6 |
Derivative_Instruments_Details4
Derivative Instruments (Details 4) (Not Designated as Hedging Instrument, Subject to Regulatory Accounting, Excluded from Earnings, USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Derivative [Line Items] | ' | ' | ' | ' |
Unrealized Gain (Loss) on Derivative Instrument | $0 | ($47) | ($34) | ($325) |
Realized Gain (Loss) on Derivative Instrument | 13 | 60 | 56 | 201 |
NUGs | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' |
Unrealized Gain (Loss) on Derivative Instrument | 7 | -50 | -13 | -183 |
Realized Gain (Loss) on Derivative Instrument | 14 | 61 | 57 | 194 |
LCAPP | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' |
Unrealized Gain (Loss) on Derivative Instrument | -8 | 3 | -22 | -142 |
Realized Gain (Loss) on Derivative Instrument | 0 | 0 | 0 | 0 |
Regulated FTRs | ' | ' | ' | ' |
Derivative [Line Items] | ' | ' | ' | ' |
Unrealized Gain (Loss) on Derivative Instrument | 1 | 0 | 1 | 0 |
Realized Gain (Loss) on Derivative Instrument | ($1) | ($1) | ($1) | $7 |
Derivative_Instruments_Details5
Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Outstanding net asset (liability) [Roll Forward] | ' | ' | ' | ' |
Outstanding net asset (liability), Beginning Balance | ($389) | ($438) | ($398) | ($301) |
Additions/Change in value of existing contracts | 0 | -47 | -34 | -325 |
Settled contracts | 13 | 60 | 56 | 201 |
Outstanding net asset (liability), Ending Balance | -376 | -425 | -376 | -425 |
NUGs | ' | ' | ' | ' |
Outstanding net asset (liability) [Roll Forward] | ' | ' | ' | ' |
Outstanding net asset (liability), Beginning Balance | -231 | -293 | -254 | -293 |
Additions/Change in value of existing contracts | 7 | -50 | -13 | -183 |
Settled contracts | 14 | 61 | 57 | 194 |
Outstanding net asset (liability), Ending Balance | -210 | -282 | -210 | -282 |
LCAPP | ' | ' | ' | ' |
Outstanding net asset (liability) [Roll Forward] | ' | ' | ' | ' |
Outstanding net asset (liability), Beginning Balance | -158 | -145 | -144 | 0 |
Additions/Change in value of existing contracts | -8 | 3 | -22 | -142 |
Settled contracts | 0 | 0 | 0 | 0 |
Outstanding net asset (liability), Ending Balance | -166 | -142 | -166 | -142 |
Regulated FTRs | ' | ' | ' | ' |
Outstanding net asset (liability) [Roll Forward] | ' | ' | ' | ' |
Outstanding net asset (liability), Beginning Balance | 0 | 0 | 0 | -8 |
Additions/Change in value of existing contracts | 1 | 0 | 1 | 0 |
Settled contracts | -1 | -1 | -1 | 7 |
Outstanding net asset (liability), Ending Balance | $0 | ($1) | $0 | ($1) |
Derivative_Instruments_Details6
Derivative Instruments (Details Textuals) (USD $) | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 11, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |
Commodity contracts | NUGs | FTRs | FES | FES | JCP&L | JCP&L | Cash Flow Hedges | Cash Flow Hedges | Fair Value Hedging | Fair Value Hedging | Fair Value Hedging | Fair Value Hedging | Fair Value Hedging | |||||
Commodity contracts | FTRs | contracts | Subsequent Event | agreements | agreements | agreements | agreements | agreements | ||||||||||
appeal | ||||||||||||||||||
Derivative [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Unamortized gains or losses associated with designated cash flow hedges | $5,000,000 | ' | $5,000,000 | $10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' |
Unamortized gains or losses associated with prior interest rate hedges | 61,000,000 | ' | 61,000,000 | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Losses to be amortized to interest expenses during next twelve months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | ' | ' | 13,000,000 | ' | ' |
Number of fixed-for-floating interest rate swap agreements outstanding | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | 0 |
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements | 48,000,000 | ' | 48,000,000 | 79,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reclassifications from long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 6,000,000 | 15,000,000 | 17,000,000 | ' |
Unamortized gain (loss) on extinguishment of debt | 9,000,000 | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | 17,000,000 | ' | ' |
Net asset position under commodity derivative contracts | ' | ' | ' | ' | 89,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Collateral posted | ' | ' | ' | ' | ' | ' | ' | 43,000,000 | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional collateral related to commodity derivatives | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected adverse change in quoted market prices of derivative instruments | 10.00% | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Decrease net income due to adverse change in commodity prices | ' | ' | 27,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Interest Rate Derivative, Termination | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Liability position | ' | ' | ' | ' | ' | 210,000,000 | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of outstanding LCAPP contracts | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' |
Number of appeals dismissed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' |
Period in which LSEs may request direct allocation of FTRs | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Direct allocation of FTRs, cost | ' | ' | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset_Retirement_Obligations_D
Asset Retirement Obligations (Details) (USD $) | 3 Months Ended | 9 Months Ended |
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2013 |
Changes to the asset retirement obligations | ' | ' |
Beginning Balance | ' | $1,599 |
Liabilities settled | ' | -13 |
Accretion | ' | 85 |
Revisions in estimated cash flows | ' | 163 |
Ending Balance | 1,834 | 1,834 |
FES | ' | ' |
Changes to the asset retirement obligations | ' | ' |
Beginning Balance | ' | 965 |
Liabilities settled | ' | -14 |
Accretion | ' | 52 |
Revisions in estimated cash flows | 5 | 156 |
Ending Balance | 1,159 | 1,159 |
TE | ' | ' |
Changes to the asset retirement obligations | ' | ' |
Revisions in estimated cash flows | $7 | ' |
Regulatory_Matters_Details
Regulatory Matters (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 0 Months Ended | 1 Months Ended | 9 Months Ended | 1 Months Ended | 3 Months Ended | 1 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||
Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Oct. 31, 2013 | Oct. 31, 2013 | Apr. 30, 2007 | Sep. 30, 2013 | Jan. 21, 2010 | Sep. 04, 2013 | 31-May-13 | Dec. 07, 2012 | Sep. 30, 2013 | Dec. 20, 2012 | Sep. 30, 2013 | Aug. 24, 2012 | Sep. 30, 2013 | Aug. 24, 2012 | Aug. 24, 2012 | Sep. 28, 2012 | Sep. 30, 2013 | Sep. 03, 2013 | Dec. 22, 2011 | Sep. 30, 2013 | Aug. 31, 2011 | Oct. 06, 2009 | Jun. 14, 2013 | Sep. 30, 2013 | Feb. 22, 2013 | Nov. 30, 2012 | Jun. 14, 2013 | Aug. 07, 2013 | Jan. 31, 2013 | Aug. 31, 2011 | Oct. 31, 2009 | Sep. 30, 2013 | Dec. 31, 2009 | Dec. 12, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2010 | Apr. 04, 2013 | Feb. 15, 2013 | Jan. 16, 2013 | 31-May-11 | Apr. 29, 2011 | Oct. 10, 2013 | Sep. 30, 2013 | Oct. 10, 2013 | Oct. 10, 2013 | Oct. 10, 2013 | Oct. 10, 2013 | Sep. 30, 2013 | Feb. 06, 2013 | Apr. 30, 2010 | Sep. 30, 2013 | Oct. 22, 2012 | Feb. 28, 2011 | Oct. 31, 2013 | Sep. 30, 2013 | Feb. 28, 2011 | Feb. 28, 2011 | Oct. 31, 2006 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | |
entities | FES | FES | FES | AE Supply | M P [Member] | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | FERC | MARYLAND | MARYLAND | MARYLAND | MARYLAND | MARYLAND | NEW JERSEY | NEW JERSEY | NEW JERSEY | NEW JERSEY | NEW JERSEY | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | OHIO | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | PENNSYLVANIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | WEST VIRGINIA | California Claims Matters | California Claims Matters | The Seneca Pumped Storage Project | The Seneca Pumped Storage Project Relicensing | |||
