Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended |
Dec. 31, 2013 | |
Entity Registrant Name | 'EXELON CORP |
Entity Central Index Key | '0001109357 |
Document Type | '10-K |
Document Period End Date | 31-Dec-13 |
Amendment Flag | 'false |
Document Fiscal Year Focus | '2013 |
Document Fiscal Period Focus | 'FY |
Current Fiscal Year End Date | '--12-31 |
Entity Well-known Seasoned Issuer | 'Yes |
Entity Voluntary Filers | 'No |
Entity Current Reporting Status | 'Yes |
Entity Filer Category | 'Large Accelerated Filer |
Entity Common Stock Shares Outstanding | 857,419,806 |
Entity Public Float | $59,092,745,316 |
Exelon Generation Co L L C [Member] | ' |
Entity Registrant Name | 'EXELON GENERATION CO LLC |
Entity Central Index Key | '0001168165 |
Entity Filer Category | 'Non-accelerated Filer |
Commonwealth Edison Co [Member] | ' |
Entity Registrant Name | 'COMMONWEALTH EDISON CO |
Entity Central Index Key | '0000022606 |
Entity Filer Category | 'Non-accelerated Filer |
Entity Common Stock Shares Outstanding | 127,016,904 |
PECO Energy Co [Member] | ' |
Entity Registrant Name | 'PECO ENERGY CO |
Entity Central Index Key | '0000078100 |
Entity Filer Category | 'Non-accelerated Filer |
Entity Common Stock Shares Outstanding | 170,478,507 |
Baltimore Gas and Electric Company [Member] | ' |
Entity Registrant Name | 'BALTIMORE GAS AND ELECTRIC |
Entity Central Index Key | '0000009466 |
Entity Common Stock Shares Outstanding | 1,000 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations and Comprehensive Income (Unaudited) (USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Operating revenues [Abstract] | ' | ' | ' |
Operating revenues from affiliates | ' | $48 | $9 |
Revenues | 24,888 | 23,489 | 19,063 |
Operating expenses | ' | ' | ' |
Purchased power | 9,468 | 9,121 | 7,130 |
Operating and maintenance | 7,270 | 7,961 | 5,184 |
Operating and maintenance for regulatory required programs | ' | ' | ' |
Depreciation and amortization | 2,153 | 1,881 | 1,347 |
Taxes other than income | 1,095 | 1,019 | 785 |
Total operating expenses | 21,242 | 21,018 | 14,583 |
Loss on equity method investments | 10 | -91 | -1 |
Operating income | 3,656 | 2,380 | 4,479 |
Other income and deductions | ' | ' | ' |
Interest expense | -1,315 | -891 | -701 |
Interest expense to affiliates, net | -41 | -37 | -25 |
Other, net | 473 | 346 | 203 |
Total other income and deductions | -883 | -582 | -523 |
Income before income taxes | 2,773 | 1,798 | 3,956 |
Income taxes | 1,044 | 627 | 1,457 |
Income from continuing operations | ' | ' | ' |
Discontinued operations | ' | ' | ' |
Income from discontinued operations, net | ' | ' | ' |
Net income | 1,729 | 1,171 | 2,499 |
Net income (loss) attributable to noncontrolling interests and preferred security dividends | -10 | -11 | -4 |
Net income on common stock | 1,719 | 1,160 | 2,495 |
Pension and non-pension postretirement benefit plans: | ' | ' | ' |
Prior service benefit reclassified to periodic benefit cost, net of tax | 0 | -1 | 5 |
Actuarial loss reclassified to periodic cost, net of tax | -208 | -168 | -136 |
Transition obligation reclassified to periodic cost, net of tax | 0 | -2 | -4 |
Pension and non-pension postretirement benefit plans valuation adjustment | 669 | -371 | -250 |
Change in unrealized gain (loss) on cash-flow hedges | -248 | -120 | 88 |
Change in unrealized income (loss) on equity investments | 106 | 1 | 0 |
Change in unrealized income (loss) on foreign currency translation | -10 | 0 | 0 |
Change in unrealized gain (loss) on marketable securities | 2 | 2 | 0 |
Other comprehensive income (loss) | 727 | -317 | -27 |
Comprehensive income | 2,456 | 854 | 2,472 |
Average shares of common stock outstanding: | ' | ' | ' |
Basic | 856 | 816 | 663 |
Diluted | 860 | 819 | 665 |
Earnings per average common share - basic | ' | ' | ' |
Income from continuing operations | $2.01 | $1.42 | $3.76 |
Earnings per average common share - diluted | ' | ' | ' |
Net income | $2 | $1.42 | $3.75 |
Dividends per common share | $1.46 | $2.10 | $2.10 |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Operating revenues [Abstract] | ' | ' | ' |
Operating revenues | 14,207 | 12,735 | 9,286 |
Operating revenues from affiliates | 1,423 | 1,702 | 1,161 |
Revenues | 15,630 | 14,437 | 10,447 |
Operating expenses | ' | ' | ' |
Purchased power and fuel from affiliate | 1,270 | 1,044 | 138 |
Purchased power | 6,927 | 6,017 | 3,451 |
Operating and maintenance | 3,960 | 4,398 | 2,827 |
Operating and maintenance from affiliate | 574 | 630 | 321 |
Depreciation and amortization | 856 | 768 | 570 |
Taxes other than income | 389 | 369 | 264 |
Total operating expenses | 13,976 | 13,226 | 7,571 |
Loss on equity method investments | 10 | -91 | -1 |
Operating income | 1,664 | 1,120 | 2,875 |
Other income and deductions | ' | ' | ' |
Interest expense | -298 | -226 | -170 |
Interest expense to affiliates, net | -59 | -75 | ' |
Other, net | 368 | 239 | 122 |
Total other income and deductions | 11 | -62 | -48 |
Income before income taxes | 1,675 | 1,058 | 2,827 |
Income taxes | 615 | 500 | 1,056 |
Discontinued operations | ' | ' | ' |
Net income | 1,060 | 558 | 1,771 |
Income (Loss) attributable to noncontrolling interest | 10 | 4 | ' |
Net income on membership interest | 1,070 | 562 | 1,771 |
Pension and non-pension postretirement benefit plans: | ' | ' | ' |
Change in unrealized gain (loss) on cash-flow hedges | -398 | -403 | -98 |
Change in unrealized income (loss) on equity investments | 107 | 1 | ' |
Change in unrealized income (loss) on foreign currency translation | -10 | ' | ' |
Change in unrealized gain (loss) on marketable securities | 2 | ' | ' |
Other comprehensive income (loss) | -299 | -402 | -98 |
Comprehensive income | 761 | 156 | 1,673 |
Commonwealth Edison Co [Member] | ' | ' | ' |
Operating revenues [Abstract] | ' | ' | ' |
Operating revenues | 4,461 | 5,441 | 6,054 |
Operating revenues from affiliates | 3 | 2 | 2 |
Revenues | 4,464 | 5,443 | 6,056 |
Operating expenses | ' | ' | ' |
Purchased power | 662 | 1,518 | 2,382 |
Purchased power from affiliate | 512 | 789 | 653 |
Operating and maintenance | 1,211 | 1,182 | 1,031 |
Operating and maintenance from affiliate | 157 | 163 | 158 |
Depreciation and amortization | 669 | 610 | 554 |
Taxes other than income | 299 | 295 | 296 |
Total operating expenses | 3,510 | 4,557 | 5,074 |
Loss on equity method investments | 0 | 0 | 0 |
Operating income | 954 | 886 | 982 |
Other income and deductions | ' | ' | ' |
Interest expense | -566 | -294 | -330 |
Interest expense to affiliates, net | -13 | -13 | -15 |
Other, net | 26 | 39 | 29 |
Total other income and deductions | -553 | -268 | -316 |
Income before income taxes | 401 | 618 | 666 |
Income taxes | 152 | 239 | 250 |
Discontinued operations | ' | ' | ' |
Net income | 249 | 379 | 416 |
Pension and non-pension postretirement benefit plans: | ' | ' | ' |
Change in unrealized gain (loss) on marketable securities | 0 | 1 | 0 |
Other comprehensive income (loss) | 0 | 1 | 0 |
Comprehensive income | 249 | 380 | 416 |
PECO Energy Co [Member] | ' | ' | ' |
Operating revenues [Abstract] | ' | ' | ' |
Operating revenues | 3,099 | 3,183 | 3,715 |
Operating revenues from affiliates | 1 | 3 | 5 |
Revenues | 3,100 | 3,186 | 3,720 |
Operating expenses | ' | ' | ' |
Purchased power | 908 | 842 | 1,369 |
Purchased power from affiliate | 392 | 533 | 495 |
Operating and maintenance | 647 | 698 | 698 |
Operating and maintenance from affiliate | 101 | 111 | 96 |
Depreciation and amortization | 228 | 217 | 202 |
Taxes other than income | 158 | 162 | 205 |
Total operating expenses | 2,434 | 2,563 | 3,065 |
Operating income | 666 | 623 | 655 |
Other income and deductions | ' | ' | ' |
Interest expense | -103 | -111 | -122 |
Interest expense to affiliates, net | -12 | -12 | -12 |
Other, net | 6 | 8 | 14 |
Total other income and deductions | -109 | -115 | -120 |
Income before income taxes | 557 | 508 | 535 |
Income taxes | 162 | 127 | 146 |
Discontinued operations | ' | ' | ' |
Net income | 395 | 381 | 389 |
Preferred security dividends | -7 | -4 | -4 |
Net income on common stock | 388 | 377 | 385 |
Pension and non-pension postretirement benefit plans: | ' | ' | ' |
Change in unrealized gain (loss) on marketable securities | 0 | 1 | 0 |
Other comprehensive income (loss) | 0 | 1 | 0 |
Comprehensive income | 395 | 382 | 389 |
Baltimore Gas and Electric Company [Member] | ' | ' | ' |
Operating revenues [Abstract] | ' | ' | ' |
Operating revenues | 3,052 | 2,725 | 3,060 |
Operating revenues from affiliates | 13 | 10 | 8 |
Revenues | 3,065 | 2,735 | 3,068 |
Operating expenses | ' | ' | ' |
Purchased power and fuel | 969 | 973 | 1,245 |
Purchased power from affiliate | 452 | 396 | 348 |
Operating and maintenance | 551 | 622 | 530 |
Operating and maintenance from affiliate | 83 | 106 | 150 |
Depreciation and amortization | 348 | 298 | 274 |
Taxes other than income | 213 | 208 | 207 |
Total operating expenses | 2,616 | 2,603 | 2,754 |
Operating income | 449 | 132 | 314 |
Other income and deductions | ' | ' | ' |
Interest expense | -106 | -128 | -113 |
Interest expense to affiliates, net | -16 | -16 | -16 |
Other, net | 17 | 23 | 26 |
Total other income and deductions | -105 | -121 | -103 |
Income before income taxes | 344 | 11 | 211 |
Income taxes | 134 | 7 | 75 |
Discontinued operations | ' | ' | ' |
Net income | 210 | 4 | 136 |
Preferred security dividends | -13 | -13 | -13 |
Net income on common stock | 197 | -9 | 123 |
Pension and non-pension postretirement benefit plans: | ' | ' | ' |
Comprehensive income | $210 | $4 | $136 |
Consolidated_Statements_of_Ope1
Consolidated Statements of Operations and Comprehensive Income (Unaudited) (Parenthetical) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Prior service costs | ' | $1 | ($4) |
Actuarial loss reclassified to periodic cost, taxes | ' | 110 | 93 |
Transition obligation | ' | 2 | 2 |
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | ' | -237 | -171 |
Change in unrealized gain (loss) on cash flow hedges, taxes | ' | -68 | 39 |
Change in unrealized gain (loss) on marketable securities, taxes | ' | -1 | 0 |
Change in unrealized gain (loss) on equity investments taxes | ' | 1 | 0 |
Actuarial loss reclassified to periodic cost, net of tax | -208 | -168 | -136 |
Other Comprehensive Income (Loss), Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service (Cost) Credit, Net of Tax | 0 | 1 | -5 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Transition (Asset) Obligation, Net of Tax | 0 | -2 | -4 |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Gain on disposal of discontinued operations, taxes | 0 | 0 | 0 |
Change in unrealized gain (loss) on cash flow hedges, taxes | -262 | -262 | -64 |
Change in unrealized gain (loss) on equity investments taxes | ' | -1 | ' |
Commonwealth Edison Co [Member] | ' | ' | ' |
Change in unrealized gain (loss) on marketable securities, taxes | 0 | 0 | 0 |
PECO Energy Co [Member] | ' | ' | ' |
Change in unrealized gain (loss) on marketable securities, taxes | 0 | 0 | 0 |
Amortization of realized gain on settled cash flow swaps, taxes | $0 | $0 | $0 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Unaudited) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Cash flows from operating activities | ' | ' | ' |
Net income | $1,729 | $1,171 | $2,499 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' | ' |
Depreciation, amortization and accretion | 3,779 | 4,079 | 2,316 |
Impairment of assets held for sale | ' | 272 | ' |
Deferred income taxes and amortization of investment tax credits | 119 | 615 | 1,457 |
Net fair value changes related to derivatives | -445 | -604 | 291 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -170 | -157 | 14 |
Other non-cash operating activities | 876 | 1,383 | 770 |
Changes in assets and liabilities: | ' | ' | ' |
Accounts receivable | -97 | 243 | 57 |
Inventories | -100 | 26 | -58 |
Accounts payable, accrued expenses and other current liabilities | -90 | -632 | -254 |
Option premiums paid, net | -36 | -114 | -3 |
Counterparty collateral (posted) received, net | 215 | 135 | -344 |
Income taxes | 883 | 544 | 492 |
Pension and non-pension postretirement benefit contributions | -422 | -462 | -2,360 |
Other assets and liabilities | 102 | -368 | -24 |
Net cash flows provided by operating activities | 6,343 | 6,131 | 4,853 |
Cash flows from investing activities | ' | ' | ' |
Capital expenditures | -5,395 | -5,789 | -4,042 |
Changes in intercompany money pool | -44 | ' | ' |
Proceeds from nuclear decommissioning trust fund sales | 4,217 | 7,265 | 6,139 |
Investment in nuclear decommissioning trust funds | -4,450 | -7,483 | -6,332 |
Cash acquired from Constellation | ' | 964 | ' |
Proceeds from sale of Three Maryland Generating Stations | 32 | 371 | ' |
Acquisitions | ' | -21 | -387 |
Distribution From Affiliates | 115 | ' | ' |
Proceeds from sales of investments | 22 | 28 | 6 |
Purchases of investments | -4 | -13 | -4 |
Change in restricted cash | -43 | -34 | -3 |
Other investing activities | 112 | 136 | 20 |
Net cash flows provided by (used in) investing activities | -5,394 | -4,576 | -4,603 |
Cash flows from financing activities | ' | ' | ' |
Payment of accounts receivable agreement | -210 | -15 | ' |
Changes in short-term debt | 332 | -197 | 161 |
Redemption of preferred securities | -93 | ' | ' |
Issuance of long-term debt | 2,055 | 2,027 | 1,199 |
Retirement or repayment of long-term debt | -1,589 | -1,145 | -789 |
Dividends paid on common stock | -1,249 | -1,716 | -1,393 |
Proceeds from employee stock plans | 47 | 72 | 38 |
Other financing activities | -119 | -111 | -62 |
Net cash flows used in financing activities | -826 | -1,085 | -846 |
Increase (decrease) in cash and cash equivalents | 123 | 470 | -596 |
Cash and cash equivalents at beginning of period | 1,486 | 1,016 | 1,612 |
Cash and cash equivalents at end of period | 1,609 | 1,486 | 1,016 |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Cash flows from operating activities | ' | ' | ' |
Net income | 1,060 | 558 | 1,771 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' | ' |
Depreciation, amortization and accretion | 2,559 | 2,966 | 1,539 |
Impairment of assets held for sale | 0 | 272 | 0 |
Deferred income taxes and amortization of investment tax credits | 315 | 408 | 551 |
Net fair value changes related to derivatives | -448 | -611 | 291 |
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | -170 | -157 | 14 |
Other non-cash operating activities | 414 | 537 | 421 |
Changes in assets and liabilities: | ' | ' | ' |
Accounts receivable | 109 | 248 | -122 |
Receivables from and payables to affiliates, net | 2 | 39 | 208 |
Inventories | -88 | 31 | -47 |
Accounts payable, accrued expenses and other current liabilities | -109 | -499 | 34 |
Option premiums paid, net | -36 | -114 | -3 |
Counterparty collateral (posted) received, net | 162 | 95 | -410 |
Income taxes | 402 | 114 | 193 |
Pension and non-pension postretirement benefit contributions | -149 | -178 | -1,070 |
Other assets and liabilities | -136 | -128 | -57 |
Net cash flows provided by operating activities | 3,887 | 3,581 | 3,313 |
Cash flows from investing activities | ' | ' | ' |
Capital expenditures | -2,752 | -3,554 | -2,491 |
Proceeds from nuclear decommissioning trust fund sales | 4,217 | 7,265 | 6,139 |
Investment in nuclear decommissioning trust funds | -4,450 | -7,483 | -6,332 |
Proceeds from sale of long-lived assets | 32 | 371 | ' |
Cash acquired from Constellation | 0 | 708 | ' |
Acquisitions | 0 | -21 | -387 |
Distribution From Affiliates | 115 | ' | ' |
Change in restricted cash | -64 | 4 | 0 |
Other investing activities | 30 | 81 | -6 |
Net cash flows provided by (used in) investing activities | -2,916 | -2,629 | -3,077 |
Cash flows from financing activities | ' | ' | ' |
Changes in short-term debt | 13 | -52 | ' |
Issuance of long-term debt | 854 | 1,076 | 0 |
Retirement or repayment of long-term debt | -570 | -145 | -2 |
Distribution to member | -625 | -1,626 | -172 |
Contributions from member | 26 | 48 | 30 |
Other financing activities | -82 | -78 | -52 |
Net cash flows used in financing activities | -384 | -777 | -196 |
Increase (decrease) in cash and cash equivalents | 587 | 175 | 40 |
Cash and cash equivalents at beginning of period | 671 | 496 | 456 |
Cash and cash equivalents at end of period | 1,258 | 671 | 496 |
Commonwealth Edison Co [Member] | ' | ' | ' |
Cash flows from operating activities | ' | ' | ' |
Net income | 249 | 379 | 416 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' | ' |
Depreciation, amortization and accretion | 669 | 610 | 554 |
Deferred income taxes and amortization of investment tax credits | -57 | 270 | 700 |
Other non-cash operating activities | 28 | 252 | 184 |
Changes in assets and liabilities: | ' | ' | ' |
Accounts receivable | -12 | 24 | 5 |
Receivables from and payables to affiliates, net | -12 | -18 | -287 |
Inventories | -18 | -11 | -9 |
Accounts payable, accrued expenses and other current liabilities | 74 | 59 | -84 |
Counterparty collateral (posted) received, net | 53 | 40 | 66 |
Income taxes | 178 | 9 | 223 |
Pension and non-pension postretirement benefit contributions | -122 | -138 | -977 |
Other assets and liabilities | 188 | -142 | 45 |
Net cash flows provided by operating activities | 1,218 | 1,334 | 836 |
Cash flows from investing activities | ' | ' | ' |
Capital expenditures | -1,433 | -1,246 | -1,028 |
Proceeds from sales of investments | 7 | 28 | 6 |
Purchases of investments | -4 | -13 | -4 |
Change in restricted cash | 2 | ' | ' |
Other investing activities | 45 | 19 | 19 |
Net cash flows provided by (used in) investing activities | -1,387 | -1,212 | -1,007 |
Cash flows from financing activities | ' | ' | ' |
Changes in short-term debt | 184 | 0 | 0 |
Issuance of long-term debt | 350 | 350 | 1,199 |
Retirement or repayment of long-term debt | -252 | -450 | -537 |
Contributions from parent | 176 | ' | ' |
Dividends paid on common stock | -220 | -105 | -300 |
Other financing activities | -1 | -7 | -7 |
Net cash flows used in financing activities | 61 | -212 | 355 |
Increase (decrease) in cash and cash equivalents | -108 | -90 | 184 |
Cash and cash equivalents at beginning of period | 144 | 234 | 50 |
Cash and cash equivalents at end of period | 36 | 144 | 234 |
PECO Energy Co [Member] | ' | ' | ' |
Cash flows from operating activities | ' | ' | ' |
Net income | 395 | 381 | 389 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' | ' |
Depreciation, amortization and accretion | 228 | 217 | 202 |
Deferred income taxes and amortization of investment tax credits | 20 | 37 | 253 |
Other non-cash operating activities | 108 | 125 | 100 |
Changes in assets and liabilities: | ' | ' | ' |
Accounts receivable | -79 | -14 | 225 |
Receivables from and payables to affiliates, net | -18 | 13 | -217 |
Inventories | 2 | 21 | 0 |
Accounts payable, accrued expenses and other current liabilities | 41 | -47 | 34 |
Income taxes | 87 | 174 | -45 |
Pension and non-pension postretirement benefit contributions | -31 | -45 | -137 |
Other assets and liabilities | -6 | 16 | 14 |
Net cash flows provided by operating activities | 747 | 878 | 818 |
Cash flows from investing activities | ' | ' | ' |
Capital expenditures | -537 | -422 | -481 |
Changes in intercompany money pool | 0 | 82 | -82 |
Change in restricted cash | -2 | 2 | -2 |
Other investing activities | 8 | 10 | 8 |
Net cash flows provided by (used in) investing activities | -531 | -328 | -557 |
Cash flows from financing activities | ' | ' | ' |
Changes in short-term debt | -210 | -15 | 0 |
Redemption of preferred securities | -93 | 0 | 0 |
Issuance of long-term debt | 550 | 350 | 0 |
Retirement or repayment of long-term debt | -300 | -375 | -250 |
Retirement of long-term debt of variable interest entity | 0 | 0 | 0 |
Retirement of long-term debt to financing affiliates | 0 | 0 | 0 |
Contributions from parent | 27 | 9 | 18 |
Dividends paid on common stock | -332 | -343 | -348 |
Dividends paid on preferred securities | -1 | -4 | -4 |
Repayment of receivable from parent | 0 | 0 | 0 |
Other financing activities | -2 | -4 | -5 |
Net cash flows used in financing activities | -361 | -382 | -589 |
Increase (decrease) in cash and cash equivalents | -145 | 168 | -328 |
Cash and cash equivalents at beginning of period | 362 | 194 | 522 |
Cash and cash equivalents at end of period | 217 | 362 | 194 |
Baltimore Gas and Electric Company [Member] | ' | ' | ' |
Cash flows from operating activities | ' | ' | ' |
Net income | 210 | 4 | 136 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | ' | ' | ' |
Depreciation, amortization and accretion | 348 | 298 | 274 |
Deferred income taxes and amortization of investment tax credits | 125 | 104 | 145 |
Other non-cash operating activities | 153 | 193 | 129 |
Changes in assets and liabilities: | ' | ' | ' |
Accounts receivable | -127 | -45 | 60 |
Receivables from and payables to affiliates, net | -14 | 26 | -44 |
Inventories | 1 | 25 | -10 |
Accounts payable, accrued expenses and other current liabilities | -14 | -33 | -21 |
Income taxes | -33 | 14 | 35 |
Pension and non-pension postretirement benefit contributions | -24 | -16 | -67 |
Other assets and liabilities | -64 | -85 | -161 |
Net cash flows provided by operating activities | 561 | 485 | 476 |
Cash flows from investing activities | ' | ' | ' |
Capital expenditures | -587 | -582 | -592 |
Changes in intercompany money pool | ' | ' | 0 |
Proceeds from sales of investments | 0 | 0 | 0 |
Change in restricted cash | 2 | 0 | 0 |
Other investing activities | 14 | 9 | ' |
Net cash flows provided by (used in) investing activities | -571 | -573 | -592 |
Cash flows from financing activities | ' | ' | ' |
Changes in short-term debt | 135 | 0 | 0 |
Issuance of long-term debt | 300 | 250 | 300 |
Retirement or repayment of long-term debt | -467 | -173 | -82 |
Contributions from parent | 0 | 66 | 0 |