Subsequent Event | Subsequent Event | kv | class | issues | Hydroelectric Asset Sale | MOPR Reform | MOPR Reform | Synchronous Condensers | Synchronous Condensers | PJM | PATH | PATH | PATH-Allegheny | Path-WV | Path-WV | FES and AE Supply | component | JCP&L | Party | proposals | proposals | plan | questions | Year 2012 | Year 2013 | Year 2014 | Annually Through 2025 | Annually Through 2018 | enhancement | choice | Party | questions | Subsequent Event | Year 2013 | Three Month Period | Twelve Month Period | Twenty-Four Month Period | Forty-Eight Month Period | Unfavorable Regulatory Action | Unfavorable Regulatory Action | MW | hearing | Facilities | Subsequent Event | Subsequent Event | City of New Martinsville | Morgantown Energy | FERC | FERC | FERC | |||||||||||||||||||||||
MW | exemption | kv | challenge | FTR Underfunding Complaint | bgs | MWh | MWh | MWh | MWh | workgroup | issues | proposals | Subsequent Event | Subsequent Event | Subsequent Event | Subsequent Event | entities | entities | Proceedings | MW | |||||||||||||||||||||||||||||||||||||||||||||||||||||
plant | Minimum | comment | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed electric consumption reduction percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed electric demand reduction percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expenditures for cost recovery program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $66,000,000 | $101,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recovery period for expenditures for cost recovery program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum penalty assessed, in dollars per day per violation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected increase in cost due to proposed plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 106,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected Infrastructure Investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,700,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected Infrastructure Investments, Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '15 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Supply Components | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Basic Generation Services | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested increase in revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 603,000,000 | 31,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (Decrease) in Revenue Recovery Request | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 112,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of cost recovery choices | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Load cap percentage minimum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum trance award to a single supplier | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Generation discount for low income customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recovery Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Costs avoided by customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 360,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fund to assist low income customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
ESP Extension Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, New Claims Filed, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Generation supply auction period, after approval | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Generation supply auction period, before approval | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual energy savings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,211,000 | 1,726,000 | 2,306,000 | 2,903,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (decrease) in annual energy savings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 416,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Utilities required to reduce peak demand | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Utilities required to additionally reduce peak demand | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of plans | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Portfolio Plan, Estimated Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Portion of Revenue Obtained to be Received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Request for proposals conducted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit to Non-Shopping Customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 43,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Credit to Non-Shopping Customers, Implementation Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '60 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Marginal Transmission Refund Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '29 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Marginal transmission losses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 254,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Impairment Charges | 473,000,000 | 473,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 254,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 330,000,000 | ' | ' | ' | ' | ' | ' | ' |
Regulatory Liabilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,000,000 | ' | ' | ' | ' | ' | ' |
Minimum reduction in Utilities reduce energy consumption | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.00% | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Minimum reduction in Utilities peak demand | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Range of Possible Loss, Maximum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | 234,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of parties not settled | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of issues not settled | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Energy Contract, Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 months | '12 months | '24 months | '48 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Requests For Proposal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Request for Proposal, Project Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annualized base rate increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Storm Restoration Deferral Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of public hearings held | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of time to implement plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '6 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional base rate increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recommend Reduction in Base Rates for Electric Service | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 202,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Decrease in ENEC rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of electric generation facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' |
Number of electric generation facilities, owned by third party | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | 1 | ' | ' | ' | ' |
Cash Consideration received in Asset Swap Transaction | ' | ' | ' | ' | ' | ' | 1,100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Noncash or Part Noncash Acquisition, Debt Assumed | ' | ' | ' | ' | ' | ' | 73,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cash Consideration provided in Asset Swap Transaction | ' | ' | ' | ' | ' | ' | ' | 1,100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Equity contribution from parent | ' | ' | ' | 1,500,000,000 | 1,500,000,000 | 0 | ' | 527,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proceeds from Collection of (Payments to Fund) Long-term Loans to Related Parties | ' | ' | ' | ' | 22,000,000 | -55,000,000 | ' | 573,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Power threshold for cost methodology | ' | ' | ' | ' | ' | ' | ' | ' | 500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Compliance Filing, Hybrid Methodology, Beneficiary Pays Cost Allocation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Denied Recovery Charges of Exit Fees | ' | ' | ' | ' | ' | ' | ' | ' | ' | 78,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Identified issues for written comments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual Revenue requirements in Zone | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of classes of regulatory proceedings | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Settlement proposal claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 190,000,000 | ' | ' |
Court proceedings from filed claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' |
New Voltage transmission facilities across PJM and a zonal transmission rate (In KV) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 765 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Cost recovery, PP&E reclassified to Regulatory Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 62,000,000 | 59,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Formal Challenges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Auctioned Energy Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 59 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Hydroelectric project | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 451 | ' |
Application to Sell Power Plant Projects, Number | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Application to Sell Power Plant Projects, Combined Power | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 527 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Application to Sell Power Plant Projects, Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Transfer, Price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of cycle | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years |
Number of Exemptions Added | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Conversion Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Transfer, Recognized Gain | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Percent of Meters to be Installed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 98.50% | 98.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected Cost of Meter Installations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,250,000,000 | 1,250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Directed Questions for Investigation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Workgroups Established | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Comments Established | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Retail Market Enhancements | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Asset, Cost Recovery, Proposed Return on Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.90% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Base Return On Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.40% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Return On Equity Granted For Regional Transmission Organization Participation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remaining Recovery Period of Regulatory Assets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues Lost of Which the Entity is Entitled | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $64,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Resource Plan, Proposed Transfer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,476 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual Load Growth Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.40% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of Time to File Case | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '6 months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regional Enforcement Entities | ' | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_Guarantees_and_Con2
Commitments, Guarantees and Contingencies (Details) (USD $) | Sep. 30, 2013 |
In Millions, unless otherwise specified | |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | $903 |
Split Rating (One rating agency's rating below investment grade) | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 501 |
BB Plus/BA1 Credit Ratings | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 545 |
FES | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 755 |
FES | Split Rating (One rating agency's rating below investment grade) | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 440 |
FES | BB Plus/BA1 Credit Ratings | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 484 |
AE Supply | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 58 |
AE Supply | Split Rating (One rating agency's rating below investment grade) | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 6 |
AE Supply | BB Plus/BA1 Credit Ratings | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 6 |
Utilities | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 90 |
Utilities | Split Rating (One rating agency's rating below investment grade) | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | 55 |
Utilities | BB Plus/BA1 Credit Ratings | ' |
Guarantor Obligations [Line Items] | ' |
Maximum exposure under collateral provisions | $55 |
Commitments_Guarantees_and_Con3
Commitments, Guarantees and Contingencies (Details Textuals) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 0 Months Ended | 9 Months Ended | 0 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 0 Months Ended | 3 Months Ended | |||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Jun. 30, 2013 | Sep. 30, 2013 | Apr. 30, 2009 | Mar. 28, 2013 | Sep. 30, 2013 | Oct. 10, 2013 | Oct. 03, 2013 | 31-May-13 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Apr. 13, 2012 | Jan. 02, 2011 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Aug. 13, 2012 | 2-May-11 | Feb. 13, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Apr. 13, 2012 | Apr. 13, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | |
ICG Litigation | Clean Water Act | Clean Water Act | Regulation of Waste Disposal | Regulation of Waste Disposal | Regulation of Waste Disposal | Regulation of Waste Disposal | Nuclear Plant Matters | Nuclear Plant Matters | Caa Compliance | National Ambient Air Quality Standards | National Ambient Air Quality Standards | National Ambient Air Quality Standards | Hazardous Air Pollutant Emissions | Climate Change | Climate Change | Climate Change | Climate Change | Senior Secured Term Loan | Senior Secured Term Loan | Regulated Distribution | FES | FES | FES | AE Supply | AE Supply | Global Holding | Global Holding | Global Holding | Signal Peak and Global Rail | Signal Peak and Global Rail | FEV | WMB Marketing Ventures, LLC | FGCO | FGCO | FGCO | FGCO | FGCO | FGCO | AE Supply and MP | AE Supply and MP | Wp | Parental Guarantees | Subsidiaries' Guarantees | Other Guarantees | State and Local Agencies | Environmental Protection Agency | Minimum | Maximum | Transportation Commitment [Member] | Transportation Commitment [Member] | |||||
aspect_of_opinion | options | Subsequent Event | Subsequent Event | petitioners | CoalFiredPlants | T | CAIR | CSAPR | celsius | lb | T | Year 2020 | Senior Loans | Senior Loans | ICG Litigation | Senior Secured Term Loan | Senior Secured Term Loan | Senior Secured Term Loan | Senior Secured Term Loan | Senior Secured Term Loan | Caa Compliance | Caa Compliance | Caa Compliance | ICG Litigation | ICG Litigation | Hazardous Air Pollutant Emissions | Hazardous Air Pollutant Emissions | Climate Change | Climate Change | Hazardous Air Pollutant Emissions | Hazardous Air Pollutant Emissions | ||||||||||||||||||||||||
IndividualsInAComplaint | deficiency | ElectricGenerationUnits | phases | phases | Increase in funding | Senior Loans | Senior Loans | Senior Loans | Senior Loans | Senior Loans | Complaints | Claim One | Claim Two | ||||||||||||||||||||||||||||||||||||||||||
Signal Peak, Global Rail and Affiliates | Signal Peak | Signal Peak | IndividualsInAComplaint | plaintiff | |||||||||||||||||||||||||||||||||||||||||||||||||||
Global Holding | Global Holding | Complaints | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Guarantor Obligations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Outstanding guarantees and other assurances aggregated | $4,400,000,000 | $4,400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,403,000,000 | $2,232,000,000 | $747,000,000 | ' | ' | ' | ' | ' | ' |
Company posted collateral related to net liability positions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | 150,000,000 | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential collateral posted related to net liability positions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 77,000,000 | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Senior secured term loan facility, term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