Dividends paid on common stock | 0 | 0 | ' |
Dividends paid on preferred securities | -13 | -13 | -13 |
Other financing activities | -3 | -2 | -5 |
Net cash flows used in financing activities | -48 | 128 | 115 |
Increase (decrease) in cash and cash equivalents | -58 | 40 | -1 |
Cash and cash equivalents at beginning of period | 89 | 49 | 50 |
Cash and cash equivalents at end of period | $31 | $89 | $49 |
Consolidated_Balance_Sheets_Un
Consolidated Balance Sheets (Unaudited) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Current assets | ' | ' | ||
CashAndCashEquivalentsNonvariableInterestEntity | $1,547 | $1,411 | ||
Cash and cash equivalents | 1,609 | 1,486 | ||
Cash and cash equivalents of variable interest entities | 62 | 75 | ||
Restricted cash and investments | 87 | 86 | ||
Restricted cash and investments of variable interest entity | 80 | 47 | ||
Accounts receivable, net | ' | ' | ||
Customer | 2,721 | 2,795 | ||
Other | 1,175 | 1,141 | ||
Accounts receivable of variable interest entities | 260 | 292 | ||
Mark-to-market derivative assets | 727 | 938 | ||
Unamortized energy contracts assets | 374 | 886 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 276 | 246 | ||
Materials and supplies | 829 | 768 | ||
Deferred income taxes | 573 | 131 | ||
Regulatory assets | 760 | 764 | ||
Other | 666 | 560 | ||
Total current assets | 10,137 | 10,140 | ||
Property, plant and equipment, net | 47,330 | 45,186 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 5,910 | 6,497 | ||
Nuclear decommissioning trust funds | 8,071 | 7,248 | ||
Investments | 1,165 | 1,184 | ||
Investments in affiliates | 22 | 22 | ||
Investment in CENG | 1,925 | 1,849 | ||
Goodwill | 2,625 | 2,625 | ||
Receivable from affiliate | ' | 2,039 | ||
Mark-to-market derivative assets | 607 | 937 | ||
Pledged assets for Zion Station decommissioning | 458 | 614 | ||
Unamortized energy contracts assets | 710 | 1,073 | ||
Other | 964 | 1,128 | ||
Deferred income taxes | 0 | 58 | ||
Total deferred debits and other assets | 22,457 | 23,235 | ||
Total assets | 79,924 | 78,561 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 341 | ' | ||
Short-term notes payable - accounts receivable agreement | ' | 210 | ||
Long-term debt due within one year | 1,424 | 975 | ||
Long-term debt of variable interest entities due within one year | 85 | 72 | ||
Accounts payable | 2,314 | 2,378 | ||
Accounts payable of variable interest entities | 170 | 202 | ||
Accrued expenses | 1,633 | 1,796 | ||
Payables to affiliates | ' | 112 | ||
Deferred income taxes | 40 | 58 | ||
Regulatory liabilities | 327 | 368 | ||
Mark-to-market derivative liabilities | 159 | 352 | ||
Unamortized energy contract liabilities | 261 | 455 | ||
Other | 858 | 813 | ||
Total current liabilities | 7,728 | 7,791 | ||
Long-term debt | 17,325 | 17,190 | ||
Long-term debt of variable financing trusts | 298 | 648 | ||
Long-term debt of variable interest entity | 648 | 508 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 12,905 | 11,551 | ||
Asset retirement obligations | 5,194 | 5,074 | ||
Pension obligations | 1,876 | 3,428 | ||
Non-pension postretirement benefit obligations | 2,190 | 2,662 | ||
Spent nuclear fuel obligation | 1,021 | 1,020 | ||
Regulatory liabilities | 4,388 | 3,981 | ||
Mark-to-market derivative liabilities | 300 | 281 | ||
Unamortized energy contract liabilities | 266 | 528 | ||
Payable for Zion Station decommissioning | 305 | 432 | ||
Other | 2,540 | 1,650 | ||
Total deferred credits and other liabilities | 30,985 | 30,607 | ||
Total liabilities | 56,984 | 56,744 | ||
Commitments and contingencies | 0 | 0 | ||
Preferred securities | ' | 87 | ||
Shareholders' equity | ' | ' | ||
Common stock | 16,741 | 16,632 | ||
Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively) | -2,327 | -2,327 | ||
Retained earnings | 10,358 | 9,893 | ||
Accumulated other comprehensive income (loss), net | -2,040 | -2,767 | ||
Total shareholders' equity | 22,732 | 21,431 | ||
BGE preference stock not subject to mandatory redemption | 193 | 193 | ||
Noncontrolling interest | 15 | 106 | ||
Total equity | 22,940 | 21,730 | ||
Total liabilities and shareholders' equity | 79,924 | 78,561 | ||
Member's equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | -2,040 | -2,767 | ||
Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 99 | 97 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | 1,423 | 1,406 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Current assets | ' | ' | ||
CashAndCashEquivalentsNonvariableInterestEntity | 1,196 | 596 | ||
Cash and cash equivalents | 1,258 | 671 | ||
Cash and cash equivalents of variable interest entities | 62 | 75 | ||
Restricted cash and cash equivalents | 19 | 0 | ||
Restricted cash and investments of variable interest entity | 52 | 16 | ||
Accounts receivable, net | ' | ' | ||
Customer | 1,429 | 1,482 | ||
Other | 353 | 472 | ||
Accounts receivable of variable interest entities | 260 | 292 | ||
Mark-to-market derivative assets | 727 | 938 | ||
Mark-to-market derivative assets with affiliates | ' | 226 | ||
Receivables from affiliates | 108 | 141 | ||
Unamortized energy contracts assets | 374 | 886 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 164 | 130 | ||
Materials and supplies | 671 | 626 | ||
Deferred income taxes | 475 | ' | ||
Receivable from Exelon intercompany money pool | 44 | ' | ||
Other | 505 | 331 | ||
Total current assets | 6,439 | 6,211 | ||
Property, plant and equipment, net | 20,111 | 19,531 | ||
Deferred debits and other assets | ' | ' | ||
Nuclear decommissioning trust funds | 8,071 | 7,248 | ||
Investments | 400 | 420 | ||
Investment in CENG | 1,925 | 1,849 | ||
Receivable from affiliate | 22 | 22 | ||
Mark-to-market derivative assets | 600 | 924 | ||
Prepaid pension asset | 1,873 | 1,975 | ||
Pledged assets for Zion Station decommissioning | 458 | 614 | ||
Unamortized energy contracts assets | 710 | 1,073 | ||
Other | 645 | 836 | ||
Total deferred debits and other assets | 14,682 | 14,939 | ||
Total assets | 41,232 | 40,681 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 22 | 0 | ||
Long-term debt due within one year | 556 | 24 | ||
Long-term debt of variable interest entities due within one year | 5 | 4 | ||
Accounts payable | 1,152 | 1,326 | ||
Accounts payable of variable interest entities | 170 | 202 | ||
Accrued expenses | 976 | 1,116 | ||
Payables to affiliates | 181 | 213 | ||
Deferred income taxes | 25 | 128 | ||
Mark-to-market derivative liabilities | 142 | 334 | ||
Unamortized energy contract liabilities | 249 | 378 | ||
Other | 389 | 372 | ||
Total current liabilities | 3,867 | 4,097 | ||
Long-term debt | 5,559 | 5,245 | ||
Long-term debt to affiliate | ' | 2,007 | ||
Long-term debt of variable financing trusts | 1,523 | ' | ||
Long-term debt of variable interest entity | 86 | 203 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 6,295 | 5,398 | ||
Asset retirement obligations | 5,047 | 4,938 | ||
Non-pension postretirement benefit obligations | 850 | 755 | ||
Spent nuclear fuel obligation | 1,021 | 1,020 | ||
Payables to affiliates | 2,740 | 2,397 | ||
Mark-to-market derivative liabilities | 120 | 232 | ||
Unamortized energy contract liabilities | 266 | 516 | ||
Payable for Zion Station decommissioning | 305 | 432 | ||
Other | 811 | 776 | ||
Total deferred credits and other liabilities | 17,455 | 16,464 | ||
Total liabilities | 28,490 | 28,016 | ||
Commitments and contingencies | 0 | 0 | ||
Shareholders' equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | 214 | 513 | ||
Noncontrolling interest | 17 | 108 | ||
Member's equity | ' | ' | ||
Membership interest | 8,898 | 8,876 | ||
Undistributed earnings | 3,613 | 3,168 | ||
Accumulated other comprehensive income (loss), net | 214 | 513 | ||
Total member's equity | 12,725 | 12,557 | ||
Total equity | 12,742 | 12,665 | ||
Total liabilities and equity | 41,232 | 40,681 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 36 | 144 | ||
Restricted cash and cash equivalents | 2 | 0 | ||
Accounts receivable, net | ' | ' | ||
Customer | 451 | 539 | ||
Other | 584 | 452 | ||
Receivables from affiliates | 3 | 3 | ||
Inventories, net | ' | ' | ||
Inventories, net | 109 | 91 | ||
Deferred income taxes | 0 | 83 | ||
Counterparty collateral deposited | 0 | 53 | ||
Regulatory assets | 329 | 388 | ||
Other | 29 | 25 | ||
Total current assets | 1,540 | 1,775 | ||
Property, plant and equipment, net | 14,666 | 13,826 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 933 | 666 | ||
Investments | 5 | 8 | ||
Investments in affiliates | 6 | 6 | ||
Goodwill | 2,625 | 2,625 | ||
Receivable from affiliate | 2,469 | 2,039 | ||
Mark-to-market derivative assets | 0 | 0 | ||
Prepaid pension asset | 1,583 | 1,661 | ||
Other | 291 | 299 | ||
Total deferred debits and other assets | 7,912 | 7,304 | ||
Total assets | 24,118 | 22,905 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 184 | 0 | ||
Long-term debt due within one year | 617 | 252 | ||
Accounts payable | 449 | 379 | ||
Accrued expenses | 307 | 295 | ||
Payables to affiliates | 83 | 97 | ||
Customer deposits | 133 | 136 | ||
Regulatory liabilities | 170 | 170 | ||
Mark-to-market derivative liabilities | 17 | 18 | ||
Mark-to-market derivative liabilities with affiliate | 0 | 226 | ||
Other | 72 | 82 | ||
Total current liabilities | 2,048 | 1,655 | ||
Long-term debt | 5,058 | 5,315 | ||
Long-term debt of variable financing trusts | 206 | 206 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 4,116 | 4,272 | ||
Asset retirement obligations | 99 | 99 | ||
Non-pension postretirement benefit obligations | 381 | 273 | ||
Regulatory liabilities | 3,512 | 3,229 | ||
Mark-to-market derivative liabilities | 176 | 49 | ||
Mark-to-market derivative liabilities with affiliate | 0 | 0 | ||
Deferred income taxes | 16 | ' | ||
Other | 994 | 484 | ||
Total deferred credits and other liabilities | 9,278 | 8,406 | ||
Total liabilities | 16,590 | 15,582 | ||
Commitments and contingencies | 0 | 0 | ||
Shareholders' equity | ' | ' | ||
Common stock | 1,588 | 1,588 | ||
Other paid-in capital | 5,190 | 5,014 | ||
Retained earnings | 750 | 721 | ||
Total shareholders' equity | 7,528 | 7,323 | ||
Total liabilities and shareholders' equity | 24,118 | 22,905 | ||
Commonwealth Edison Co [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 78 | 75 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | 1,219 | 1,192 | ||
PECO Energy Co [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 217 | 362 | ||
Restricted cash and cash equivalents | 2 | 0 | ||
Accounts receivable, net | ' | ' | ||
Customer | 360 | 364 | ||
Other | 107 | 161 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 60 | 65 | ||
Materials and supplies | 21 | 19 | ||
Deferred income taxes | 83 | 40 | ||
Receivable from Exelon intercompany money pool | 0 | 0 | ||
Prepaid utility taxes | 3 | 21 | ||
Regulatory assets | 17 | 32 | ||
Other | 36 | 30 | ||
Total current assets | 906 | 1,094 | ||
Property, plant and equipment, net | 6,384 | 6,078 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 1,448 | 1,378 | ||
Investments | 23 | 22 | ||
Investments in affiliates | 8 | 8 | ||
Receivable from affiliate | 447 | 360 | ||
Prepaid pension asset | 363 | 373 | ||
Other | 38 | 40 | ||
Total deferred debits and other assets | 2,327 | 2,181 | ||
Total assets | 9,617 | 9,353 | ||
Current liabilities | ' | ' | ||
Short-term notes payable - accounts receivable agreement | 0 | 210 | ||
Long-term debt due within one year | 250 | 300 | ||
Long-term debt to PECO Energy Transition Trust due within one year | 0 | 0 | ||
Accounts payable | 285 | 244 | ||
Accrued expenses | 106 | 82 | ||
Payables to affiliates | 58 | 76 | ||
Deferred income taxes | 0 | 0 | ||
Customer deposits | 49 | 51 | ||
Regulatory liabilities | 106 | 169 | ||
Mark-to-market derivative liabilities | 0 | 0 | ||
Mark-to-market derivative liabilities with affiliate | 0 | 0 | ||
Other | 37 | 26 | ||
Total current liabilities | 891 | 1,158 | ||
Long-term debt | 1,947 | 1,647 | ||
Long-term debt of variable financing trusts | 184 | [1] | 184 | [1] |
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 2,487 | 2,331 | ||
Asset retirement obligations | 29 | 29 | ||
Non-pension postretirement benefit obligations | 286 | 284 | ||
Regulatory liabilities | 629 | 538 | ||
Mark-to-market derivative liabilities | 0 | 0 | ||
Mark-to-market derivative liabilities with affiliate | 0 | 0 | ||
Other | 99 | 113 | ||
Total deferred credits and other liabilities | 3,530 | 3,295 | ||
Total liabilities | 6,552 | 6,284 | ||
Preferred securities | 0 | 87 | ||
Shareholders' equity | ' | ' | ||
Common stock | 2,415 | 2,388 | ||
Receivable from parent | 0 | 0 | ||
Retained earnings | 649 | 593 | ||
Accumulated other comprehensive income (loss), net | 1 | 1 | ||
Total shareholders' equity | 3,065 | 2,982 | ||
Total liabilities and shareholders' equity | 9,617 | 9,353 | ||
Member's equity | ' | ' | ||
Accumulated other comprehensive income (loss), net | 1 | 1 | ||
PECO Energy Co [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 0 | 0 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | 0 | 0 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Current assets | ' | ' | ||
Cash and cash equivalents | 31 | 89 | ||
Restricted cash and investments of variable interest entity | 28 | 30 | ||
Accounts receivable, net | ' | ' | ||
Customer | 480 | 409 | ||
Other | 114 | 111 | ||
Income taxes receivable | 30 | 3 | ||
Inventories, net | ' | ' | ||
Fossil fuel | 53 | 51 | ||
Materials and supplies | 28 | 31 | ||
Deferred income taxes | 2 | 1 | ||
Prepaid utility taxes | 57 | 57 | ||
Regulatory assets | 181 | 190 | ||
Other | 7 | 8 | ||
Total current assets | 1,011 | 980 | ||
Property, plant and equipment, net | 5,864 | 5,498 | ||
Deferred debits and other assets | ' | ' | ||
Regulatory assets | 524 | 522 | ||
Investments | 5 | 5 | ||
Investments in affiliates | 8 | 8 | ||
Prepaid pension asset | 423 | 467 | ||
Other | 26 | 26 | ||
Deferred income taxes | 0 | ' | ||
Total deferred debits and other assets | 986 | 1,028 | ||
Total assets | 7,861 | 7,506 | ||
Current liabilities | ' | ' | ||
Short-term borrowings | 135 | ' | ||
Long-term debt due within one year | 0 | 400 | ||
Long-term debt of variable interest entities due within one year | 70 | 67 | ||
Accounts payable | 270 | 235 | ||
Accrued expenses | 111 | 102 | ||
Payables to affiliates | 55 | 69 | ||
Deferred income taxes | 27 | 0 | ||
Customer deposits | 76 | 71 | ||
Regulatory liabilities | 48 | 29 | ||
Other | 35 | 7 | ||
Total current liabilities | 827 | 980 | ||
Long-term debt | 1,746 | 1,446 | ||
Long-term debt of variable financing trusts | 258 | 258 | ||
Long-term debt of variable interest entity | 195 | 265 | ||
Deferred credits and other liabilities | ' | ' | ||
Deferred income taxes and unamortized investment tax credits | 1,773 | 1,658 | ||
Asset retirement obligations | 19 | 8 | ||
Non-pension postretirement benefit obligations | 217 | 229 | ||
Regulatory liabilities | 204 | 214 | ||
Other | 67 | 90 | ||
Total deferred credits and other liabilities | 2,280 | 2,199 | ||
Total liabilities | 5,306 | 5,148 | ||
Shareholders' equity | ' | ' | ||
Common stock | 1,360 | 1,360 | ||
Retained earnings | 1,005 | 808 | ||
Total shareholders' equity | 2,365 | 2,168 | ||
BGE preference stock not subject to mandatory redemption | 190 | 190 | ||
Total equity | 2,555 | 2,358 | ||
Total liabilities and shareholders' equity | 7,861 | 7,506 | ||
Baltimore Gas and Electric Company [Member] | Removal Costs [Member] | ' | ' | ||
Current liabilities | ' | ' | ||
Regulatory liabilities | 21 | 22 | ||
Deferred credits and other liabilities | ' | ' | ||
Regulatory liabilities | $204 | $214 | ||
[1] | Amounts owed to this financing trust are recorded as debt to financing trusts within PECO's Consolidated Balance Sheets. |
Consolidated_Balance_Sheets_Un1
Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, except Share data, unless otherwise specified | ||
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | $0 | ' |
Shareholders' equity | ' | ' |
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 857,290,484 | 854,781,389 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
PECO Energy Co [Member] | ' | ' |
Accounts Receivable [Abstract] | ' | ' |
Gross accounts receivable pledged as collateral | $0 | $289 |
Shareholders' equity | ' | ' |
Common stock, shares authorized | 500,000,000 | ' |
Common stock, shares outstanding | 170,478,507 | 170,478,507 |
Baltimore Gas and Electric Company [Member] | ' | ' |
Shareholders' equity | ' | ' |
Common stock, shares authorized | 175,000,000 | ' |
Common stock, shares outstanding | 1,000 | 1,000 |
Consolidated_Statement_of_Chan
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (USD $) | Total | Common Stock [Member] | Treasury Stock | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Preference Stock Not Subject To Mandatory Redemption [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||
In Millions, except Share data in Thousands | Undistributed Earnings [Member] | Membership Interest [Member] | Accumulated Other Comprehensive (Loss) Income, Net | Noncontrolling Interest | Common Stock [Member] | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Common Stock [Member] | Retained Earnings | Accumulated Other Comprehensive (Loss) Income, Net | Other Paid-In Capital | Retained Deficit Unappropriated | Retained Earnings Appropriated | Undistributed Earnings [Member] | Common Stock [Member] | Membership Interest [Member] | Retained Earnings | Preference Stock Not Subject To Mandatory Redemption [Member] | |||||||||||||
Beginning Balance at Dec. 31, 2009 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Noncontrolling interest in income of consolidated entity | ' | ' | ' | ' | ' | ($3) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2010 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,883 | 2,361 | 522 | 0 | 6,910 | 1,588 | ' | -1 | 4,992 | -1,639 | 1,970 | ' | 779 | 1,294 | 2,073 | ' | ' | ||
Ending Balance at Dec. 31, 2010 | 13,563 | 9,006 | -2,327 | 9,304 | -2,423 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,263 | ' | ' | ' | ' | 190 | ||
Beginning Balance at Dec. 31, 2010 | ' | 696,589 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2010 | ' | ' | ' | ' | ' | ' | ' | 7,177 | 2,633 | 3,526 | 1,013 | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 2,499 | ' | ' | 2,495 | ' | ' | 4 | 1,771 | 1,771 | ' | ' | ' | 389 | ' | 389 | ' | 416 | ' | 416 | ' | ' | ' | ' | 136 | 136 | ' | 136 | ' | ' | ||
Net income on common stock | 2,495 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 385 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 123 | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | ' | 861 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | ' | 662 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Appropriation of retained earnings for future dividends | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | -416 | 416 | ' | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | 76 | 76 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | 25 | 25 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock dividends | -1,744 | ' | ' | -1,744 | ' | ' | ' | ' | ' | ' | ' | ' | -348 | ' | -348 | ' | -300 | ' | ' | ' | ' | ' | -300 | 85 | ' | ' | ' | 85 | ' | ||
Distribution to members | ' | ' | ' | ' | ' | ' | ' | -172 | -172 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from members | ' | ' | ' | ' | ' | ' | ' | 30 | ' | 30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Transfer of AmerGen pension and non-pension postretirement benefit plans to Exelon, net of income taxes | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18 | 18 | ' | ' | 11 | ' | ' | ' | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred security dividends | 4 | ' | ' | ' | ' | ' | 4 | ' | ' | ' | ' | ' | -4 | ' | -4 | ' | ' | ' | ' | ' | ' | ' | ' | 13 | 13 | ' | 13 | ' | ' | ||
Repayment of receivable from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Acquisition of Exelon Wind | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other comprehensive income (loss), net of tax | -27 | ' | ' | ' | -27 | ' | ' | -98 | ' | ' | -98 | ' | 0 | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,938 | 2,379 | 559 | 0 | 7,037 | 1,588 | ' | ' | 5,003 | -1,639 | 2,086 | ' | 817 | ' | 2,111 | ' | ' | ||
Ending Balance at Dec. 31, 2011 | 14,388 | 9,107 | -2,327 | 10,055 | -2,450 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,301 | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2011 | ' | 698,112 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | ' | ' | 8,708 | 4,232 | 3,556 | 915 | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 200 | ' | ' | ' | ' | ' | ' | 168 | ' | ' | ' | ' | 96 | ' | ' | ' | 87 | ' | ' | ' | ' | ' | ' | -33 | ' | ' | ' | ' | ' | ||
Ending Balance at Mar. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,938 | 2,379 | 559 | 0 | 7,037 | 1,588 | ' | -1 | 5,003 | -1,639 | 2,086 | ' | 817 | 1,294 | 2,111 | ' | ' | ||
Beginning Balance at Dec. 31, 2011 | 14,388 | 9,107 | -2,327 | 10,055 | -2,450 | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,301 | ' | ' | ' | ' | 190 | ||
Beginning Balance at Dec. 31, 2011 | ' | 698,112 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2011 | ' | ' | ' | ' | ' | ' | ' | 8,708 | 4,232 | 3,556 | 915 | 5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 1,171 | ' | ' | 1,160 | ' | -3 | 14 | 558 | 562 | ' | ' | -4 | 381 | ' | 381 | ' | 379 | ' | 379 | ' | ' | ' | ' | 4 | 4 | ' | 4 | ' | ' | ||