New syndicated senior secured term loan facility | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Repayments of senior secured term loan facility | ' | 2,662,000,000 | 870,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,179,000,000 | 246,000,000 | ' | ' | ' | ' | ' | ' | ' | 350,000,000 | ' | ' | 352,000,000 | 169,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Investment ownership percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 69.99% | ' | ' | 33.33% | 33.33% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Guarantor obligations, guarantee fee receivable, percentage, remainder of fiscal year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Guarantor obligations, guarantee fee receivable, percentage, next twelve months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of complaints filed against FGCO | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of complaints seek enjoin plant | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of individuals behalf of which complaint filed | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of named plaintiffs as class representatives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reduction in air emissions and compliance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25.00% | 40.00% | ' | ' |
Number of electric generation facilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of generation units | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of phases under the EPAbs CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capping of SO2 emissions (In Tons) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capping of NOx emissions (In Tons) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capping of SO2 Emissions Under CSAPR | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Capping of NOx emissions under CSAPR | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential cost of compliance, MATS | ' | ' | ' | ' | ' | ' | ' | ' | 234,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 465,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss Contingency, Settlement Agreement, Consideration | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 45,000,000 |
Loss Contingency, Range of Possible Loss, Maximum | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000,000 | ' |
Pre-tax severance expense related to closures | 2,000,000 | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Upper threshold limit for carbon dioxide emission (Tons per Year) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Increase (decrease) in global temperature | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Funds provided for Copenhagen Green Climate Fund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000,000 | ' | ' | 100,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitment Period by Developed Countries to Provide Funds, Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitment, Proposed Emissions Standard | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Aspects of opinion reversed | ' | ' | ' | ' | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Annual percentage that fish impingement should be reduced to, per CWA | ' | ' | ' | ' | ' | 12.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Maximum capital investment required to install technology to meet TDS and Sulfate limits | ' | ' | ' | ' | ' | 150,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
TMDL Limit Development Period | ' | ' | ' | ' | ' | '5 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Deficiencies Identified in Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Options proposed by EPA for additional regulation of coal combustion residuals | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Claims Resolution, Civil Penalties | ' | ' | ' | ' | ' | ' | ' | ' | 800,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 86,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Period of time to implement plan | ' | ' | ' | ' | ' | ' | ' | '15 years | ' | ' | '9 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Bond Closure and Post Closure Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '45 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Accrual for Environmental Loss Contingencies | ' | ' | ' | ' | ' | ' | ' | ' | 124,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Environmental Liabilities Former Gas Facilities | ' | ' | ' | ' | ' | ' | ' | ' | 82,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Decommissioning Fund Investments | 2,183,000,000 | 2,183,000,000 | ' | 2,204,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 2,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,270,000,000 | ' | 1,283,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Parental guarantee associated with the funding of decommissioning costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 125,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Parental Guarantee Associated With Funding Of Decommissioning Costs, Additions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Renewal length of operating license for Davis-Besse Nuclear Power Station | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '20 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Loss incurred in damages for replacement coal purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional damages incurred for future shortfalls | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Verdict in Favor | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount for which verdict entered for future damages | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount for replacement coal and interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain contingency, unrecorded amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Gain Contingency, Damages Denied, Value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential MATS Extension Period | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | '1 year | ' | ' | ' | ' |
Gain contingency, damages denied | ' | ' | ' | ' | $16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Number of Petitioners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Supplemental_Guarantor_Informa2
Supplemental Guarantor Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | $2,530 | $2,670 | $7,139 | $7,533 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 657 | 636 | 1,915 | 1,833 |
Purchased power | 1,120 | 1,063 | 2,932 | 3,367 |
Other operating expenses | 877 | 861 | 2,645 | 2,597 |
Provision for depreciation | 316 | 272 | 909 | 834 |
General taxes | 242 | 257 | 747 | 760 |
Total operating expenses | 3,524 | 3,150 | 10,064 | 9,589 |
OPERATING INCOME (LOSS) | 512 | 902 | 1,206 | 2,191 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 9 | 0 | -132 | 0 |
Investment income | 5 | 39 | 8 | 63 |
Interest expense | -257 | -230 | -771 | -750 |
Capitalized interest | 17 | 18 | 51 | 54 |
Total other income (expense) | -226 | -173 | -844 | -633 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 286 | 729 | 362 | 1,558 |
INCOME TAXES (BENEFITS) | 77 | 307 | 129 | 650 |
NET INCOME FROM CONTINUING OPERATIONS | 209 | 422 | 233 | 908 |
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 |
NET INCOME (LOSS) | 218 | 425 | 250 | 919 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | 218 | 425 | 250 | 919 |
Pension and OPEB prior service costs | -47 | -47 | -148 | -148 |
Amortized loss (gain) on derivative hedges | 2 | 0 | 4 | 1 |
Change in unrealized gain on available-for-sale securities | 6 | 1 | 3 | 13 |
Other comprehensive income (loss) | -39 | -46 | -141 | -134 |
Income taxes (benefits) on other comprehensive income (loss) | -15 | -24 | -55 | -75 |
Net other comprehensive income (loss) | -24 | -22 | -86 | -59 |
COMPREHENSIVE INCOME (LOSS) | 194 | 403 | 164 | 860 |
FES | ' | ' | ' | ' |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | 1,654 | 1,523 | 4,575 | 4,443 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 0 | 0 | 0 | 0 |
Other operating expenses | 147 | 130 | 484 | 313 |
Provision for depreciation | 1 | 1 | 4 | 3 |
General taxes | 21 | 20 | 60 | 60 |
Total operating expenses | 1,898 | 1,692 | 5,369 | 4,959 |
OPERATING INCOME (LOSS) | -244 | -169 | -794 | -516 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 0 | ' | -103 | ' |
Investment income | 2 | 1 | 4 | 2 |
Miscellaneous income, including net income from equity investees | 180 | 317 | 543 | 854 |
Capitalized interest | 0 | 0 | 1 | 0 |
Total other income (expense) | 166 | 288 | 385 | 770 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | -78 | 119 | -409 | 254 |
INCOME TAXES (BENEFITS) | -118 | 18 | -380 | 32 |
NET INCOME FROM CONTINUING OPERATIONS | 40 | 101 | -29 | 222 |
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 |
NET INCOME (LOSS) | 40 | 101 | -29 | 222 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | 40 | 101 | -29 | 222 |
Pension and OPEB prior service costs | -5 | -5 | -16 | -2 |
Amortized loss (gain) on derivative hedges | -1 | -2 | -3 | -6 |
Change in unrealized gain on available-for-sale securities | 5 | -2 | 2 | 11 |
Other comprehensive income (loss) | -1 | -9 | -17 | 3 |
Income taxes (benefits) on other comprehensive income (loss) | -1 | -3 | -7 | 1 |
Net other comprehensive income (loss) | 0 | -6 | -10 | 2 |
COMPREHENSIVE INCOME (LOSS) | 40 | 95 | -39 | 224 |
FES | Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 1,009 | 1,042 | 3,072 | 3,163 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -3 | -5 | -10 | -14 |
FES | Non-Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 720 | 499 | 1,749 | 1,420 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -13 | -25 | -50 | -72 |
FGCO | ' | ' | ' | ' |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | 528 | 610 | 1,612 | 1,777 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 249 | 248 | 782 | 824 |
Other operating expenses | 65 | 78 | 208 | 268 |
Provision for depreciation | 33 | 29 | 96 | 87 |
General taxes | 9 | 10 | 28 | 28 |
Total operating expenses | 360 | 368 | 1,120 | 1,212 |
OPERATING INCOME (LOSS) | 168 | 242 | 492 | 565 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 0 | ' | 0 | ' |
Investment income | 0 | 5 | 0 | 14 |
Miscellaneous income, including net income from equity investees | 19 | 0 | 23 | 19 |
Capitalized interest | 1 | 1 | 1 | 3 |
Total other income (expense) | -6 | -23 | -59 | -48 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 162 | 219 | 433 | 517 |
INCOME TAXES (BENEFITS) | 111 | -14 | 215 | -25 |
NET INCOME FROM CONTINUING OPERATIONS | 51 | 233 | 218 | 542 |
Discontinued operations (Note 16) | 7 | 5 | 14 | 11 |
NET INCOME (LOSS) | 58 | 238 | 232 | 553 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | 58 | 238 | 232 | 553 |
Pension and OPEB prior service costs | -5 | -4 | -15 | -1 |
Amortized loss (gain) on derivative hedges | 0 | 0 | 0 | 0 |
Change in unrealized gain on available-for-sale securities | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | -5 | -4 | -15 | -1 |
Income taxes (benefits) on other comprehensive income (loss) | -2 | -2 | -6 | -1 |
Net other comprehensive income (loss) | -3 | -2 | -9 | 0 |
COMPREHENSIVE INCOME (LOSS) | 55 | 236 | 223 | 553 |
FGCO | Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 0 | 0 | 0 | 0 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -2 | -2 | -4 | -5 |
FGCO | Non-Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 4 | 3 | 6 | 5 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -24 | -27 | -79 | -79 |
Nuclear Generation Corp | ' | ' | ' | ' |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | 440 | 395 | 1,337 | 1,262 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 55 | 55 | 154 | 154 |
Other operating expenses | 114 | 122 | 376 | 410 |
Provision for depreciation | 46 | 41 | 134 | 114 |
General taxes | 5 | 5 | 18 | 16 |
Total operating expenses | 285 | 290 | 879 | 883 |
OPERATING INCOME (LOSS) | 155 | 105 | 458 | 379 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 0 | ' | 0 | ' |
Investment income | -1 | 37 | 3 | 49 |
Miscellaneous income, including net income from equity investees | 0 | 0 | 0 | 0 |
Capitalized interest | 8 | 8 | 26 | 24 |
Total other income (expense) | -7 | 29 | -18 | 34 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 148 | 134 | 440 | 413 |
INCOME TAXES (BENEFITS) | 28 | 59 | 138 | 124 |
NET INCOME FROM CONTINUING OPERATIONS | 120 | 75 | 302 | 289 |
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 |
NET INCOME (LOSS) | 120 | 75 | 302 | 289 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | 120 | 75 | 302 | 289 |
Pension and OPEB prior service costs | 0 | 0 | 0 | 0 |
Amortized loss (gain) on derivative hedges | 0 | 0 | 0 | 0 |
Change in unrealized gain on available-for-sale securities | 5 | -1 | 2 | 12 |
Other comprehensive income (loss) | 5 | -1 | 2 | 12 |
Income taxes (benefits) on other comprehensive income (loss) | 3 | 0 | 1 | 5 |
Net other comprehensive income (loss) | 2 | -1 | 1 | 7 |
COMPREHENSIVE INCOME (LOSS) | 122 | 74 | 303 | 296 |
Nuclear Generation Corp | Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 65 | 67 | 197 | 189 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -1 | -1 | -5 | -3 |
Nuclear Generation Corp | Non-Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 0 | 0 | 0 | 0 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -13 | -15 | -42 | -36 |
Eliminations | ' | ' | ' | ' |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | -943 | -978 | -2,869 | -2,971 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 0 | 0 | 0 | 0 |
Other operating expenses | 13 | 12 | 37 | 37 |
Provision for depreciation | 0 | -1 | -3 | -4 |
General taxes | 0 | 0 | 0 | 0 |
Total operating expenses | -929 | -967 | -2,834 | -2,938 |
OPERATING INCOME (LOSS) | -14 | -11 | -35 | -33 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 0 | ' | 0 | ' |
Investment income | -4 | -5 | -11 | -15 |
Miscellaneous income, including net income from equity investees | -178 | -316 | -537 | -848 |
Capitalized interest | 0 | 0 | 0 | 0 |
Total other income (expense) | -162 | -300 | -491 | -801 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | -176 | -311 | -526 | -834 |
INCOME TAXES (BENEFITS) | 2 | 2 | 8 | 8 |
NET INCOME FROM CONTINUING OPERATIONS | -178 | -313 | -534 | -842 |
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 |
NET INCOME (LOSS) | -178 | -313 | -534 | -842 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | -178 | -313 | -534 | -842 |
Pension and OPEB prior service costs | 5 | 4 | 15 | 1 |
Amortized loss (gain) on derivative hedges | 0 | 0 | 0 | 0 |
Change in unrealized gain on available-for-sale securities | -5 | 1 | -2 | -12 |
Other comprehensive income (loss) | 0 | 5 | 13 | -11 |
Income taxes (benefits) on other comprehensive income (loss) | -1 | 2 | 5 | -4 |
Net other comprehensive income (loss) | 1 | 3 | 8 | -7 |
COMPREHENSIVE INCOME (LOSS) | -177 | -310 | -526 | -849 |
Eliminations | Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | -942 | -978 | -2,868 | -2,971 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | 5 | 5 | 12 | 15 |
Eliminations | Non-Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 0 | 0 | 0 | 0 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | 15 | 16 | 45 | 47 |
FES | ' | ' | ' | ' |
Consolidating Statements of Income | ' | ' | ' | ' |
Revenues | 1,679 | 1,550 | 4,655 | 4,511 |
OPERATING EXPENSES: | ' | ' | ' | ' |
Fuel | 304 | 303 | 936 | 978 |
Other operating expenses | 339 | 342 | 1,105 | 1,028 |
Provision for depreciation | 80 | 70 | 231 | 200 |
General taxes | 35 | 35 | 106 | 104 |
Total operating expenses | 1,614 | 1,383 | 4,534 | 4,116 |
OPERATING INCOME (LOSS) | 65 | 167 | 121 | 395 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Loss on debt redemptions | 0 | 0 | -103 | 0 |
Investment income | -3 | 38 | -4 | 50 |
Miscellaneous income, including net income from equity investees | 21 | 1 | 29 | 25 |
Capitalized interest | 9 | 9 | 28 | 27 |
Total other income (expense) | -9 | -6 | -183 | -45 |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | 56 | 161 | -62 | 350 |
INCOME TAXES (BENEFITS) | 23 | 65 | -19 | 139 |
NET INCOME FROM CONTINUING OPERATIONS | 33 | 96 | -43 | 211 |
Discontinued operations (Note 16) | 7 | 5 | 14 | 11 |
NET INCOME (LOSS) | 40 | 101 | -29 | 222 |
OTHER COMPREHENSIVE INCOME (LOSS): | ' | ' | ' | ' |
NET INCOME | 40 | 101 | -29 | 222 |
Pension and OPEB prior service costs | -5 | -5 | -16 | -2 |
Amortized loss (gain) on derivative hedges | -1 | -2 | -3 | -6 |
Change in unrealized gain on available-for-sale securities | 5 | -2 | 2 | 11 |
Other comprehensive income (loss) | -1 | -9 | -17 | 3 |
Income taxes (benefits) on other comprehensive income (loss) | -1 | -3 | -7 | 1 |
Net other comprehensive income (loss) | 0 | -6 | -10 | 2 |
COMPREHENSIVE INCOME (LOSS) | 40 | 95 | -39 | 224 |
FES | Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 132 | 131 | 401 | 381 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | -1 | -3 | -7 | -7 |
FES | Non-Affiliates | ' | ' | ' | ' |