Net income on common stock | 1,160 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 377 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -9 | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | ' | 2,432 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | ' | 857 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Appropriation of retained earnings for future dividends | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | -379 | 379 | ' | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | 126 | 126 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | 26 | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock dividends | -1,322 | ' | ' | -1,322 | ' | ' | ' | ' | ' | ' | ' | ' | -343 | ' | -343 | ' | -105 | ' | ' | ' | ' | ' | -105 | 0 | 0 | ' | 0 | ' | ' | ||
Common stock issuance - Constellation merger - Shares | 188,124 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock issuance - Constellation merger - Value | 7,365 | 7,365 | ' | ' | ' | ' | ' | 5,264 | ' | 5,264 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Contribution from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 66 | ' | 66 | ' | ' | ' | ||
Distribution to members | ' | ' | ' | ' | ' | ' | ' | -1,626 | -1,626 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from members | ' | ' | ' | ' | ' | ' | ' | 48 | ' | 48 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9 | 9 | ' | ' | 11 | ' | ' | ' | 11 | ' | ' | ' | ' | ' | ' | ' | ' | ||
BGE preference stock acquired | 193 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 193 | ||
Preferred security dividends | 14 | ' | ' | ' | ' | ' | 14 | ' | ' | ' | ' | ' | -4 | ' | -4 | ' | ' | ' | ' | ' | ' | ' | ' | -13 | -13 | ' | -13 | ' | ' | ||
Repayment of receivable from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Acquisition of Exelon Wind | ' | ' | ' | ' | ' | ' | ' | 115 | ' | 8 | ' | 107 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Noncontrolling interest acquired | 114 | 8 | ' | ' | ' | 106 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other comprehensive income (loss), net of tax | -317 | ' | ' | ' | -317 | ' | ' | -402 | ' | ' | -402 | ' | 1 | ' | ' | 1 | 1 | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2012 | 21,431 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,982 | 2,388 | 593 | 1 | 7,323 | 1,588 | ' | 0 | 5,014 | -1,639 | 2,360 | 2,168 | 808 | 1,360 | 2,168 | ' | ' | ||
Ending Balance at Dec. 31, 2012 | 21,730 | 16,632 | -2,327 | 9,893 | -2,767 | 106 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,358 | ' | ' | ' | ' | 190 | ||
Ending Balance at Dec. 31, 2012 | ' | 889,525 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | 193 | 12,665 | 3,168 | 8,876 | 513 | 108 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Sep. 30, 2012 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 378 | ' | ' | ' | ' | ' | ' | 137 | ' | ' | ' | ' | 79 | ' | ' | ' | 160 | ' | ' | ' | ' | ' | ' | 15 | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2012 | 21,431 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,982 | ' | ' | ' | 7,323 | 1,588 | ' | ' | ' | ' | ' | 2,168 | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2012 | 21,730 | ' | -2,327 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,358 | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | ' | 12,665 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | -4 | ' | ' | ' | ' | ' | ' | -18 | ' | ' | ' | ' | 121 | ' | ' | ' | -81 | ' | ' | ' | ' | ' | ' | 77 | ' | ' | ' | ' | ' | ||
Ending Balance at Mar. 31, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | 21,431 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,982 | 2,388 | 593 | 1 | 7,323 | 1,588 | ' | ' | 5,014 | -1,639 | 2,360 | 2,168 | 808 | ' | 2,168 | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | 21,730 | 16,632 | -2,327 | 9,893 | -2,767 | 106 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,358 | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | ' | 889,525 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Dec. 31, 2012 | ' | ' | ' | ' | ' | ' | 193 | 12,665 | 3,168 | 8,876 | 513 | 108 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 1,729 | ' | ' | 1,719 | ' | -10 | 20 | 1,060 | 1,070 | ' | ' | ' | 395 | ' | 395 | ' | 249 | ' | 249 | ' | ' | ' | ' | 210 | 210 | ' | 210 | ' | ' | ||
Net income on common stock | 1,719 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 388 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 197 | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | ' | 1,445 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | 1,064 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Appropriation of retained earnings for future dividends | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | -249 | 249 | ' | ' | ' | ' | ' | ' | ||
Long-term incentive plan activity | 81 | 81 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Employee stock purchase plan issuances | 28 | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Common stock dividends | -1,254 | ' | ' | -1,254 | ' | ' | ' | ' | ' | ' | ' | ' | -332 | ' | -332 | ' | -220 | ' | ' | ' | ' | ' | -220 | ' | ' | ' | ' | ' | ' | ||
Distribution to members | ' | ' | ' | ' | ' | ' | ' | -625 | -625 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from members | ' | ' | ' | ' | ' | ' | ' | 26 | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred stock redemption premium | -6 | ' | ' | ' | ' | ' | -6 | ' | ' | ' | ' | ' | 6 | ' | 6 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Allocation of tax benefit from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 27 | 27 | ' | ' | 176 | ' | ' | ' | 176 | ' | ' | ' | ' | ' | ' | ' | ' | ||
Consolidated VIE dividend to non-controlling interest | -63 | ' | ' | ' | ' | ' | ' | 63 | ' | ' | ' | 63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Preferred security dividends | 14 | ' | ' | ' | ' | ' | 14 | ' | ' | ' | ' | ' | -1 | ' | -1 | ' | ' | ' | ' | ' | ' | ' | ' | -13 | -13 | ' | -13 | ' | ' | ||
Repayment of receivable from parent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Noncontrolling interest acquired | -63 | ' | ' | ' | ' | -63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Other comprehensive income (loss), net of tax | 727 | ' | ' | ' | 727 | [1] | ' | ' | -299 | ' | ' | -299 | [1] | ' | 0 | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Noncontrolling interest in income of consolidated entity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Sale of noncontrolling interest | ' | ' | ' | ' | ' | ' | ' | -3 | ' | -3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
ImpairmentOfLongLivedAssetsToBeDisposedOf | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Deconsolidation of VIE | -18 | ' | ' | ' | ' | -18 | ' | -19 | ' | -1 | ' | -18 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2013 | 22,732 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,065 | 2,415 | 649 | 1 | 7,528 | 1,588 | ' | 0 | 5,190 | -1,639 | 2,389 | 2,365 | 1,005 | 1,360 | 2,365 | ' | ' | ||
Ending Balance at Dec. 31, 2013 | 22,940 | 16,741 | -2,327 | 10,358 | -2,040 | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,555 | ' | ' | ' | ' | 190 | ||
Ending Balance at Dec. 31, 2013 | ' | 892,034 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2013 | ' | ' | ' | ' | ' | ' | 193 | 12,742 | 3,613 | 8,898 | 214 | 17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Beginning Balance at Sep. 30, 2013 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net income | 495 | ' | ' | ' | ' | ' | ' | 269 | ' | ' | ' | ' | 102 | ' | ' | ' | 109 | ' | ' | ' | ' | ' | ' | 47 | ' | ' | ' | ' | ' | ||
Ending Balance at Dec. 31, 2013 | 22,732 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,065 | ' | ' | ' | 7,528 | 1,588 | ' | 0 | ' | ' | ' | 2,365 | ' | 1,360 | ' | ' | ' | ||
Ending Balance at Dec. 31, 2013 | 22,940 | ' | -2,327 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,555 | ' | ' | ' | ' | 190 | ||
Ending Balance at Dec. 31, 2013 | ' | ' | ' | ' | ' | ' | ' | $12,742 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
[1] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Consolidated_Statement_of_Chan1
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' |
Other comprehensive income, income taxes | $468 | ($41) | ($221) |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Other comprehensive income, income taxes | -261 | -64 | -102 |
PECO Energy Co [Member] | ' | ' | ' |
Other comprehensive income, income taxes | 0 | 1 | 0 |
Commonwealth Edison Co [Member] | ' | ' | ' |
Other comprehensive income, income taxes | $0 | $0 | $3 |
Significant_Accounting_Policie
Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Significant Accounting Policies [Line Items] | ' | |||||||||||||||
Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||
1. Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Description of Business (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon's principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation's regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. | ||||||||||||||||
The energy generation business includes: | ||||||||||||||||
Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions. | ||||||||||||||||
The energy delivery businesses include: | ||||||||||||||||
ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago. | ||||||||||||||||
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia. | ||||||||||||||||
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. | ||||||||||||||||
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures. | ||||||||||||||||
Exelon did not apply push-down accounting to BGE and BGE continued to be subject to reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2013, 2012 and 2011 and the financial position as of December 31, 2013 and December 31, 2012. However, for Exelon's consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2013. | ||||||||||||||||
Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. | ||||||||||||||||
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon's corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed. | ||||||||||||||||
Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE's preference stock. Exelon owned none of PECO's preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity, PECO's preferred securities as preferred securities of subsidiary through their redemption in 2013, and BGE's preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters. | ||||||||||||||||
Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in non-controlling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the non-controlling members for certain of these projects. | ||||||||||||||||
ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity. | ||||||||||||||||
Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions. | ||||||||||||||||
For the year ended December 31, 2013, BGE recorded a $2 million correcting adjustment to decrease amortization expense related to regulatory assets that were originally recorded during 2012, an adjustment to decrease income tax expense by $4 million related to the recognition and measurement of regulatory assets that should have been recorded in periods prior to 2013, and a $4 million correcting adjustment to decrease operating and maintenance expense for an overstatement of BGE's life insurance obligation related to post-employment benefits in prior years. For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. In addition, ComEd identified a disclosure adjustment within the renewable energy credits and alternative energy credits section of the 2012 Form 10-K Note 8 – Intangible Assets which has been revised in Note 10 of this year's report. Exelon, ComEd and BGE have concluded these correcting adjustments are not material to its results of operations, cash flows, or financial positions for the years ended December 31, 2013, and December 31, 2012, or any prior period. | ||||||||||||||||
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. | ||||||||||||||||
Use of Estimates (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. | ||||||||||||||||
Reclassifications (Exelon, ComEd, and BGE) | ||||||||||||||||
Certain prior year amounts in Exelon's and BGE's Consolidated Statements of Operations and Cash Flows, and Exelon's, ComEd's, and BGE's Consolidated Balance Sheets have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. | ||||||||||||||||
In 2013, Exelon and BGE identified a presentation errors of $12 million and $16 million on their Statements of Operations and Comprehensive Income, respectively related to its financing trusts within interest expense that is now presented within Interest expense to affiliates, net. Additionally, Exelon identified similar presentation errors of $92 million between Accounts payable, Accrued expenses and Payables to affiliates on its Balance Sheet. Generation identified a related presentation error of $83 million between Accounts payable and Payables to affiliates on its Balance Sheet. BGE identified a related presentation error of $4 million between Accrued expenses and Payables to affiliates on its Balance Sheet. Similar adjustments are also reflected on the related party transactions footnote. | ||||||||||||||||
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) | ||||||||||||||||
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities' costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd's, PECO's or BGE's business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information. | ||||||||||||||||
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order. | ||||||||||||||||
. | ||||||||||||||||
Revenues (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Note 3—Regulatory Matters and Note 6—Accounts Receivable for further information. | ||||||||||||||||
RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Company in the different RTOs and ISOs. | ||||||||||||||||
Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. As ComEd receives full cost recovery for energy procurement and related costs from retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 3—Regulatory Matters and Note 12 – Derivative Financial Instruments for further information. | ||||||||||||||||
Proprietary Trading Activities. Exelon and Generation account for Generation's trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 12 – Derivative Financial Instruments for further information. | ||||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants' Consolidated Balance Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, the Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in interest expense or in other income and deductions (interest income) on their Consolidated Statements of Operations. | ||||||||||||||||
Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14—Income Taxes for further information. | ||||||||||||||||
Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Exelon, Generation, ComEd, PECO and BGE collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23—Supplemental Financial Information for Generation's, ComEd's, PECO's and BGE's utility taxes that are presented on a gross basis. | ||||||||||||||||
Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents. | ||||||||||||||||
Restricted Cash and Investments (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Restricted cash and investments represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2013 and 2012, Exelon Corporate's restricted cash and investments primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, Exelon Corporate has funds restricted for merger commitments. In addition, Exelon Corporate's investments include its direct financing lease investments. As of December 31, 2013, Generation's restricted cash and investments primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2012, Generation's restricted cash primarily included cash at Antelope Valley required for debt service and construction. As of December 31, 2013 and 2012, ComEd's restricted cash primarily represented cash collateral held from suppliers associated with ComEd's REC procurement contracts. As of December 31, 2013, PECO's restricted cash primarily represented funds from the sales of assets that were subject to PECO's mortgage indenture. As of December 31, 2013 and 2012, BGE's restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds. | ||||||||||||||||
Restricted cash and investments not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2013 and 2012, Exelon's and Generation's NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2013, Exelon, Generation, ComEd, PECO and BGE had investments in Rabbi trusts classified as noncurrent assets. | ||||||||||||||||
Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The allowance for uncollectible accounts reflects the Registrants' best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. BGE estimates the allowance for uncollectible accounts on customer receivables by assigning reserve factors for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. ComEd, PECO and BGE customers' accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd's, PECO's and BGE's provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3 —Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd. | ||||||||||||||||
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes the following specific requirements: | ||||||||||||||||
requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE, | ||||||||||||||||
requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and | ||||||||||||||||
requires the entity that consolidates a VIE (the primary beneficiary) to present separately on the face of its balance sheet (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. | ||||||||||||||||
Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities: | ||||||||||||||||
Exelon has presented separately on its Consolidated Balance Sheets, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon's consolidated VIEs for which creditors do not have recourse to Exelon's general credit. | ||||||||||||||||
Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity. | ||||||||||||||||
See Note 2 – Variable Interest Entities for additional information. | ||||||||||||||||
Inventories (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Inventory is recorded at the lower of weighted average cost or market. Provisions are recorded for excess and obsolete inventory. | ||||||||||||||||
Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, propane and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used or sold. | ||||||||||||||||
Materials and Supplies. Materials and supplies inventory generally includes the weighted average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, when installed or used. | ||||||||||||||||
Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations. | ||||||||||||||||
Marketable Securities (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
All marketable securities are reported at fair value. Marketable securities held in the NDT funds, certain Generation Rabbi trust investments and BGE's Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former AmerGen nuclear generating units, the Zion generating station and portions of the Peach Bottom nuclear generating units not subject to a regulatory agreement (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on certain Generation Rabbi trust investments and BGE's Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gains and losses, net of tax, for Generation's, ComEd's and PECO's available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd's and PECO's available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 15— Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 23—Supplemental Financial Information for additional information regarding ComEd's and PECO's regulatory assets and liabilities. | ||||||||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Property, plant and equipment is recorded at original cost. Original cost includes labor, materials and construction overhead. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred. For constructed assets, Exelon capitalizes construction-related direct labor and material costs. ComEd, PECO and BGE also capitalized indirect construction costs including labor and related costs of departments associated with supporting construction activities. | ||||||||||||||||
Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE are accounted for as CIAC. | ||||||||||||||||
For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to operating and maintenance expense as incurred. | ||||||||||||||||
For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd's and BGE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. ComEd's and BGE's actual incurred removal costs are applied against a related regulatory liability. PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. | ||||||||||||||||
Generation's oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred. | ||||||||||||||||
See Note 7—Property, Plant and Equipment, Note 9—Jointly Owned Electric Utility Plant and Note 23—Supplemental Financial Information for additional information regarding property, plant and equipment. | ||||||||||||||||
Nuclear Fuel (Exelon and Generation) | ||||||||||||||||
The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. The estimated disposal cost of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22—Commitments and Contingencies for additional information regarding the SNF disposal fee. | ||||||||||||||||
Nuclear Outage Costs (Exelon and Generation) | ||||||||||||||||
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to operating and maintenance expense or capitalized to property, plant and equipment (based on the nature of the activities) in the period incurred. | ||||||||||||||||
New Site Development Costs (Exelon and Generation) | ||||||||||||||||