OPERATING EXPENSES: | ' | ' | ' | ' |
Purchased power | 724 | 502 | 1,755 | 1,425 |
OTHER INCOME (EXPENSE): | ' | ' | ' | ' |
Interest expense | ($35) | ($51) | ($126) | ($140) |
Supplemental_Guarantor_Informa3
Supplemental Guarantor Information (Details 1) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Dec. 31, 2011 |
In Millions, unless otherwise specified | ||||
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | $222 | $172 | $150 | $202 |
Receivables- | ' | ' | ' | ' |
Customers | 1,579 | 1,614 | ' | ' |
Other Receivables | 231 | 315 | ' | ' |
Materials and supplies, at average cost | 731 | 861 | ' | ' |
Derivatives | 140 | 160 | ' | ' |
Prepayments and other | 262 | 208 | ' | ' |
Total current assets | 3,559 | 3,768 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | 44,089 | 43,210 | ' | ' |
Less - Accumulated provision for depreciation | 13,167 | 12,600 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | 30,922 | 30,610 | ' | ' |
Construction work in progress | 2,301 | 2,293 | ' | ' |
Total net property, plant and equipment | 33,223 | 32,903 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 2,183 | 2,204 | ' | ' |
Other | 876 | 936 | ' | ' |
Total other property and investments | 3,105 | 3,194 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 234 | 0 | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Goodwill | 6,418 | 6,447 | 6,444 | ' |
Other | 1,698 | 1,719 | ' | ' |
Total deferred charges and other assets | 10,262 | 10,541 | ' | ' |
Total assets | 50,383 | 50,406 | 48,738 | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | 1,889 | 1,999 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Accrued taxes | 401 | 543 | ' | ' |
Derivatives | 105 | 126 | ' | ' |
Other | 872 | 1,038 | ' | ' |
Total current liabilities | 7,955 | 7,605 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | 12,544 | 13,084 | ' | ' |
Long-term debt and other long-term obligations | 15,291 | 15,179 | ' | ' |
Total capitalization | 27,838 | 28,272 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 866 | 892 | ' | ' |
Accumulated deferred income taxes | 6,603 | 6,616 | ' | ' |
Asset retirement obligations | 1,834 | 1,599 | ' | ' |
Retirement benefits | 3,104 | 3,080 | ' | ' |
Other | 1,716 | 1,836 | ' | ' |
Total noncurrent liabilities | 14,590 | 14,529 | ' | ' |
Total liabilities and capitalization | 50,383 | 50,406 | ' | ' |
FES | ' | ' | ' | ' |
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ' | ' | ' | ' |
Customers | 524 | 483 | ' | ' |
Affiliated companies | 420 | 232 | ' | ' |
Other Receivables | 76 | 56 | ' | ' |
Notes receivable from affiliated companies | 337 | 366 | ' | ' |
Materials and supplies, at average cost | 64 | 66 | ' | ' |
Derivatives | 139 | 158 | ' | ' |
Prepayments and other | 61 | 38 | ' | ' |
Total current assets | 1,621 | 1,399 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | 104 | 91 | ' | ' |
Less - Accumulated provision for depreciation | 26 | 32 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | 78 | 59 | ' | ' |
Construction work in progress | 21 | 34 | ' | ' |
Total net property, plant and equipment | 99 | 93 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 0 | 0 | ' | ' |
Investment in affiliated companies | 5,503 | 4,972 | ' | ' |
Other | 1 | 0 | ' | ' |
Total other property and investments | 5,504 | 4,972 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 0 | ' | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Accumulated deferred income tax benefits | 16 | 0 | ' | ' |
Customer intangibles | 99 | 110 | ' | ' |
Goodwill | 23 | 24 | ' | ' |
Property taxes | 0 | 0 | ' | ' |
Unamortized sale and leaseback costs | 0 | 0 | ' | ' |
Derivatives | 65 | 99 | ' | ' |
Other | 174 | 160 | ' | ' |
Total deferred charges and other assets | 377 | 393 | ' | ' |
Total assets | 7,601 | 6,857 | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | 1 | 1 | ' | ' |
Short-term borrowings | 0 | 0 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Affiliated companies | 643 | 748 | ' | ' |
Other | 88 | 63 | ' | ' |
Accrued taxes | 7 | 126 | ' | ' |
Derivatives | 103 | 124 | ' | ' |
Other | 46 | 71 | ' | ' |
Total current liabilities | 1,584 | 1,491 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | 5,229 | 3,763 | ' | ' |
Long-term debt and other long-term obligations | 712 | 1,482 | ' | ' |
Total capitalization | 5,941 | 5,245 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 0 | 0 | ' | ' |
Accumulated deferred income taxes | 0 | 28 | ' | ' |
Asset retirement obligations | 0 | 0 | ' | ' |
Retirement benefits | 27 | 26 | ' | ' |
Derivatives | 22 | 37 | ' | ' |
Other | 27 | 30 | ' | ' |
Total noncurrent liabilities | 76 | 121 | ' | ' |
Total liabilities and capitalization | 7,601 | 6,857 | ' | ' |
FES | Affiliates | ' | ' | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Short-term borrowings | 696 | 358 | ' | ' |
FGCO | ' | ' | ' | ' |
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | 2 | 3 | 3 | 7 |
Receivables- | ' | ' | ' | ' |
Customers | 0 | 0 | ' | ' |
Affiliated companies | 445 | 417 | ' | ' |
Other Receivables | 22 | 19 | ' | ' |
Notes receivable from affiliated companies | 163 | 7 | ' | ' |
Materials and supplies, at average cost | 161 | 231 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Prepayments and other | 37 | 39 | ' | ' |
Total current assets | 830 | 716 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | 6,068 | 5,899 | ' | ' |
Less - Accumulated provision for depreciation | 1,928 | 1,915 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | 4,140 | 3,984 | ' | ' |
Construction work in progress | 115 | 230 | ' | ' |
Total net property, plant and equipment | 4,255 | 4,214 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 0 | 0 | ' | ' |
Investment in affiliated companies | 0 | 0 | ' | ' |
Other | 10 | 12 | ' | ' |
Total other property and investments | 10 | 12 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 121 | ' | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Accumulated deferred income tax benefits | 169 | 313 | ' | ' |
Customer intangibles | 0 | 0 | ' | ' |
Goodwill | 0 | 0 | ' | ' |
Property taxes | 14 | 14 | ' | ' |
Unamortized sale and leaseback costs | 0 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 242 | 194 | ' | ' |
Total deferred charges and other assets | 425 | 521 | ' | ' |
Total assets | 5,641 | 5,463 | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | 366 | 586 | ' | ' |
Short-term borrowings | 4 | 4 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Affiliated companies | 386 | 143 | ' | ' |
Other | 125 | 96 | ' | ' |
Accrued taxes | 17 | 25 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 72 | 148 | ' | ' |
Total current liabilities | 1,284 | 1,348 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | 2,010 | 1,787 | ' | ' |
Long-term debt and other long-term obligations | 1,873 | 2,009 | ' | ' |
Total capitalization | 3,883 | 3,796 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 0 | 0 | ' | ' |
Accumulated deferred income taxes | 0 | 0 | ' | ' |
Asset retirement obligations | 176 | 29 | ' | ' |
Retirement benefits | 228 | 215 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 70 | 75 | ' | ' |
Total noncurrent liabilities | 474 | 319 | ' | ' |
Total liabilities and capitalization | 5,641 | 5,463 | ' | ' |
FGCO | Affiliates | ' | ' | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Short-term borrowings | 314 | 346 | ' | ' |
Nuclear Generation Corp | ' | ' | ' | ' |
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ' | ' | ' | ' |
Customers | 0 | 0 | ' | ' |
Affiliated companies | 285 | 478 | ' | ' |
Other Receivables | 25 | 16 | ' | ' |
Notes receivable from affiliated companies | 764 | 607 | ' | ' |
Materials and supplies, at average cost | 214 | 208 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Prepayments and other | 6 | 10 | ' | ' |
Total current assets | 1,294 | 1,319 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | 6,719 | 6,391 | ' | ' |
Less - Accumulated provision for depreciation | 2,882 | 2,646 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | 3,837 | 3,745 | ' | ' |
Construction work in progress | 980 | 877 | ' | ' |
Total net property, plant and equipment | 4,817 | 4,622 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 1,270 | 1,283 | ' | ' |
Investment in affiliated companies | 0 | 0 | ' | ' |
Other | 0 | 0 | ' | ' |