New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management's determination that the project is economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. At December 31, 2013 and 2012, there were no material capitalized development costs for projects not yet under construction included in Property, plant and equipment, net on Exelon's and Generation's Consolidated Balance Sheets. Approximately $10 million, $4 million and $2 million of costs were expensed by Exelon and Generation for the years ended December 31, 2013, 2012, and 2011, respectively. These costs primarily related to the possible development of new renewable energy projects. | ||||||||||||||||
Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Costs incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year: | ||||||||||||||||
Net unamortized software costs | Exelon | Generation | ComEd | PECO | BGE | |||||||||||
31-Dec-13 | $ | 479 | $ | 129 | $ | 101 | $ | 71 | $ | 155 | ||||||
31-Dec-12 | 499 | 143 | 105 | 63 | 157 | |||||||||||
Amortization of capitalized software costs | Exelon (a) | Generation (a) | ComEd | PECO | BGE (a) | |||||||||||
2013 | $ | 198 | $ | 67 | $ | 52 | $ | 33 | $ | 36 | ||||||
2012 | 208 | 81 | 56 | 30 | 32 | |||||||||||
2011 | 122 | 41 | 50 | 25 | 25 | |||||||||||
__________ | ||||||||||||||||
(a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012 and 2011. | ||||||||||||||||
Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd's and BGE's depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation's operating nuclear generating stations except for Oyster Creek. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations. | ||||||||||||||||
See Note 7—Property, Plant and Equipment for further information regarding depreciation. | ||||||||||||||||
Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations. | ||||||||||||||||
Amortization of regulatory assets is recorded over the recovery period specified in the related legislation or regulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost would have originally been recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income. For income tax related regulatory assets, amortization is generally recorded to Income tax expense in the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||
See Note 3—Regulatory Matters and Note 23—Supplemental Financial Information for additional information regarding Generation's nuclear fuel, Generation's ARC and the amortization of ComEd's, PECO's and BGE's regulatory assets. | ||||||||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years. The liabilities associated with Exelon's non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd's, PECO's, and BGE's accretion, through an increase to regulatory assets. See Note 15—Asset Retirement Obligations for additional information. | ||||||||||||||||
Capitalized Interest and AFUDC (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. | ||||||||||||||||
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. | ||||||||||||||||
The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year: | ||||||||||||||||
Exelon (a) | Generation (a) | ComEd | PECO | BGE (a) | ||||||||||||
2013 | Total incurred interest (b) | $ | 1,423 | $ | 411 | $ | 584 | $ | 117 | $ | 129 | |||||
Capitalized interest | 54 | 54 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 35 | — | 16 | 6 | 13 | |||||||||||
2012 | Total incurred interest (b) | $ | 1,003 | $ | 368 | $ | 310 | $ | 125 | $ | 149 | |||||
Capitalized interest | 67 | 67 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 25 | — | 9 | 6 | 15 | |||||||||||
2011 | Total incurred interest (b) | $ | 783 | $ | 219 | $ | 349 | $ | 138 | $ | 136 | |||||
Capitalized interest | 49 | 49 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 25 | — | 12 | 13 | 22 | |||||||||||
__________ | ||||||||||||||||
(a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010. | ||||||||||||||||
(b) Includes interest expense to affiliates. | ||||||||||||||||
Guarantees (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. | ||||||||||||||||
The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22—Commitments and Contingencies for additional information. | ||||||||||||||||
Asset Impairments (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Cash flows from Generation plant assets are generally evaluated at a regional portfolio level along with cash flows generated from Generation's supply and risk management activities, including cash flows from contracts that are recorded as intangible contract assets and liabilities on the balance sheet. In certain cases generation assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). | ||||||||||||||||
Impairment may occur when the carrying value of the asset or asset group exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. | ||||||||||||||||
Conditions that could have an adverse impact on the expected future cash flows and the fair value of the long-lived assets and asset groups include, among other factors, a deteriorating business climate, including energy prices and market conditions, revisions to regulatory laws, or plans to dispose of a long-lived asset significantly before the end of its useful life. See Note 8 – Impairment of Long-Lived Assets for additional information. | ||||||||||||||||
Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10—Intangible Assets for additional information regarding Exelon's and ComEd's goodwill. | ||||||||||||||||
Equity Method Investments. Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is not temporary in nature. Additionally, if the project in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other than temporary decline in value. | ||||||||||||||||
Direct Financing Lease Investments. Direct financing lease investments represent the estimated residual values of leased coal-fired plants in Georgia and Texas. Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. See Note 8 – Impairment of Long-Lived Assets for additional information. | ||||||||||||||||
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that are not designated or do not qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon's Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. | ||||||||||||||||
For commodity derivative contracts, effective with the date of the merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivatives executed to hedge economic risk for commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company. | ||||||||||||||||
As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12—Derivative Financial Instruments for additional information. | ||||||||||||||||
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation's defined benefit pension and other postretirement benefit plans and defined contribution savings plans. | ||||||||||||||||
The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16—Retirement Benefits for additional discussion of Exelon's accounting for retirement benefits. | ||||||||||||||||
Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation) | ||||||||||||||||
Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, including Generation's 50.01% interest in CENG, in equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment. See Note 5 – Investment in CENG and Note 25—Related Party Transactions for additional discussion of Exelon's and Generation's investment in CENG. | ||||||||||||||||
Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investments and which could result in the recognition of an impairment loss if such investment experiences an other than temporary decline in value. | ||||||||||||||||
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that may affect the Registrants. | ||||||||||||||||
Presentation of Items Reclassified out of Accumulated Other Comprehensive Income | ||||||||||||||||
In February 2013, the FASB issued authoritative guidance requiring entities to present either in the notes or parenthetically on the face of the financial statements, reclassifications from each component of accumulated other comprehensive income and the affected income statement line items. Entities only need to disclose the affected income statement line item for components reclassified to net income in their entirety; otherwise, a cross-reference to the related note should be provided. This guidance was effective for the Registrants for periods beginning after December 15, 2012 and was required to be applied prospectively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 21 – Changes in Accumulated Other Comprehensive Income for the new disclosures. | ||||||||||||||||
Disclosures About Offsetting Assets and Liabilities | ||||||||||||||||
In December 2011 (and amended in January 2013), the FASB issued authoritative guidance requiring entities to disclose both gross and net information about recognized derivative instruments, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing or lending transactions that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The guidance was effective for the Registrants for periods beginning on or after January 1, 2013 and was required to be applied retrospectively. This guidance is primarily applicable to certain derivative transactions for Exelon and Generation. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 12 – Derivative Financial Instruments for the new disclosures. | ||||||||||||||||
Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes | ||||||||||||||||
In July 2013, the FASB issued authoritative guidance permitting entities to designate the Fed Funds Effective Swap Rate as a U.S. benchmark interest rate for hedge accounting purposes. Prior to the issuance of this guidance, only interest rates on direct treasury obligations of the U.S. government and the LIBOR swap rate were considered benchmark interest rates in the U.S. This guidance was effective immediately and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. Currently, the Registrants do not use the Fed Funds Effective Swap Rate as a benchmark interest rate, but may in the future. | ||||||||||||||||
The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants. | ||||||||||||||||
Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist | ||||||||||||||||
In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. Currently, the Registrants present their unrecognized tax benefits as liabilities on a gross basis unless an unrecognized tax benefit is directly associated with a tax position taken in a tax year that results in the recognition of a net operating loss or other tax carryforward for that year. This guidance is effective for the Registrants for periods beginning after December 15, 2013 and is required to be applied prospectively, with retroactive application permitted. The Registrants will not retroactively adopt this guidance. This guidance is currently not expected to have an impact on the Registrants upon adoption with the exception of Exelon and Generation in which approximately $11 million of unrecognized tax benefits will be offset against current deferred income assets. The adoption of this standard will not impact the Registrants' results of operations. | ||||||||||||||||
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | ||||||||||||||||
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $458 million and $614 million as of December 31, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $414 million and $564 million as of December 31, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 15 – Asset Retirement Obligations for further discussion. | ||||||||||||||||
For each unconsolidated VIE, Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities. | ||||||||||||||||
Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEs which, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs. | ||||||||||||||||
ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon or Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions' creditors do not have any recourse to Exelon's or Generation's general credit. | ||||||||||||||||
Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 22 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. | ||||||||||||||||
For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. | ||||||||||||||||
Investment in Energy Development Projects. Generation has several equity investments in energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities of the VIEs that most significantly impact the VIEs economic performance. | ||||||||||||||||
Residential Solar Provider. Generation has an equity investment in a residential solar provider. Generation has evaluated the significant agreements, ownership structure and risks of the entity, and determined that the entity is a VIE because it does not have sufficient equity at risk to fund its operations. Generation has determined that its equity investment in the entity is a variable interest. However, Generation has concluded that we are not the primary beneficiary because Generation does not have the power to direct the activities of the VIE that most significantly impact the entity's economic performance. Exelon or Generation do not have any contractual or other obligations to provide additional financial support and the residential solar provider's creditors do not have any recourse to Exelon's or Generation's general credit. | ||||||||||||||||
ComEd, PECO and BGE | ||||||||||||||||
ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 22 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. | ||||||||||||||||
For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs as a result of commercial arrangements represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2013, the total amount of accounts payable owed by the utilities under agreements with these VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in these VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. | ||||||||||||||||
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon's, ComEd's, PECO's or BGE's financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 – Debt and Credit Agreements for additional information. | ||||||||||||||||
New_Accounting_Pronouncements_
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended |
Dec. 31, 2013 | |
New Accounting Pronouncements And Changes In Accounting Principles [Line Items] | ' |
Schedule Of New Accounting Pronouncements And Changes In Accounting Principles (Exelon, Generation, ComEd, PECO and BGE) | ' |
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE) | |
Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that may affect the Registrants. | |
Presentation of Items Reclassified out of Accumulated Other Comprehensive Income | |
In February 2013, the FASB issued authoritative guidance requiring entities to present either in the notes or parenthetically on the face of the financial statements, reclassifications from each component of accumulated other comprehensive income and the affected income statement line items. Entities only need to disclose the affected income statement line item for components reclassified to net income in their entirety; otherwise, a cross-reference to the related note should be provided. This guidance was effective for the Registrants for periods beginning after December 15, 2012 and was required to be applied prospectively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 21 – Changes in Accumulated Other Comprehensive Income for the new disclosures. | |
Disclosures About Offsetting Assets and Liabilities | |
In December 2011 (and amended in January 2013), the FASB issued authoritative guidance requiring entities to disclose both gross and net information about recognized derivative instruments, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing or lending transactions that are offset on the balance sheet or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet. The guidance was effective for the Registrants for periods beginning on or after January 1, 2013 and was required to be applied retrospectively. This guidance is primarily applicable to certain derivative transactions for Exelon and Generation. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial positions. See Note 12 – Derivative Financial Instruments for the new disclosures. | |
Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes | |
In July 2013, the FASB issued authoritative guidance permitting entities to designate the Fed Funds Effective Swap Rate as a U.S. benchmark interest rate for hedge accounting purposes. Prior to the issuance of this guidance, only interest rates on direct treasury obligations of the U.S. government and the LIBOR swap rate were considered benchmark interest rates in the U.S. This guidance was effective immediately and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. Currently, the Registrants do not use the Fed Funds Effective Swap Rate as a benchmark interest rate, but may in the future. | |
The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants. | |
Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist | |
In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. Currently, the Registrants present their unrecognized tax benefits as liabilities on a gross basis unless an unrecognized tax benefit is directly associated with a tax position taken in a tax year that results in the recognition of a net operating loss or other tax carryforward for that year. This guidance is effective for the Registrants for periods beginning after December 15, 2013 and is required to be applied prospectively, with retroactive application permitted. The Registrants will not retroactively adopt this guidance. This guidance is currently not expected to have an impact on the Registrants upon adoption with the exception of Exelon and Generation in which approximately $11 million of unrecognized tax benefits will be offset against current deferred income assets. The adoption of this standard will not impact the Registrants' results of operations. |
Variable_Interest_Entities_Exe
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Variable Interest Entities Disclosure [Line Items] | ' | ||||||||||||||||||
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
2. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||
Under the applicable authoritative guidance, a VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly impact the entity's economic performance. | |||||||||||||||||||
At December 31, 2013 and 2012, the Exelon, Generation, and BGE consolidated four and five VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of December 31, 2013, the Registrants had one VIE for which the Registrants were the primary beneficiary, however, the VIE is immaterial and was not included in the consolidated financial statements or in the consolidated VIE table below. As of December 31, 2013 and 2012, the Registrants had significant interests in eight and nine other VIEs for which the Registrants do not have the power to direct the entities' activities, respectively, and accordingly, were not the primary beneficiary. | |||||||||||||||||||
Consolidated Variable Interest Entities | |||||||||||||||||||
The carrying amounts and classification of the consolidated VIEs' assets and liabilities included in the Registrants' consolidated financial statements at December 31, 2013 and 2012 are as follows: | |||||||||||||||||||
31-Dec-13 | 31-Dec-12 | ||||||||||||||||||
Exelon (a) | Generation | BGE | Exelon (a)(b) | Generation (b) | BGE | ||||||||||||||
Current assets | $ | 484 | $ | 446 | $ | 28 | $ | 550 | $ | 519 | $ | 30 | |||||||
Noncurrent assets | 1,905 | 1,884 | 3 | 1,719 | 1,680 | - | |||||||||||||
Total assets | $ | 2,389 | $ | 2,330 | $ | 31 | $ | 2,269 | $ | 2,199 | $ | 30 | |||||||
Current liabilities | $ | 566 | $ | 481 | $ | 74 | $ | 684 | $ | 612 | $ | 71 | |||||||
Noncurrent liabilities | 774 | 562 | 195 | 775 | 470 | 265 | |||||||||||||
Total liabilities | $ | 1,340 | $ | 1,043 | $ | 269 | $ | 1,459 | $ | 1,082 | $ | 336 | |||||||
________________ | |||||||||||||||||||
Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||||||||||||||||||
Includes total assets of $146 million and total liabilities of $42 million as of December 31, 2012 related to a retail supply company that is not a consolidated VIE as of December 31, 2013. See additional information below. | |||||||||||||||||||
Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the preceding table can only be settled using VIE resources. | |||||||||||||||||||
RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. BGE has determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidates BondCo. | |||||||||||||||||||
BondCo's assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2013, 2012, and 2011, BGE remitted $83 million, $85 million, and $92 million, respectively, to BondCo. | |||||||||||||||||||
BGE did not provide any additional financial support to BondCo during 2013. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo. | |||||||||||||||||||
Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third-party gas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group's activities without the additional credit support that is provided in the form of a parental guarantee. Generation is the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE. | |||||||||||||||||||
The third-party gas supply arrangement is collateralized as follows: | |||||||||||||||||||
The assets of the retail gas entity group must be used to settle obligations under the third-party gas supply agreement before it can make any distributions to Generation, | |||||||||||||||||||
The third-party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and | |||||||||||||||||||
As of December 31, 2013 Exelon provided a $75 million parental guarantee to the third-party gas supplier in support of the retail gas entity group. | |||||||||||||||||||
Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide additional financial support under the collateralized third-party gas supply agreement. The third-party gas supply creditors do not have any recourse to Exelon's or Generation's general credit other than the parental guarantee. | |||||||||||||||||||
Solar Project Entity Group. In 2011, Constellation formed a group of solar project limited liability companies to build, own, and operate solar power facilities, which are now part of Generation. Additionally, on September 30, 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley) from First Solar, Inc., a 230-MW solar PV project under construction in northern Los Angeles County, California. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. Generation provides capital funding to these solar VIE entities for ongoing construction of the solar power facilities. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $536 million, as of December 31, 2013, for which the creditors have no recourse to Generation, however there is limited recourse to Generation with respect to remaining equity contributions necessary to complete the Antelope Valley project. For additional information on these project-specific financing arrangements refer to Note 13 – Debt and Credit Agreements. | |||||||||||||||||||
Retail Power Supply Entity. In August 2013, Generation executed an agreement to terminate its energy supply contract with a retail power supply company that was previously a consolidated VIE. Generation did not have an ownership interest in the entity, but was the primary beneficiary through the energy supply contract. As a result of the termination, Generation no longer has a variable interest in the retail power supply company and ceased consolidation of the entity during the third quarter of 2013. Upon deconsolidation, there was no gain or loss recognized. The assets, liabilities, and non-controlling interest were removed from Exelon's and Generation's balance sheet and the change in non-controlling interest is also reflected on the Statement of Changes in Shareholders' Equity and the Statement of Changes in Member's Equity for Exelon and Generation, respectively. | |||||||||||||||||||
Wind Project Entity Group. Generation owns and operates a number of wind project limited liability entities, the majority of which were acquired on December 9, 2010 when Generation completed the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownership structures and risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have non-controlling interest holders that absorb variability from the wind projects, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind power facilities. While Generation owns 100% of the majority of the wind project entities, 10 of the projects have non-controlling equity interests held by third parties, that currently range between 1% and 6%. Of these 10 projects, Generation's current economic interests in nine of the projects are significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the non-controlling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the non-controlling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the non-controlling interests state that Generation is to provide financial support to the projects in proportion to its current economic interests in the projects that currently range between 94% and 99%. However, no additional support to these projects beyond what was contractually required has been provided during 2013. As of December 31, 2013, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relate to the wind generating assets, PPA intangible assets and working capital amounts. | |||||||||||||||||||
As of December 31, 2013 and 2012, ComEd and PECO did not have any consolidated VIEs. | |||||||||||||||||||
Unconsolidated Variable Interest Entities | |||||||||||||||||||
Exelon's and Generation's variable interests in unconsolidated VIEs generally include three transaction types: (1) equity investments, (2) energy purchase and sale contracts, and (3) fuel purchase commitments. For the equity investments, the carrying amount of the investments is reflected on their Consolidated Balance Sheets in Investments in affiliates. For the energy purchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon's and Generation's Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements. | |||||||||||||||||||
As of December 31, 2013 and 2012, Exelon and Generation had significant unconsolidated variable interests in eight and nine, respectively, VIEs for which they were not the primary beneficiary; including certain equity investments and certain commercial agreements. The change in the number of unconsolidated variable interests is driven by the completion of certain obligations which cause the entities to no longer be unconsolidated variable interests offset by the addition of an equity investment in a residential solar provider. The following tables present summary information about the significant unconsolidated VIE entities: | |||||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 128 | $ | 332 | $ | 460 | |||||||||||||
Total liabilities (a) | 17 | 123 | 140 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 86 | 86 | ||||||||||||||||
Other ownership interests (a) | 111 | 123 | 234 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity investments | 7 | 67 | 74 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-12 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 386 | $ | 354 | $ | 740 | |||||||||||||
Total liabilities (a) | 219 | 114 | 333 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 167 | 143 | 310 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Letters of credit | 5 | 0 | 5 | ||||||||||||||||
Carrying amount of equity investments | 0 | 77 | 77 | ||||||||||||||||
Contract intangible asset | 8 | 0 | 8 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 50 | 0 | 50 | ||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Variable Interest Entities Disclosure [Line Items] | ' | ||||||||||||||||||
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | |||||||||||||||||||
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $458 million and $614 million as of December 31, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $414 million and $564 million as of December 31, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 15 – Asset Retirement Obligations for further discussion. | |||||||||||||||||||
For each unconsolidated VIE, Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities. | |||||||||||||||||||
Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEs which, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs. | |||||||||||||||||||
ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon or Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions' creditors do not have any recourse to Exelon's or Generation's general credit. | |||||||||||||||||||
Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 22 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. | |||||||||||||||||||
For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. | |||||||||||||||||||
Investment in Energy Development Projects. Generation has several equity investments in energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities of the VIEs that most significantly impact the VIEs economic performance. | |||||||||||||||||||
Residential Solar Provider. Generation has an equity investment in a residential solar provider. Generation has evaluated the significant agreements, ownership structure and risks of the entity, and determined that the entity is a VIE because it does not have sufficient equity at risk to fund its operations. Generation has determined that its equity investment in the entity is a variable interest. However, Generation has concluded that we are not the primary beneficiary because Generation does not have the power to direct the activities of the VIE that most significantly impact the entity's economic performance. Exelon or Generation do not have any contractual or other obligations to provide additional financial support and the residential solar provider's creditors do not have any recourse to Exelon's or Generation's general credit. | |||||||||||||||||||
ComEd, PECO and BGE | |||||||||||||||||||
ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 22 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. | |||||||||||||||||||
For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs as a result of commercial arrangements represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2013, the total amount of accounts payable owed by the utilities under agreements with these VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in these VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. | |||||||||||||||||||
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon's, ComEd's, PECO's or BGE's financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 – Debt and Credit Agreements for additional information. | |||||||||||||||||||
Merger_and_Acquisitions_Exelon
Merger and Acquisitions (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||||||||||||||||||
Mergers and Acquisitions (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||||||||
4. Merger and Acquisitions | |||||||||||||||||||||||||||||
Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
Description of Transaction | |||||||||||||||||||||||||||||
On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation's interest in RF HoldCo LLC, which holds Constellation's interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon's interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger. | |||||||||||||||||||||||||||||
Regulatory Matters | |||||||||||||||||||||||||||||
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. | |||||||||||||||||||||||||||||
The following costs were recognized after the closing of the merger and are included in Exelon's, Generation's and BGE's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012. | |||||||||||||||||||||||||||||
Description | Payment Period | BGE | Generation | Exelon | Statement of Operations Location | ||||||||||||||||||||||||
BGE rate credit of $100 per residential | |||||||||||||||||||||||||||||
customer (a) | Q2 2012 | $ | 113 | $ | 0 | $ | 113 | Revenues | |||||||||||||||||||||
Customer investment fund to invest in | |||||||||||||||||||||||||||||
energy efficiency and low-income | |||||||||||||||||||||||||||||
energy assistance to BGE customers | 2012 to 2014 | 0 | 0 | 113.5 | O&M Expense | ||||||||||||||||||||||||
Contribution for renewable energy, | |||||||||||||||||||||||||||||
energy efficiency or related projects | |||||||||||||||||||||||||||||
in Baltimore | 2012 to 2014 | 0 | 0 | 2 | O&M Expense | ||||||||||||||||||||||||
Charitable contributions at $7 million per | |||||||||||||||||||||||||||||
year for 10 years | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | ||||||||||||||||||||||||
State funding for offshore wind | |||||||||||||||||||||||||||||
development projects | Q2 2012 | 0 | 0 | 32 | O&M Expense | ||||||||||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | -2 | 0 | -2 | Taxes Other Than Income | ||||||||||||||||||||||||
Total | $ | 139 | $ | 35 | $ | 328.5 | |||||||||||||||||||||||
Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. | |||||||||||||||||||||||||||||
The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation's competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that is contingent upon the developer obtaining all required approvals, permits and financing for the construction of the building. Once required approvals are received and financing conditions are met, construction will commence and the building is expected to be ready for occupancy in approximately 2 years after building construction commences. | |||||||||||||||||||||||||||||
The direct investment estimate also includes $600 million to $650 million for Exelon's and Generation's commitment to develop or assist in development of 285 — 300 MWs of new generation in Maryland, expected to be completed over a period of 10 years. The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of December 31, 2013, it is reasonably possible that Exelon will be required to make subsidy or liquidated damages payments of approximately $40 million rather than build one of the generation projects contemplated by the commitments, given that the generation build is dependent upon the passage of legislation and other conditions that Exelon does not control. | |||||||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland site with 120MW of new natural gas-fired generation to satisfy certain of these commitments and achievement of commercial operation is expected in 2015. In December 2013, Generation acquired the Fourmile Ridge Project in western Maryland and executed a wind turbine supply agreement for construction of a 32.5 MW project targeted for commercial operation in November 2014. This project will satisfy a portion of the 125 MW Tier I land-based renewables commitment. See Note 22 – Commitments and Contingencies for additional information. As of December 31, 2013, amounts reflected in the Exelon and Generation consolidated financial statements include $24 million of capital expenditures and $6 million of development costs included within operating and maintenance expense associated with pursuit of these commitments for new generation in the State of Maryland. | |||||||||||||||||||||||||||||
Associated with certain of the regulatory approvals required for the merger, on November 30, 2012, a subsidiary of Generation sold three Maryland generating stations and associated assets, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. The sale agreement included a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in net proceeds from the sale of approximately $371 million. Decisions by certain market participants to remove themselves from the bidding process, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realized sales proceeds below Generation's estimated fair value of the Maryland generating stations. Consequently, Exelon and Generation recorded a pre-tax loss of $272 million in 2012 to reflect the difference between the sales price and the carrying value of the generating stations and associated assets. In the first quarter of 2013, Exelon and Generation recorded a pre-tax gain of $8 million to reflect the final settlement of the sales price with Raven Power. | |||||||||||||||||||||||||||||
In connection with the sale of the Maryland generating stations, Exelon agreed to indemnify Raven Power for certain costs associated with the treatment of hazardous substances at off-site disposal facilities and any claims arising as a result of, or in connection with, any toxic tort, natural resource damages, loss of life or injury to persons due to releases of, or exposure to hazardous substances in connection with Raven Power's remediation of environmental contamination or Exelon's non-compliance with environmental laws or permits prior to the closing date of the sale. | |||||||||||||||||||||||||||||
Pursuant to the MDPSC merger approval conditions, BGE is restricted from paying any dividend on its common shares through the end of 2014, was required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and is not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process for two years following the closing of the merger. Additionally, BGE is subject to other merger approval conditions to enhance BGE's ring-fencing measures established by order of the MDPSC. | |||||||||||||||||||||||||||||
Subsequent to the merger, Generation discovered that, for the first two weeks following the merger, due to a software error, Generation inadvertently bid certain generating units into the PJM energy market at prices that slightly exceeded the cost-based caps to which it had agreed. This error was a violation of the commitments made in connection with merger approvals by DOJ, FERC and the MDPSC. Generation reported the error to the DOJ, FERC and the MDPSC and committed to remedy the impacts of its error. The MDPSC held a hearing to review the error, and accepted Generation's proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for some minor adjustments to the cost build up for certain of its PJM units. Generation has coordinated with PJM to determine the impact on Generation's revenues and the market from this error and these adjustments, and Generation has worked with PJM to reverse the financial impacts. In November 2012, Generation reached a settlement with the DOJ regarding this matter. The final resolution did not have a material impact on Exelon's or Generation's results of operations, cash flows or financial position. | |||||||||||||||||||||||||||||
Exelon was named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors' breaches. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. On June 26, 2012, the court approved the settlement and entered final judgment. | |||||||||||||||||||||||||||||
Accounting for the Merger Transaction | |||||||||||||||||||||||||||||
The fair value of Constellation's non-regulated business assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed. | |||||||||||||||||||||||||||||
The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to rate-setting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE's tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE's debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE's assets acquired and liabilities assumed is recorded as a regulatory asset and liability at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1 — Significant Accounting Policies for additional information on BGE's push-down accounting treatment. Also see Note 3 — Regulatory Matters for additional information on BGE's regulatory assets. | |||||||||||||||||||||||||||||
The preliminary valuations performed in the first quarter of 2012 were updated in the second, third and fourth quarters of 2012, with the most significant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply and fuel contracts, unregulated property, plant and equipment and investments in affiliates. There were no significant adjustments to the purchase price allocation in the first quarter of 2013 and the purchase price allocation was final as of March 31, 2013. | |||||||||||||||||||||||||||||
The final purchase price allocation of the Merger of Exelon with Constellation and Exelon's contribution of certain subsidiaries of Constellation to Generation was as follows: | |||||||||||||||||||||||||||||
Preliminary Purchase Price Allocation, excluding amortization | Exelon | Generation | |||||||||||||||||||||||||||
Current assets | $ | 4,936 | $ | 3,638 | |||||||||||||||||||||||||
Property, plant and equipment | 9,342 | 4,054 | |||||||||||||||||||||||||||
Unamortized energy contracts | 3,218 | 3,218 | |||||||||||||||||||||||||||
Other intangibles, trade name and retail relationships | 457 | 457 | |||||||||||||||||||||||||||
Investment in affiliates | 1,942 | 1,942 | |||||||||||||||||||||||||||
Pension and OPEB regulatory asset | 740 | 0 | |||||||||||||||||||||||||||
Other assets | 2,265 | 1,266 | |||||||||||||||||||||||||||
Total assets | 22,900 | 14,575 | |||||||||||||||||||||||||||
Current liabilities | 3,408 | 2,804 | |||||||||||||||||||||||||||
Unamortized energy contracts | 1,722 | 1,512 | |||||||||||||||||||||||||||
Long-term debt, including current maturities | 5,632 | 2,972 | |||||||||||||||||||||||||||
Non-controlling interest | 90 | 90 | |||||||||||||||||||||||||||
Deferred credits and other liabilities and preferred securities | 4,683 | 1,933 | |||||||||||||||||||||||||||
Total liabilities, preferred securities and non-controlling interest | 15,535 | 9,311 | |||||||||||||||||||||||||||
Total purchase price | $ | 7,365 | $ | 5,264 | |||||||||||||||||||||||||
Intangible Assets Recorded | |||||||||||||||||||||||||||||
For the power supply and fuel contracts acquired from Constellation, the difference between the contract price and the market price at the date of the merger was recognized as either an intangible asset or liability based on whether the contracts were in or out-of-the-money. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the merger date. Amortization expense and income are recorded through purchased power and fuel expense or operating revenues. | |||||||||||||||||||||||||||||
Exelon and Generation present separately in their Consolidated Balance Sheets the unamortized energy contract assets and liabilities for these contracts. Generation's amortization expense for the year ended December 31, 2013 amounted to $470 million. Generation's amortization expense for the period March 12, 2012 to December 31, 2012 amounted to $1,101 million. In addition, Exelon Corporate has established a regulatory asset and an unamortized energy contract liability related to BGE's power supply and fuel contracts. The power supply and fuel contracts regulatory asset amortization was $77 million for the year ended December 31, 2013 and $116 million for the period March 12, 2012 to December 31, 2012. An equally offsetting amortization of the unamortized energy contract liability has been recorded at Exelon Corporate in the Consolidated Statement of Operations. | |||||||||||||||||||||||||||||
The fair value of the Constellation trade name intangible asset was determined based on the relief from royalty method of the income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. Exelon's and Generation's straight line amortization expense for the fair value of the Constellation trade name intangible asset for the year ended December 31, 2013 and for the period March 12, 2012 to December 31, 2012 amounted to $26 million and $20 million, respectively. The trade name intangible asset is included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||||||||||||||||||