Total other property and investments | 1,270 | 1,283 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 0 | ' | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Accumulated deferred income tax benefits | 0 | 0 | ' | ' |
Customer intangibles | 0 | 0 | ' | ' |
Goodwill | 0 | 0 | ' | ' |
Property taxes | 22 | 22 | ' | ' |
Unamortized sale and leaseback costs | 0 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 14 | 5 | ' | ' |
Total deferred charges and other assets | 36 | 27 | ' | ' |
Total assets | 7,417 | 7,251 | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | 514 | 537 | ' | ' |
Short-term borrowings | 0 | 0 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Affiliated companies | 378 | 583 | ' | ' |
Other | 0 | 0 | ' | ' |
Accrued taxes | 37 | 20 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 22 | 15 | ' | ' |
Total current liabilities | 951 | 1,155 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | 3,469 | 3,165 | ' | ' |
Long-term debt and other long-term obligations | 789 | 834 | ' | ' |
Total capitalization | 4,258 | 3,999 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 0 | 0 | ' | ' |
Accumulated deferred income taxes | 770 | 714 | ' | ' |
Asset retirement obligations | 983 | 936 | ' | ' |
Retirement benefits | 0 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 455 | 447 | ' | ' |
Total noncurrent liabilities | 2,208 | 2,097 | ' | ' |
Total liabilities and capitalization | 7,417 | 7,251 | ' | ' |
Nuclear Generation Corp | Affiliates | ' | ' | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Short-term borrowings | 0 | 0 | ' | ' |
Eliminations | ' | ' | ' | ' |
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Receivables- | ' | ' | ' | ' |
Customers | 0 | 0 | ' | ' |
Affiliated companies | -631 | -748 | ' | ' |
Other Receivables | 0 | 0 | ' | ' |
Notes receivable from affiliated companies | -1,010 | -704 | ' | ' |
Materials and supplies, at average cost | 0 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Prepayments and other | 1 | 0 | ' | ' |
Total current assets | -1,640 | -1,452 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | -383 | -384 | ' | ' |
Less - Accumulated provision for depreciation | -187 | -185 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | -196 | -199 | ' | ' |
Construction work in progress | 0 | 0 | ' | ' |
Total net property, plant and equipment | -196 | -199 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 0 | 0 | ' | ' |
Investment in affiliated companies | -5,503 | -4,972 | ' | ' |
Other | 0 | 0 | ' | ' |
Total other property and investments | -5,503 | -4,972 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 0 | ' | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Accumulated deferred income tax benefits | -185 | -313 | ' | ' |
Customer intangibles | 0 | 0 | ' | ' |
Goodwill | 0 | 0 | ' | ' |
Property taxes | 0 | 0 | ' | ' |
Unamortized sale and leaseback costs | 161 | 119 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | -162 | -106 | ' | ' |
Total deferred charges and other assets | -186 | -300 | ' | ' |
Total assets | -7,525 | -6,923 | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | -22 | -22 | ' | ' |
Short-term borrowings | 0 | 0 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Affiliated companies | -631 | -748 | ' | ' |
Other | 0 | 0 | ' | ' |
Accrued taxes | -19 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 36 | 46 | ' | ' |
Total current liabilities | -1,646 | -1,428 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | -5,479 | -4,952 | ' | ' |
Long-term debt and other long-term obligations | -1,196 | -1,207 | ' | ' |
Total capitalization | -6,675 | -6,159 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 866 | 892 | ' | ' |
Accumulated deferred income taxes | -71 | -227 | ' | ' |
Asset retirement obligations | 0 | 0 | ' | ' |
Retirement benefits | 0 | 0 | ' | ' |
Derivatives | 0 | 0 | ' | ' |
Other | 1 | -1 | ' | ' |
Total noncurrent liabilities | 796 | 664 | ' | ' |
Total liabilities and capitalization | -7,525 | -6,923 | ' | ' |
Eliminations | Affiliates | ' | ' | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Short-term borrowings | -1,010 | -704 | ' | ' |
FES | ' | ' | ' | ' |
CURRENT ASSETS: | ' | ' | ' | ' |
Cash and cash equivalents | 2 | 3 | 3 | 7 |
Receivables- | ' | ' | ' | ' |
Customers | 524 | 483 | ' | ' |
Affiliated companies | 519 | 379 | ' | ' |
Other Receivables | 123 | 91 | ' | ' |
Notes receivable from affiliated companies | 254 | 276 | ' | ' |
Materials and supplies, at average cost | 439 | 505 | ' | ' |
Derivatives | 139 | 158 | ' | ' |
Prepayments and other | 105 | 87 | ' | ' |
Total current assets | 2,105 | 1,982 | ' | ' |
PROPERTY, PLANT AND EQUIPMENT: | ' | ' | ' | ' |
In service | 12,508 | 11,997 | ' | ' |
Less - Accumulated provision for depreciation | 4,649 | 4,408 | ' | ' |
Property, plant and equipment in service net of accumulated provision for depreciation | 7,859 | 7,589 | ' | ' |
Construction work in progress | 1,116 | 1,141 | ' | ' |
Total net property, plant and equipment | 8,975 | 8,730 | ' | ' |
INVESTMENTS: | ' | ' | ' | ' |
Nuclear plant decommissioning trusts | 1,270 | 1,283 | ' | ' |
Investment in affiliated companies | 0 | 0 | ' | ' |
Other | 11 | 12 | ' | ' |
Total other property and investments | 1,281 | 1,295 | ' | ' |
ASSETS HELD FOR SALE, NET (NOTE 16): | 121 | 0 | ' | ' |
DEFERRED CHARGES AND OTHER ASSETS: | ' | ' | ' | ' |
Accumulated deferred income tax benefits | 0 | 0 | ' | ' |
Customer intangibles | 99 | 110 | ' | ' |
Goodwill | 23 | 24 | ' | ' |
Property taxes | 36 | 36 | ' | ' |
Unamortized sale and leaseback costs | 161 | 119 | ' | ' |
Derivatives | 65 | 99 | ' | ' |
Other | 268 | 253 | ' | ' |
Total deferred charges and other assets | 652 | 641 | ' | ' |
Total assets | 13,134 | 12,648 | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Currently payable long-term debt | 859 | 1,102 | ' | ' |
Short-term borrowings | 4 | 4 | ' | ' |
Accounts payable- | ' | ' | ' | ' |
Affiliated companies | 776 | 726 | ' | ' |
Other | 213 | 159 | ' | ' |
Accrued taxes | 42 | 171 | ' | ' |
Derivatives | 103 | 124 | ' | ' |
Other | 176 | 280 | ' | ' |
Total current liabilities | 2,173 | 2,566 | ' | ' |
CAPITALIZATION: | ' | ' | ' | ' |
Total equity | 5,229 | 3,763 | ' | ' |
Long-term debt and other long-term obligations | 2,178 | 3,118 | ' | ' |
Total capitalization | 7,407 | 6,881 | ' | ' |
NONCURRENT LIABILITIES: | ' | ' | ' | ' |
Deferred gain on sale and leaseback transaction | 866 | 892 | ' | ' |
Accumulated deferred income taxes | 699 | 515 | ' | ' |
Asset retirement obligations | 1,159 | 965 | ' | ' |
Retirement benefits | 255 | 241 | ' | ' |
Derivatives | 22 | 37 | ' | ' |
Other | 553 | 551 | ' | ' |
Total noncurrent liabilities | 3,554 | 3,201 | ' | ' |
Total liabilities and capitalization | 13,134 | 12,648 | ' | ' |
FES | Affiliates | ' | ' | ' | ' |
CURRENT LIABILITIES: | ' | ' | ' | ' |
Short-term borrowings | $0 | $0 | ' | ' |
Supplemental_Guarantor_Informa4
Supplemental Guarantor Information (Details 2) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Jun. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 |
FES | FES | FGCO | FGCO | Nuclear Generation Corp | Nuclear Generation Corp | Eliminations | Eliminations | FES | FES | FES | |||||
Consolidated Statements of Cash Flows [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net cash provided from operating activities | ' | ' | $1,671 | $1,276 | ($1,018) | ($971) | $712 | $683 | $705 | $799 | ($10) | ($10) | ' | $389 | $501 |
New Financing- | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term debt | ' | ' | 2,745 | 660 | ' | 0 | ' | 317 | ' | 243 | ' | 0 | ' | 0 | 560 |
Short-term borrowings, net | ' | ' | 1,435 | 1,604 | 338 | 982 | 0 | 49 | 0 | 0 | -338 | -1,028 | ' | 0 | 3 |
Equity contribution from parent | ' | ' | ' | ' | 1,500 | ' | 0 | ' | 0 | ' | 0 | ' | 1,500 | 1,500 | 0 |
Redemptions and Repayments- | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Long-term debt | ' | ' | -2,662 | -870 | -769 | 0 | -352 | -169 | -68 | -87 | 10 | 10 | ' | -1,179 | -246 |
Short-term borrowings, net | ' | ' | ' | ' | 0 | 0 | -32 | 0 | 0 | -32 | 32 | 32 | ' | 0 | 0 |
Tender premiums | ' | ' | -110 | 0 | -67 | ' | 0 | ' | 0 | ' | 0 | ' | ' | -67 | 0 |
Other | ' | ' | -64 | -42 | -3 | -1 | -4 | -6 | ' | -2 | ' | 0 | ' | -7 | -9 |