The fair value of the retail relationships was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset's fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The measure is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The intangible assets for the fair value of the retail relationships are amortized as amortization expense on a straight line basis over the useful life of the underlying assets. Exelon's and Generation's straight line amortization expense for year ended December 31, 2013 and for the period March 12, 2012 to December 31, 2012 amounted to $21 million and $15 million, respectively. The retail relationships intangible assets are included in deferred debits and other assets within Exelon's and Generation's Consolidated Balance Sheets. | |||||||||||||||||||||||||||||
Exelon's intangible assets and liabilities acquired through the merger with Constellation included in its Consolidated Balance Sheets, along with the future estimated amortization, were as follows as of December 31, 2013: | |||||||||||||||||||||||||||||
Estimated amortization expense | |||||||||||||||||||||||||||||
Description | Weighted Average Amortization (Years) (b) | Gross | Accumulated Amortization | Net | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and Beyond | |||||||||||||||||||
Unamortized energy contracts, net (a) | 1.5 | $ | 1,499 | $ | -1,378 | $ | 121 | $ | 75 | $ | 18 | $ | -31 | $ | -21 | $ | 11 | $ | 69 | ||||||||||
Trade name | 10 | 243 | -46 | 197 | 24 | 24 | 24 | 24 | 24 | 77 | |||||||||||||||||||
Retail relationships | 12.4 | 214 | -36 | 178 | 19 | 18 | 18 | 18 | 18 | 87 | |||||||||||||||||||
Total, net | $ | 1,956 | $ | -1,460 | $ | 496 | $ | 118 | $ | 60 | $ | 11 | $ | 21 | $ | 53 | $ | 233 | |||||||||||
Includes the fair value of BGE's power and gas supply contracts of $12 million for which an offsetting Exelon Corporate regulatory asset was also recorded. | |||||||||||||||||||||||||||||
(b) Weighted average amortization period was calculated as of the date of acquisition. | |||||||||||||||||||||||||||||
Impact of Merger | |||||||||||||||||||||||||||||
It is impracticable to determine the overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger for the year ended December 31, 2012. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation's operations and are therefore not fully distinguishable after the merger. | |||||||||||||||||||||||||||||
The impact of BGE on Exelon's Consolidated Statement of Operations and Comprehensive Income includes operating revenues of $3,065 million and $ 2,091 million and net income (loss) of $210 million and $ (31) million during the years ended December 31, 2013 and December 31, 2012, respectively. | |||||||||||||||||||||||||||||
During the year ended December 31, 2013, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $142 million, $106 million, $16 million, $9 million and $6 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $17 million, $11 million and $6 million, respectively, as a regulatory asset as of December 31, 2013. Additionally, Exelon and BGE established a regulatory asset of $6 million as of December 31, 2013 for previously incurred 2012 merger and integration-related costs. | |||||||||||||||||||||||||||||
During the year ended December 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $804 million, $340 million, $41 million, $17 million and $182 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $58 million, $36 million and $22 million, respectively, as a regulatory asset as of December 31, 2012. | |||||||||||||||||||||||||||||
The costs incurred are classified primarily within Operating and Maintenance Expense in the Registrants' respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the BGE customer rate credit and the credit facility fees, which are included as a reduction to operating revenues and other, net, respectively, for years ended December 31, 2013 and 2012. See Note 22 — Commitments and Contingencies for additional information. | |||||||||||||||||||||||||||||
Pro-forma Impact of the Merger | |||||||||||||||||||||||||||||
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon's and Generation's accounting policies and adjusting Constellation's results to reflect purchase accounting adjustments. | |||||||||||||||||||||||||||||
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company. | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||
(unaudited) | 2012 | 2011 (a) | 2012 | 2011 (b) | |||||||||||||||||||||||||
Total Revenues | $ | 17,013 | $ | 19,494 | $ | 26,700 | $ | 30,712 | |||||||||||||||||||||
Net income attributable to Exelon | 1,205 | 324 | 2,092 | 974 | |||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | n.a. | $ | 2.56 | $ | 1.15 | |||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | n.a. | 2.55 | 1.14 | |||||||||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
Acquisitions (Exelon and Generation) | |||||||||||||||||||||||||||||
Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future power and fuel market prices. Additionally, market prices based on the Market Price Referent (MPR) established by the CPUC for renewable energy resources were used in determining the fair value of the Antelope Valley assets acquired and liabilities assumed. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and the duration of the liabilities assumed. Generation did not record any goodwill related to any of the respective acquisitions. | |||||||||||||||||||||||||||||
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for each of the companies acquired by Generation during the year ended December 31, 2011: | |||||||||||||||||||||||||||||
Acquisitions | |||||||||||||||||||||||||||||
2011 | |||||||||||||||||||||||||||||
Wolf Hollow | Antelope Valley | ||||||||||||||||||||||||||||
Fair value of consideration transferred | |||||||||||||||||||||||||||||
Cash | $ | 305 | $ | 75 | |||||||||||||||||||||||||
Plus: Gain on PPA settlement | 6 | - | |||||||||||||||||||||||||||
Total fair value of consideration transferred | $ | 311 | $ | 75 | |||||||||||||||||||||||||
Recognized amounts of identifiable assets acquired and liabilities assumed | |||||||||||||||||||||||||||||
Property, plant and equipment | $ | 347 | $ | 15 | |||||||||||||||||||||||||
Inventory | 5 | - | |||||||||||||||||||||||||||
Intangible assets (a) | - | 190 | |||||||||||||||||||||||||||
Payable to First Solar, Inc. (b) | - | -135 | |||||||||||||||||||||||||||
Working capital, net | -5 | - | |||||||||||||||||||||||||||
Other Assets | - | 5 | |||||||||||||||||||||||||||
Total net identifiable assets | $ | 347 | $ | 75 | |||||||||||||||||||||||||
Bargain purchase gain | $ | 36 | $ | - | |||||||||||||||||||||||||
________________________ | |||||||||||||||||||||||||||||
(a) See Note 10 - Intangible Assets for additional information. | |||||||||||||||||||||||||||||
(b) Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a "seller financing" arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation's implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc. During 2013, a subsidiary of Generation paid off the remaining balance of the payable to First Solar, Inc. | |||||||||||||||||||||||||||||
Wolf Hollow, LLC. On August 24, 2011, Generation completed the acquisition of all of the equity interests of Wolf Hollow, LLC (Wolf Hollow), a combined-cycle natural gas-fired power plant in north Texas, for a purchase price of $311 million which increased Generation's owned capacity within the ERCOT power market by 720 MWs. The acquisition supports the Exelon commitment to low-carbon generation as part of Exelon 2020. | |||||||||||||||||||||||||||||
Generation recognized an approximately $36 million non-cash bargain purchase gain (i.e., negative goodwill). The gain was included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||||||||||
The pro forma impact of this acquisition would not have been material to Exelon's or Generation's results of operations for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
Antelope Valley Solar Ranch One. On September 30, 2011, Generation announced the completion of its acquisition of all of the interests in Antelope Valley Solar Ranch One (Antelope Valley), a 230-MW solar PV project under development in northern Los Angeles County, California, from First Solar, Inc., which is developing, building, operating, and maintaining the project. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013. Exelon has been informed by First Solar of issues relating to delays in the certification of certain components relating to the final two blocks of the project, which will delay commercial operation of these two blocks until the first half of 2014. When fully operational, Antelope Valley will be one of the largest PV solar projects in the world, with approximately 3.8 million solar panels generating enough clean, renewable electricity to power the equivalent of 75,000 average homes per year. The project has a 25-year PPA, approved by the California Public Utilities Commission, with Pacific Gas & Electric Company for the full output of the plant. The acquisition supports Exelon's commitment to renewable energy as part of Exelon 2020. | |||||||||||||||||||||||||||||
Exelon expects to invest up to $650 million in equity in the project through 2014. The DOE's Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the project. See Note 13 – Debt and Credit Agreements for additional information on the DOE loan guarantee. | |||||||||||||||||||||||||||||
The pro forma impact of this acquisition would not have been material to Exelon's or Generation's results of operations for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
Regulatory_Matters_Exelon_Gene
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
3. Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | 31-Dec-12 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||||||||||||||||||
The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants. | Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning | $ | 0 | $ | 2,397 | $ | 0 | $ | 2,037 | $ | 0 | $ | 360 | $ | 0 | $ | 0 | ||||||||||||||||||||||||||||||||||||
Removal costs | 97 | 1,406 | 75 | 1,192 | 0 | 0 | 22 | 214 | ||||||||||||||||||||||||||||||||||||||||||||
Illinois Regulatory Matters | Energy efficiency and demand | |||||||||||||||||||||||||||||||||||||||||||||||||||
response programs | 131 | 0 | 43 | 0 | 88 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Energy Infrastructure Modernization Act (Exelon and ComEd). | Electric distribution tax repairs | 20 | 132 | 0 | 0 | 20 | 132 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs | 8 | 46 | 0 | 0 | 8 | 46 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Background | Over-recovered uncollectible | |||||||||||||||||||||||||||||||||||||||||||||||||||
accounts | 6 | 0 | 6 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Since 2011, ComEd's distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd's best estimate of the revenue requirement expected to be approved by the ICC for that year's reconciliation. As of December 31, 2013, and December 31, 2012, ComEd had a net regulatory asset associated with the distribution formula rate of $463 million and $209 million, respectively. | Energy and transmission programs | 54 | 0 | 6 | 0 | 48 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
Over-recovered gas universal | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Formula Rate Tariff | service fund costs | 3 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
Over-recovered AEPS costs | 2 | 0 | 0 | 0 | 2 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
On November 8, 2011, ComEd filed its initial formula rate tariff and associated testimony based on 2010 costs and 2011 plant additions. The primary purpose of that proceeding was to establish the formula rate under which rates will be calculated going-forward, and the initial rates, which went into effect in late June 2012. On May 29, 2012, the ICC issued an Order (May Order) in that proceeding. The May Order reduced the annual revenue requirement by $168 million, or approximately $110 million more than the proposed reduction by ComEd. Of this incremental revenue requirement reduction, approximately $50 million reflected the ICC's determination that certain costs should be recovered through alternative rate recovery tariffs available to ComEd or will be reflected in a subsequent annual reconciliation, thereby primarily delaying the timing of cash flows. The incremental revenue reduction also reflected a $35 million reduction for the disallowance of return on ComEd's pension asset, a $10 million reduction for incentive compensation related adjustments, and $15 million of reductions for various adjustments for cash working capital, operating reserves, and other technical items. In the second quarter of 2012, ComEd recorded a decrease in revenue of approximately $100 million pre-tax to decrease the regulatory asset for 2011 and for the first three months of 2012 consistent with the terms of the May Order. | Revenue subject to refund | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
Over-recovered gas revenue | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On June 22, 2012, the ICC granted an expedited rehearing on three of the issues decided in the May Order. On October 3, 2012, the ICC issued its final order (Rehearing Order) in that rehearing, adopting ComEd's position on the return on its pension asset, resulting in an increase in the annual revenue requirement. For the two other issues, the ICC ruled against ComEd by reaffirming use of an average rather than year-end rate base in the annual reconciliation and amending its prior order to provide a short-term debt rate to apply to the annual reconciliation. In the fourth quarter of 2012, ComEd recorded an increase in revenue of approximately $135 million pre-tax consistent with the terms of the Rehearing Order, of which $75 million pre-tax reflects the reinstatement of the return on pension asset for 2011 and $60 million pre-tax reflects the return on pension asset for 2012. New rates reflecting the impacts of the Rehearing Order went into effect in November 2012. ComEd has filed an appeal with the Illinois Appellate Court. ComEd cannot predict the results of any such appeals. | decoupling | 7 | 0 | 0 | 0 | 0 | 0 | 7 | 0 | |||||||||||||||||||||||||||||||||||||||||||
In March 2013, the Illinois legislature passed Senate Bill 9 to clarify the intent of EIMA on the three issues decided in the Rehearing Order: an allowed return on ComEd's pension asset; the use of year-end rather than average rate base and capital structure in the annual reconciliation; and the use of ComEd's weighted average cost of capital interest rate rather than a short-term debt rate to apply to the annual reconciliation. On May 22, 2013, Senate Bill 9 became effective after the Illinois legislature overrode the Governor's veto of that Bill. On June 5, 2013, the ICC approved ComEd's updated distribution formula rate structure to reflect the impacts of Senate Bill 9. | Total regulatory liabilities | $ | 368 | $ | 3,981 | $ | 170 | $ | 3,229 | $ | 169 | $ | 538 | $ | 29 | $ | 214 | |||||||||||||||||||||||||||||||||||
In October 2013, the ICC opened an investigation (the Investigation), in response to a complaint filed by the Illinois Attorney General, to change the formula rate structure by requesting three changes: the elimination of the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance, the netting of associated accumulated deferred income taxes against the annual reconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining any ROE collar adjustment. On November 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes but accepting the proposed change to eliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance. The accepted change became effective in January 2014, and is estimated to reduce ComEd's 2014 revenue by approximately $8 million. This change had no financial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearing requests were denied by the ICC. ComEd and intervenors have filed appeals with the Illinois Appellate Court. ComEd cannot predict the results of any such appeals. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual Reconciliation | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2012 Filing. On April 30, 2012, ComEd filed its annual distribution formula rate. On December 20, 2012, the ICC issued its final order, which increased the revenue requirement by $73 million, in conformity with the formula rate structure provided in the May 2012 and Rehearing Orders. The $73 million reflected an increase of $80 million for the initial revenue requirement for 2012 and a decrease of $7 million for the annual reconciliation for 2011. The rate increase was set using an allowed return on capital of 7.54% (inclusive of an allowed return on common equity of 9.81%). The rates took effect in January 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court. ComEd cannot predict the results of any such appeals. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On May 30, 2013, ComEd updated its revenue requirement allowed in the December 2012 Order to reflect the impacts of Senate Bill 9, which resulted in a reduction to the current revenue requirement in effect of $14 million. The rates took effect in July 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2013 Filing. On April 29, 2013, ComEd filed its annual distribution formula rate, which was updated in August 2013, to request a total increase to the revenue requirement of $353 million of which $42 million related to Senate Bill 9. On December 19, 2013, the ICC issued its final order, which increased the revenue requirement by $341 million, reflecting an increase of $160 million for the initial revenue requirement for 2013 and an increase of $181 million for the annual reconciliation for 2012. The rate increase was set using an allowed return on capital of 6.94% (inclusive of an allowed return on common equity of 8.72%). The rates took effect in January 2014. ComEd requested a rehearing on specific issues, which was denied by the ICC. ComEd also filed an appeal. ComEd cannot predict the results of any such appeals. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Expenditures and Capital Investment | ||||||||||||||||||||||||||||||||||||||||||||||||||||
As part of the enactment of EIMA legislation, ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million, the first of which was made on December 31, 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which will not be recoverable through rates. These contributions began in 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On January 6, 2012, ComEd filed its Infrastructure Investment Plan with the ICC. Under that plan, ComEd will invest approximately $2.6 billion over ten years to modernize and storm-harden its distribution system and to implement smart grid technology. On April 23, 2012, ComEd filed its initial AMI Deployment Plan with the ICC, which was approved by the ICC on June 22, 2012, with certain modifications. ComEd outlined the new deployment schedule within testimony provided in the AMI Plan Rehearing and filed a revised AMI deployment plan. The deployment plan provides for the installation of 4 million electric smart meters, of which more than 60,000 meters were installed by the end of 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd's 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd's annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP). | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The court held the ICC abused its discretion in not reducing ComEd's rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period. ComEd continued to bill rates as established under the ICC's order in the 2007 Rate Case until June 1, 2011 when the rates set in the 2010 electric distribution rate case (2010 Rate Case) became effective. In subsequent ICC proceedings, the ICC issued an order requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal with the Court. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
However, on September 27, 2013 the Court ruled against ComEd on the accumulated depreciation issue and affirmed that ComEd owes a refund to customers of $37 million. As of December 31, 2013, and December 31, 2012, ComEd was fully reserved for this liability. ComEd will not seek rehearing or appeal on this matter and is working with the ICC on the process and timing for a refund to customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Advanced Metering Program Proceeding (Exelon and ComEd) ComEd's 2007 Rate Case filing included a system modernization rider, which permitted investments in AMI to study the costs and benefits and to develop the cost estimate of full system-wide implementation. In October 2009, the ICC approved a modified version of ComEd's system modernization rider proposed in the 2007 Rate Case, Rider AMP (Advanced Metering Program). ComEd collected approximately $24 million under Rider AMP through December 31, 2013. Several other parties, including the Illinois Attorney General, appealed the ICC's order on Rider AMP. In ComEd's 2010 electric distribution rate case, the ICC approved ComEd's transfer of other costs from recovery under Rider AMP to recovery through electric distribution rates. On March 19, 2012, the Court reversed the ICC's approval of Rider AMP, concluding that the ICC's October 2009 approval of the rider constituted single-issue ratemaking. ComEd filed a Petition for Leave to Appeal to the Illinois Supreme Court on April 23, 2012, which was denied in September 2012, and the matter was returned to the ICC to calculate a refund amount. ComEd believes any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Appellate Court's order on March 19, 2012. As a result, ComEd recorded a regulatory liability of approximately $0.4 million at December 31, 2013, which represents the amounts collected from customers since March 19, 2012. ComEd cannot predict the ultimate outcome of the ICC proceeding and therefore, actual refunds may differ from the estimated accrual recorded at December 31, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2010 Illinois Electric Distribution Rate Case (Exelon and ComEd). On May 24, 2011, the ICC issued an order in ComEd's 2010 Rate Case, which became effective on June 1, 2011. The order approved a $143 million increase to ComEd's annual delivery services revenue requirement and a 10.5% rate of return on common equity. ComEd originally requested a $396 million increase, although it was subsequently reduced to $343 million to account for various adjustments. As expected, the ICC followed the Court's ruling on ComEd's 2007 Rate Case on the post-test year accumulated depreciation issue. The order allowed ComEd to establish or reestablish a net amount of approximately $40 million of previously expensed plant balances or new regulatory assets, which is reflected as a reduction in operating and maintenance expense and income tax expense in 2011. The order also affirmed the current regulatory asset for severance costs, which was challenged by an intervener in the 2010 Rate Case. The order was appealed to the Court by several parties on a number of issues. On May 16, 2013, the Court dismissed as moot the appeals of the ICC's order in the 2010 Rate Case as ComEd now recovers distribution costs under EIMA through a pre-established formula rate tariff. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). Since the first quarter of 2011, ComEd has been required to buy certain RES receivables, primarily residential and small commercial and industrial customers, at the option of the RES, for electric supply service and then include those amounts on ComEd's bill to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible accounts. ComEd produces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. As of December 31, 2013, the balance of purchased accounts receivable was $105 million. Under the applicable tariff, ComEd recovers from RES and customers the costs for implementing and operating the program. A number of municipalities, including the City of Chicago have switched to RES electric supply. As a result, ComEd experienced a significant increase in the amount of RES receivables it purchased in 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, as a result of the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. On December 21, 2011, the ICC approved the IPA's procurement plan covering the period June 2012 through May 2017. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of the electricity it purchases for customer deliveries from renewable energy resources. Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers' own actions or as a result of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd's purchase obligation. ComEd entered into several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy and associated RECs in order to meet its obligations under the state's RPS. Under the Illinois Settlement Legislation, all associated costs are recoverable from customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
As a result of reduced ComEd load forecasts, purchases under the existing long-term contracts for energy and the associated RECs were reduced on a pro-rata basis under the terms of those contracts for the June 2013 – May 2014 period to keep the purchases under the statutory rate impact cap. The curtailment's impact on ComEd's financial position and cash flows was immaterial. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On December 18, 2013, the ICC approved the IPA's 2014-2019 procurement plan. The plan provides for two separate energy procurements during 2014 to address potential fluctuations in energy demand due to customer switching between ComEd and competitive electric generation suppliers. The Commission also approved the IPA's expansion of energy efficiency programs for both ComEd and Ameren. The ICC did not require the acquisition of additional renewable resources in 2014-2015 due to insufficient available funds to procure those resources. Further, the ICC again approved a reduction of purchases under the existing long-term contracts for energy and the associated RECs on a pro-rata basis under the terms of those contracts for the June 2014 – May 2015 period to keep the purchases under the statutory rate impact cap; however, the amount of the reduction will not be finalized and approved by the ICC until March 2014. The curtailment's impact on ComEd's financial position and cash flows is expected to be immaterial. See Note 12 – Derivative Financial Instruments for additional information regarding ComEd's financial swap contract with Generation, which expired in May 2013, and long-term renewable energy contracts. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The sourcing agreement provides that the Utilities will pay FutureGen's contract prices, which are set annually pursuant to a formula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility. The order also directs the Utilities to recover (or pass along) these costs from the Utilities' distribution system customers, regardless of whether they purchase electricity from the utility or from competitive electric generation suppliers. In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On August 22, 2013, the Utilities executed the sourcing agreement with FutureGen in accordance with the ICC order. However, in the event the order is reversed as a result of the appeal, ComEd's obligations under the sourcing agreement should be suspended. Depending on the ultimate outcome of the appeals, the eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon's and ComEd's cash flows and financial positions. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
See Note 22 – Commitments and Contingencies for additional information on ComEd's energy commitments. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). As a result of the Illinois Settlement Legislation, electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which increases annually to 2.0% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten-year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In December 2010, the ICC approved ComEd's second three-year Energy Efficiency and Demand Response Plan covering the period June 2011 through May 2014. The plans are designed to meet the Illinois Settlement Legislation's energy efficiency and demand response goals through May 2014, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
EIMA provides for additional energy efficiency in Illinois. Starting in the June 2013 – May 2014 period and occurring annually thereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additional new cost-effective program and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energy efficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separately from the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected under the same rider. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Since June 1, 2008, utilities have been required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth in the Illinois Settlement Legislation. As of December 31, 2013, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois Settlement Legislation. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates. See Note 22 — Commitments and Contingencies for information regarding ComEd's future commitments for the procurement of RECs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Pennsylvania Regulatory Matters | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO's electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs on a full and current basis through a rider. The approved electric and natural gas distribution rates became effective on January 1, 2011. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In addition, the settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from the application of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The expected total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 is $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2013. PECO currently anticipates that the IRS will issue guidance in early 2014 providing a safe harbor method of accounting for gas transmission and distribution property. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution rate cases. See Note 14 for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The 2010 electric and natural gas distribution rate case settlements did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. PECO has not filed a transmission rate case since rates have been unbundled. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Pennsylvania Procurement Proceedings (Exelon and PECO). PECO's first PAPUC approved DSP Program, under which PECO was providing default electric service, had a 29-month term that ended May 31, 2013. On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129. Under the DSP Programs, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. In addition, PECO's second DSP Program provides for the recovery of AEPS compliance costs through the GSA rather than a separate AEPS rider. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In the second DSP Program, PECO is procuring electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small, medium, and large commercial classes that will begin in June 2014. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations and Comprehensive Income. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from electric generation suppliers beginning April 1, 2014. On May 1, 2013, PECO filed a Petition for Approval of its CAP Shopping Plan with the PAPUC, which the PAPUC granted and denied in part on January 9, 2014. PECO and other parties to the proceeding filed petitions for reconsideration of the Commission's decision on February 10, 2014, and these petitions are currently pending before the PAPUC. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO's Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO's SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO's universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO's SMPIP, under which PECO will deploy the remainder of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 of which $200 million will be funded by SGIG as discussed below. As of December 31, 2013, PECO has spent $423 million and $116 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO's existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of December 31, 2013, PECO has received $190 million of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $3 million as of December 31, 2013, which has been recorded in Other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor's meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Following PECO's decision, as of October 9, 2012 PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period's earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any agreement with the vendor will not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and will receive $12 million in return, of which $7 million has been received as of December 31, 2013. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. As of December 31, 2013 and 2012, $5 million and $17 million, respectively, was recorded on Exelon's and PECO's Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO will reclassify the regulatory asset balance as a receivable, with no gain or loss impacts on future results of operations. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Efficiency Programs (Exelon and PECO). PECO's PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I plan set forth how PECO would meet the required reduction targets established by Act 129's EE&C provisions, which included a 3% reduction in electric consumption in PECO's service territory and a 4.5% reduction in PECO's annual system peak demand in the 100 hours of highest demand by May 31, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The peak demand period ended on September 30, 2012 and PECO communicated its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report for all Phase I targets, was filed with the PAPUC on November 15, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On March 29, 2013, PECO filed a Petition with the PAPUC to change the recovery period of certain Direct Load Control (DLC) Program costs necessary to implement the Phase I Plan. The Petition sought approval to allow PECO to recover $12 million in equipment, installation and information technology costs for its Residential DLC program with the amounts collected for the Phase I Plan. As the Phase I Plan was implemented at a cost less than originally budgeted, PECO proposed to recover these expenses from its Phase I Energy Efficiency Program Charge over-collection consistent with PAPUC guidance to recover all Phase I costs through Phase I funding. The PAPUC approved PECO's Petition on May 9, 2013. A regulatory liability was established for the DLC program costs that will be amortized as a credit to the income statement to offset the related depreciation expense during the same period. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirements for the second phase of Act 129's EE&C programs, which went into effect on June 1, 2013. The order tentatively established PECO's three-year cumulative consumption reduction target at 1,125,852 MWh, which was reaffirmed by the PAPUC on December 5, 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II plan with the PAPUC on November 1, 2012. The plan sets forth how PECO will reduce electric consumption by at least 1,125,852 MWh in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO's public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company's total annual revenue as of December 31, 2006. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On March 15, 2013, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2013 to May 31, 2014. PECO proposed to fund the estimated $10 million costs of the one-year program by modifying incentive levels for other Phase II programs. On May 9, 2013, the PAPUC approved PECO's amended EE&C Phase II plan. The costs of DLC program will be recovered through PECO's Energy Efficiency Program Charge along with all other Phase II Plan costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. The comment process is scheduled to be completed in the first quarter of 2014. Any decision reached would affect PECO's EE&C Plan subsequent to its Phase II Plan. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2011, following the expiration of PECO's rate cap transition period, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 and the AEPS Act. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO has entered into five-year and ten-year agreements with accepted bidders, including Generation, totaling 452,000 non-solar and 8,000 solar Tier I AECs annually in accordance with a PAPUC approved plan. The plan allowed PECO to bank AECs procured prior to 2011 and use the banked AECs to meet its AEPS Act obligations over two compliance years ending May 2013. The PAPUC also approved the procurement of Tier II AECs and supplemental AECs as well as the sale of excess AECs through independent third-party auctions or brokers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
All AEPS administrative costs and costs of AECs incurred after December 31, 2010 are being recovered on a full and current basis from default service customers through a surcharge. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO's second DSP Program eliminated the AEPS surcharge. Beginning in June 2013, AEPS compliance costs are being recovered through the GSA. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Investigation of Pennsylvania Retail Electricity Market (Exelon and PECO). On July 28, 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania's retail electric market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. On March 1, 2012, the PAPUC issued the final order describing more detailed recommendations to be implemented prior to the expiration of the electric distribution company's current default service plan and providing guidelines for electric distribution companies for development of their next default service plan. On October 12, 2012, the PAPUC approved PECO's second DSP Program, which includes several new programs to continue PECO's support of retail market competition in Pennsylvania in accordance with the order issued by the PAPUC on December 15, 2011. Further, the PAPUC issued a final order on February 14, 2013, outlining its proposed end-state for default service, which included default service pricing for residential and small commercial customers based on three month full requirements contracts, full requirement contracts using hourly spot market pricing for large commercial and industrial default service customers, and the inclusion of CAP customers in the customer choice programs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC's authority to approve alternative ratemaking mechanisms, which would allow for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities' aging electric and natural gas distribution systems in Pennsylvania. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first year rates are in effect. On August 2, 2012, the PAPUC issued a final order establishing rules and procedures to implement the ratemaking provisions of Act 11. The implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing a DSIC. On May 9, 2013, the PAPUC approved PECO's LTIIP for its Gas Operations, which was filed on February 8, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Maryland Regulatory Matters | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs are being recovered over a 5-year period that began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. On February 22, 2013, the MDPSC issued an order in BGE's 2012 electric and natural gas distribution rate case for increases in annual distribution service revenue of $81 million and $32 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on merger integration costs incurred during the test year, including severance. As a result, the order affirmed the treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSC decisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance merger integration costs, which includes $6 million of costs incurred during 2012. Current MDPSC treatment of these merger integration regulatory assets is to provide recovery over a five year period. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE's application includes a request for recovery of incremental capital expenditures and operating costs associated with BGE's proposed short-term reliability improvement plan in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. On December 13, 2013, the MDPSC issued an order in BGE's 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after December 13, 2013. The MDPSC also conditionally approved five of the eight programs included in BGE's proposed short-term reliability improvement plan. Commencement of the program and recovery are dependent on final MDPSC approval with the surcharge starting no earlier than April 1, 2014. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million. The MDPSC's approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of December 31, 2013 and December 31, 2012, BGE recorded a regulatory asset of $66 million and $31 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding. The MDPSC continues to evaluate the impacts of a customer opt-out feature in BGE's Smart Grid program. In March 2013, BGE filed a description of the overall additional costs associated with allowing customers to retain their current meter, and for radio frequency (RF)-Free and RF-Minimizing options related to the installation of their smart meters as well as a proposed cost recovery mechanism. The MDPSC held a hearing in August 2013 to consider the filings made by BGE and other Maryland electric utilities. The ultimate resolution related to this feature could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system. Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs. Pursuant to the ARRA of 2009, BGE is a recipient of $200 million in federal funding from the DOE for its smart grid and other related initiatives, which substantially reduces the total cost of these initiatives to BGE's ratepayers. The project to install the smart meters began in late April 2012. As of December 31, 2013, BGE had received $200 million in reimbursements from the DOE. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that CPV projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other utilities pay (or receive) the difference between CPV's contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The MDPSC's Order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOS load. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On April 16, 2013, the MDPSC issued an order that required BGE to execute a specific form of contract with CPV, and the parties executed the contract as of June 6, 2013. As of December 31, 2013, there is no impact on Exelon's and BGE's results of operations, cash flows and financial positions. Furthermore, the agreement does not become effective until the resolution of certain items, including all current litigation. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On April 27, 2012, a civil complaint was filed in the U.S. District Court for the District of Maryland by certain unaffiliated parties that challenges the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC's Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United States Constitution. On November 22, 2013, the MDPSC and CPV appealed the District Court's ruling to the United States Court of Appeals for the Fourth Circuit. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order under state law. That petition was subsequently transferred to the Circuit Court for Baltimore City and consolidated with similar appeals that have been filed by other interested parties. On October 1, 2013, the Circuit Court Judge issued a Memorandum Opinion and Order finding the decisions of the MDPSC were within its statutory authority under Maryland law. This decision is separate from the judgment in the federal litigation that the MDPSC Order is unconstitutional and the CfD is unenforceable under federal law. The federal judgment, if upheld, would prevent enforcement of the CfD even if the Circuit Court decision stands. On October 29, 2013, BGE and the two other Maryland utilities appealed the Circuit Court's ruling to the Maryland Court of Special Appeals. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Depending on the ultimate outcome of the pending state and federal litigation, on the eventual market conditions, and on the manner of cost recovery as of the effective date of the agreement, the CfD could have a material impact on Exelon and BGE's results of operations, cash flows and financial positions. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon believes that this and other states' projects may have artificially suppressed capacity prices in PJM and may continue to do so in future auctions to the detriment of Exelon's market driven position. In addition to this litigation, Exelon is working with other market participants to implement market rules that will appropriately limit the market suppressing effect of such state activities. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and other Maryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due at various times before August 30, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures and operating costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. The MDPSC held evidentiary hearings on BGE's proposed plan and surcharge from November 12, 2013 through November 14, 2013. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE's plan and surcharge. BGE must submit a list detailing specific projects planned for 2014 to the MDPSC for approval within 30 days of the decision. Upon approval of the project list by the MDPSC, BGE will be able to implement the surcharge rates on gas customers' bills. The new surcharges are expected to take effect in second quarter of 2014. In addition, BGE will be subject to an annual independent audit to review plan performance and progress. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Federal Regulatory Matters | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Transmission Formula Rate (Exelon, ComEd and BGE). ComEd's and BGE's transmission rates are each established based on a FERC-approved formula. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