Net cash provided from (used for) financing activities | ' | ' | 654 | 662 | 999 | 981 | -388 | 191 | -68 | 122 | -296 | -986 | ' | 247 | 308 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property additions | -548 | -775 | -1,960 | -1,686 | -9 | -10 | -192 | -175 | -276 | -350 | 0 | 0 | ' | -477 | -535 |
Nuclear fuel | ' | ' | -159 | -207 | 0 | 0 | 0 | 0 | -159 | -207 | 0 | 0 | ' | -159 | -207 |
Proceeds from asset sales | ' | ' | ' | ' | 0 | 0 | 21 | 17 | 0 | 0 | 0 | 0 | ' | 21 | 17 |
Sales of investment securities held in trusts | ' | ' | 1,545 | 2,133 | 0 | 0 | 0 | 0 | 650 | 1,167 | 0 | 0 | ' | 650 | 1,167 |
Purchases of investment securities held in trusts | ' | ' | -1,567 | -2,188 | 0 | 0 | 0 | 0 | -694 | -1,194 | 0 | 0 | ' | -694 | -1,194 |
Loans to affiliated companies, net | ' | ' | ' | ' | 28 | 1 | -156 | -715 | -156 | -337 | 306 | 996 | ' | 22 | -55 |
Other | ' | ' | 3 | -23 | 0 | -1 | 2 | -5 | -2 | 0 | 0 | 0 | ' | 0 | -6 |
Net cash used for investing activities | ' | ' | -2,275 | -1,990 | 19 | -10 | -325 | -878 | -637 | -921 | 306 | 996 | ' | -637 | -813 |
Net change in cash and cash equivalents | ' | ' | 50 | -52 | 0 | 0 | -1 | -4 | 0 | 0 | 0 | 0 | ' | -1 | -4 |
Cash and cash equivalents at beginning of period | ' | ' | 172 | 202 | 0 | 0 | 3 | 7 | 0 | 0 | 0 | 0 | ' | 3 | 7 |
Cash and cash equivalents at end of period | $222 | $150 | $222 | $150 | $0 | $0 | $2 | $3 | $0 | $0 | $0 | $0 | ' | $2 | $3 |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | $4,036 | $4,052 | $11,270 | $11,778 | ' | ||||
Internal revenues | 0 | 0 | 0 | 2 | ' | ||||
Total revenues | 4,036 | [1] | 4,052 | [1] | 11,270 | [1] | 11,780 | [1] | ' |
Depreciation and amortization | 628 | 333 | 1,352 | 1,032 | ' | ||||
Investment income | 5 | 39 | 8 | 63 | ' | ||||
Interest expense | 257 | 230 | 771 | 750 | ' | ||||
Income taxes (benefits) | 77 | 307 | 129 | 650 | ' | ||||
Income from continuing operations | 209 | 422 | 233 | 908 | ' | ||||
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 | ' | ||||
NET INCOME (LOSS) | 218 | 425 | 250 | 919 | ' | ||||
Total assets | 50,383 | 48,738 | 50,383 | 48,738 | 50,406 | ||||
Total goodwill | 6,418 | 6,444 | 6,418 | 6,444 | 6,447 | ||||
Property additions | 548 | 775 | 1,960 | 1,686 | ' | ||||
Regulated Distribution | ' | ' | ' | ' | ' | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | 2,340 | 2,483 | 6,593 | 6,976 | ' | ||||
Internal revenues | 0 | 0 | 0 | 0 | ' | ||||
Total revenues | 2,340 | 2,483 | 6,593 | 6,976 | ' | ||||
Depreciation and amortization | 460 | 193 | 882 | 618 | ' | ||||
Investment income | 14 | 20 | 41 | 62 | ' | ||||
Interest expense | 134 | 136 | 404 | 405 | ' | ||||
Income taxes (benefits) | 50 | 168 | 284 | 355 | ' | ||||
Income from continuing operations | 85 | 286 | 474 | 603 | ' | ||||
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 | ' | ||||
NET INCOME (LOSS) | 85 | 286 | 474 | 603 | ' | ||||
Total assets | 27,030 | 26,122 | 27,030 | 26,122 | ' | ||||
Total goodwill | 5,025 | 5,025 | 5,025 | 5,025 | 5,025 | ||||
Property additions | 261 | 308 | 980 | 751 | ' | ||||
Regulated Transmission | ' | ' | ' | ' | ' | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | 190 | 187 | 546 | 557 | ' | ||||
Internal revenues | 0 | 0 | 0 | 0 | ' | ||||
Total revenues | 190 | 187 | 546 | 557 | ' | ||||
Depreciation and amortization | 31 | 28 | 91 | 86 | ' | ||||
Investment income | 0 | 0 | 0 | 1 | ' | ||||
Interest expense | 23 | 24 | 68 | 70 | ' | ||||
Income taxes (benefits) | 32 | 35 | 93 | 101 | ' | ||||
Income from continuing operations | 54 | 59 | 156 | 171 | ' | ||||
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 | ' | ||||
NET INCOME (LOSS) | 54 | 59 | 156 | 171 | ' | ||||
Total assets | 4,953 | 4,519 | 4,953 | 4,519 | ' | ||||
Total goodwill | 526 | 526 | 526 | 526 | ' | ||||
Property additions | 105 | 47 | 291 | 169 | ' | ||||
Competitive Energy Services | ' | ' | ' | ' | ' | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | 1,573 | 1,462 | 4,350 | 4,465 | ' | ||||
Internal revenues | 196 | 209 | 588 | 686 | ' | ||||
Total revenues | 1,769 | 1,671 | 4,938 | 5,151 | ' | ||||
Depreciation and amortization | 125 | 102 | 347 | 303 | ' | ||||
Investment income | -5 | 36 | -6 | 48 | ' | ||||
Interest expense | 53 | 73 | 187 | 209 | ' | ||||
Income taxes (benefits) | 47 | 74 | -189 | 165 | ' | ||||
Income from continuing operations | 68 | 126 | -317 | 284 | ' | ||||
Discontinued operations (Note 16) | 9 | 3 | 17 | 11 | ' | ||||
NET INCOME (LOSS) | 77 | 129 | -300 | 295 | ' | ||||
Total assets | 17,809 | 16,846 | 17,809 | 16,846 | ' | ||||
Total goodwill | 867 | 893 | 867 | 893 | 896 | ||||
Property additions | 162 | 412 | 630 | 715 | ' | ||||
Other/Corporate | ' | ' | ' | ' | ' | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | -31 | -31 | -89 | -78 | ' | ||||
Internal revenues | 0 | 0 | 0 | 0 | ' | ||||
Total revenues | -31 | -31 | -89 | -78 | ' | ||||
Depreciation and amortization | 12 | 9 | 32 | 25 | ' | ||||
Investment income | 3 | -2 | 6 | -1 | ' | ||||
Interest expense | 47 | -3 | 112 | 66 | ' | ||||
Income taxes (benefits) | -44 | -8 | -55 | -49 | ' | ||||
Income from continuing operations | 0 | 0 | 0 | 0 | ' | ||||
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 | ' | ||||
NET INCOME (LOSS) | -10 | -13 | -92 | -82 | ' | ||||
Total assets | 591 | 1,251 | 591 | 1,251 | ' | ||||
Total goodwill | 0 | 0 | 0 | 0 | ' | ||||
Property additions | 20 | 8 | 59 | 51 | ' | ||||
Reconciling Adjustments | ' | ' | ' | ' | ' | ||||
Segment Financial Information | ' | ' | ' | ' | ' | ||||
External revenues | -36 | -49 | -130 | -142 | ' | ||||
Internal revenues | -196 | -209 | -588 | -684 | ' | ||||
Total revenues | -232 | -258 | -718 | -826 | ' | ||||
Depreciation and amortization | 0 | 1 | 0 | 0 | ' | ||||
Investment income | -7 | -15 | -33 | -47 | ' | ||||
Interest expense | 0 | 0 | 0 | 0 | ' | ||||
Income taxes (benefits) | -8 | 38 | -4 | 78 | ' | ||||
Income from continuing operations | 2 | -49 | -80 | -150 | ' | ||||
Discontinued operations (Note 16) | 0 | 0 | 0 | 0 | ' | ||||
NET INCOME (LOSS) | 12 | -36 | 12 | -68 | ' | ||||
Total assets | 0 | 0 | 0 | 0 | ' | ||||
Total goodwill | 0 | 0 | 0 | 0 | ' | ||||
Property additions | $0 | $0 | $0 | $0 | ' | ||||
[1] | Includes excise tax collections of $117 million and $123 million in the three months ended SeptemberB 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended SeptemberB 30, 2013 and 2012, respectively. |
Segment_Information_Details_Te
Segment Information (Details Textuals) | 9 Months Ended | ||||
Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 09, 2013 | Oct. 09, 2013 | |
Regulated Distribution | Competitive Energy Services | Competitive Energy Services | Subsequent Event | Subsequent Event | |
Customers | MW | Unregulated Plants Expected to be Closed by 9/1/2012 | Regulated Distribution | Regulated Distribution | |
Companies | MW | MW | Harrison and Pleasants | ||
sqmi | MW | ||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' |
Number of existing utility operating companies | 10 | ' | ' | ' | ' |
Number of customers served by utility operating companies | 6,000,000 | ' | ' | ' | ' |
Number of square miles in service area | 65,000 | ' | ' | ' | ' |
Megawatts of net demonstrated capacity of competitive segment | ' | 15,000 | ' | 4,000 | 1,476 |
Megawatt capacity of plants expected to be closed | ' | ' | 885 | ' | ' |
Plant Capacity Planned for Deactivation | ' | 2,080 | ' | ' | ' |
Discontinued_Operations_and_As1
Discontinued Operations and Assets Held for Sale (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
In Millions, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' | ' | ' | ' | ' |
Assets Held-for-sale, Long Lived | $234 | ' | $234 | ' | $0 |
Disposal Group, Including Discontinued Operation, Goodwill | 29 | ' | 29 | ' | ' |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 12 | 5 | 26 | 19 | ' |
Disposal Group, Including Discontinued Operation, Revenue | 11 | 6 | 24 | 24 | ' |
FES | ' | ' | ' | ' | ' |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ' | ' | ' | ' | ' |
Assets Held-for-sale, Long Lived | 121 | ' | 121 | ' | 0 |
Disposal Group, Including Discontinued Operation, Goodwill | 1 | ' | 1 | ' | ' |
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax | 12 | 8 | 22 | 17 | ' |
Disposal Group, Including Discontinued Operation, Revenue | $10 | $8 | $22 | $18 | ' |