ComEd's most recent annual formula rate update filed in April 2013 reflects 2012 actual costs plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a net revenue requirement of $513 million. This compares to the May 2012 updated revenue requirement of $450 million offset by a $5 million reduction related to the reconciliation of 2011 actual costs for a net revenue requirement of $445 million. The increase in the revenue requirement was primarily driven by increased capital investment, higher pension and post-retirement healthcare costs, and higher operating and maintenance costs. The 2013 net revenue requirement became effective June 1, 2013, and is being recovered over the period extending through May 31, 2014. The regulatory asset associated with the true-up is being amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.70%, a decrease from the 8.91% return previously authorized. The decrease in return was primarily due to lower interest rates on ComEd's long-term debt outstanding. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.5% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the formula transmission rate is currently capped at 55%. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
BGE's most recent annual formula rate update filed in April 2013 reflects actual 2012 expenses and investments plus forecasted 2013 capital additions. The update resulted in a revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. This compares to the April 2012 updated revenue requirement of $156 million increased by $2 million related to the reconciliation of 2011 actual costs for a net revenue requirement of $158 million. The decrease in the revenue requirement was primarily driven by a lower allowed rate of return associated with a reduced equity ratio and reduced rate base, offset partially by higher depreciation and operating and maintenance costs. The 2013 net revenue requirement became effective June 1, 2013, and is being recovered over the period extending through May 31, 2014. The regulatory liability associated with the true-up is being amortized as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.35%, a decrease from the 8.43% included in the prior year formula update. The decrease in return was primarily due to a debt issuance in 2012 and lower interest rates on BGE's debt outstanding. As part of the FERC-approved settlement in 2006 of BGE's 2005 transmission rate case, the base rate of return on common equity for BGE's electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the Pepco Holdings, Inc. companies relating to their respective transmission formula rates. BGE's formula rate includes a 10.8% base rate of return on common equity (ROE) for most investments included in its rate base and 11.3% for the remaining transmission investment (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the earliest date from which the base return on equity could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint. As of December 31, 2013, BGE cannot predict the likelihood or a reasonable estimate of the amount of a change, if any, in the allowed base return on equity, or a reasonable estimate of the refund period start date. While BGE cannot predict the outcome of this matter, if FERC orders a reduction of BGE's base return on equity to 8.7% (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the estimated annual impact would be a reduction in revenues of approximately $10 million. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM's current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, that court issued its decision affirming FERC's order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing of its March 30, 2012 Order and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. ComEd, and BGE anticipate that all impacts of any rate design changes effective after December 31, 2006 and June 30, 2006, respectively, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on their respective results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO's 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO's results of operations, cash flows or financial position. To the extent that any rate design changes are retroactive to periods prior to January 1, 2011, however, there may be an impact on PECO's results of operations. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On October 11, 2012, the PJM Transmission Owners filed with FERC a cost allocation for new transmission facilities asking that the new cost allocation methodology apply to all transmission approved by the PJM Board on or after February 1, 2013. The proposed methodology is a hybrid methodology that would socialize 50% of the costs of new facilities at 500kV and above and double-circuit 345kV lines, and allocate the remaining 50% to direct beneficiaries. For all other facilities, the costs would be allocated to the direct beneficiaries. On March 22, 2013, FERC issued an order accepting the cost allocation with minor exceptions and requiring a compliance filing on those few issues within 120 days of the order. The compliance filing was made on July 22, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE's estimated commitments are as follows: | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||||||||||||||||||||||||||||
ComEd | $ | 486 | $ | 134 | $ | 173 | $ | 177 | $ | 2 | $ | 0 | ||||||||||||||||||||||||||||||||||||||||
PECO | 133 | 32 | 29 | 40 | 24 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||
BGE | 400 | 42 | 83 | 95 | 87 | 93 | ||||||||||||||||||||||||||||||||||||||||||||||
PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The proceedings leading to FERC's approval of the MOPR were extensive, and there have been numerous changes to the MOPR and litigation related to it since it was originally implemented. For example, in 2011 the parties disputed numerous elements of the MOPR including: (i) the default price that should apply to bids found subject to the MOPR, (ii) the duration of the MOPR and (iii) the application of the MOPR to self-supplying capacity and state-sponsored capacity. The FERC orders approving that MOPR have been appealed to the United States Court of Appeals for the Third Circuit. A resolution of that appeal is not expected until sometime in 2014. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In May 2012 (based on the MOPR provisions the FERC approved in 2011), PJM announced the results of its capacity auction covering the delivery year ending May 31, 2016. Several new units with state-sanctioned subsidy contracts cleared in the auction at prices below the MOPR. Potentially, these states could expand such state-sanctioned subsidy programs or other states may seek to establish similar programs. Generation believed that further revisions to that MOPR were necessary to ensure that the potential to artificially reduce capacity auction prices is appropriately limited in PJM. In early December 2012, PJM filed a new MOPR for approval at the FERC, which Exelon believed would be more effective in preventing state-sanctioned subsidy contracts from artificially reducing capacity prices. Generation was actively involved in the process through which those MOPR changes were developed and supported the changes. On May 3, 2013, the FERC issued its order. While the FERC order accepted certain aspects of the proposal that Exelon supported (such as applying the MOPR to all of PJM and not just certain zones within PJM), the FERC required PJM to retain a key element of its previous MOPR structure, the unit-specific exemption, an element that Exelon had supported removing. Several entities, including two capacity suppliers that Exelon has been working with sought rehearing of that order. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
In May 2013 (based on the MOPR provisions the FERC approved earlier that month), PJM announced the results of its capacity auction covering the delivery year ending May 31, 2017. Exelon is working with PJM stakeholders on several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts, excessive imported capacity resources and certain limited availability demand response resources) cannot inappropriately affect capacity auction prices in PJM. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Market-Based Rates (Exelon, Generation, ComEd, PECO and BGE). Generation, ComEd, PECO and BGE are public utilities for purposes of the Federal Power Act and are required to obtain FERC's acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd, PECO and BGE have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds in certain instances if it finds that the market-based rates are not just and reasonable under the Federal Power Act. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
As required by FERC's regulations, as promulgated in the Order No. 697 series, Generation, ComEd, PECO and BGE file market power analyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates in the regions where they are selling energy, capacity, and ancillary services under market-based rate tariffs. FERC accepted the 2008 filings on September 16, 2008, January 15, 2009 and September 2, 2009 and accepted the 2009 filings on July 28, 2009, October 26, 2009, February 23, 2010 and April 30, 2010, affirming Exelon's affiliates continued right to make sales at market-based rates. These analyses must examine historic test period data and must be updated every three years on a prescribed schedule. Generation, ComEd, PECO and BGE filed an updated analysis for the Northeast Region, which includes PJM, in late 2010, based on 2009 historic test period data. On June 22, 2011, FERC issued an order confirming Generation's continued authority to charge market based rates, based on Generation's most recent updated analysis filed in 2010, stating that any market power concerns are adequately addressed by PJM's monitoring and mitigation programs. On December 30, 2013, Generation, ComEd, PECO and BGE filed its updates analysis for the Northeast Region, based on 2012 historic test period data and FERC has not yet acted on the filing. Similarly, on June 29, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012, and on December 23, 2011, Generation filed its updated market power analysis for the Southeast Region which the FERC accepted on October 10, 2012. On December 21, 2012, Generation, ComEd, BGE and PECO filed their updated market power analysis for the SPP region, which the FERC accepted on October 8, 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Reliability Pricing Model (Exelon, Generation and BGE). PJM's RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2017 occurred in May 2013. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC's temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court's decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule which is now not expected until October 3, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 at the earliest. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The FERC extended the deadline to January 31, 2014 to file a water quality certification application pursuant to Section 401 of the Clean Water Act (CWA) with the MDE for Conowingo. Generation is working with stakeholders to resolve licensing issues, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. Resolution of these issues relating to Conowingo may have a material effect on Generation's results of operations and financial position through an increase in capital expenditures and operating costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
On August 29, 2013, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with PA DEP for Muddy Run, addressing these and other issues that included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $20 million to $30 million, and will include both an increase in capital expenditures as well as an increase in operating expenses. Exelon anticipates that the PA DEP will issue the water quality certification pursuant to Section 401 of the CWA for Muddy Run in the first quarter of 2014. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run's current license on August 31, 2014, and the expiration of Conowingo's license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications. The stations are currently being depreciated over their useful lives, which includes the license renewal period. As of December 31, 2013, $33 million of direct costs associated with relicensing efforts have been capitalized. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon, ComEd, PECO and BGE prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2013 and 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||||||||||||||||||||||||
Pension and other postretirement | ||||||||||||||||||||||||||||||||||||||||||||||||||||
benefits | $ | 221 | $ | 2,794 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||||||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | 0 | 1,317 | 8 | 77 | ||||||||||||||||||||||||||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | 0 | 58 | 0 | 66 | ||||||||||||||||||||||||||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Under-recovered distribution service | ||||||||||||||||||||||||||||||||||||||||||||||||||||
costs | 178 | 285 | 178 | 285 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | ||||||||||||||||||||||||||||||||||||||||||||
Fair value of BGE long-term debt | 0 | 219 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Fair value of BGE supply contract | 12 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Severance | 16 | 12 | 12 | 0 | 0 | 0 | 4 | 12 | ||||||||||||||||||||||||||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | 0 | 25 | 0 | 10 | ||||||||||||||||||||||||||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Under-recovered uncollectible | ||||||||||||||||||||||||||||||||||||||||||||||||||||
accounts | 0 | 48 | 0 | 48 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs | 53 | 0 | 52 | 0 | 0 | 0 | 1 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Deferred storm costs | 3 | 3 | 0 | 0 | 0 | 0 | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||
Electric generation-related | ||||||||||||||||||||||||||||||||||||||||||||||||||||
regulatory asset | 13 | 30 | 0 | 0 | 0 | 0 | 13 | 30 | ||||||||||||||||||||||||||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | 0 | 0 | 0 | 0 | 71 | 154 | ||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||||||||||||||||||||||||
response programs | 73 | 148 | 0 | 0 | 0 | 0 | 73 | 148 | ||||||||||||||||||||||||||||||||||||||||||||
Merger integration costs | 2 | 9 | 0 | 0 | 2 | 9 | ||||||||||||||||||||||||||||||||||||||||||||||
Other | 31 | 39 | 18 | 26 | 8 | 7 | 4 | 6 | ||||||||||||||||||||||||||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | ||||||||||||||||||||||||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||||||||||||||||
Nuclear decommissioning | 0 | 2,740 | 0 | 2,293 | 0 | 447 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | 0 | 0 | 21 | 204 | ||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand | ||||||||||||||||||||||||||||||||||||||||||||||||||||
response programs | 53 | 0 | 45 | 0 | 8 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
DLC program costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency phase II | 0 | 21 | 0 | 0 | 0 | 21 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | 0 | 0 | 20 | 114 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | 0 | 0 | 8 | 37 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs | 78 | 0 | 9 | 0 | 58 | 0 | 11 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Over-recovered gas and electric | ||||||||||||||||||||||||||||||||||||||||||||||||||||
universal service fund costs | 8 | 0 | 0 | 0 | 8 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Revenue subject to refund | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Over-recovered electric and gas | ||||||||||||||||||||||||||||||||||||||||||||||||||||
revenue decoupling | 16 | 0 | 0 | 0 | 0 | 0 | 16 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Other | 4 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | ||||||||||||||||||||||||||||||||||||
Pension and other postretirement benefits. As of December 31, 2013, Exelon had regulatory assets of $3,015 million and regulatory liabilities of $45 million related to ComEd's and BGE's portion of deferred costs associated with Exelon's pension plans and ComEd's, PECO's and BGE's portion of deferred costs associated with Exelon's other postretirement benefit plans. PECO's pension regulatory recovery is based on cash contributions and is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon's pension and other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the merger related to BGE's portion of the deferred costs associated with legacy Constellation's pension and other postretirement benefit plans. The BGE-related regulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at the date of the merger. See Note 16 – Retirement Benefits for additional detail. No return is earned on Exelon's regulatory asset. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with accelerated depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For ComEd and BGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. ComEd was granted recovery of these additional income taxes on May 24, 2011 in the ICC's 2010 Rate Case order. The recovery period for these costs is through May 31, 2014. For BGE, these additional income taxes are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC's March 2011 rate order. See Note 14—Income Taxes and Note 16—Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
AMI programs. For ComEd, this amount represents operating and maintenance expenses and meter costs associated with ComEd's AMI pilot program approved in the May 24, 2011, ICC order in ComEd's 2010 rate case. The recovery periods for operating and maintenance expenses and meter costs are through May 31, 2014, and January 1, 2020, respectively. As of December 31, 2013, ComEd had regulatory assets of $35 million related to accelerated depreciation costs resulting from the early retirements of non-AMI meters, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the meter costs. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to the PAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating and maintenance expenses. The approved plan allows for recovery of filing and implementation costs incurred through December 31, 2012. In addition, the approved plan provides for recovery of program costs, which includes depreciation on new equipment placed in service, beginning in January 2011 on full and current basis, which includes interest income or expense on the under or over recovery. The approved plan also provides for recovery of accelerated depreciation on PECO's non-AMI meter assets over a 10-year period ending December 31, 2020. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatory asset, and, beginning with the MDPSC's March 2011 rate order, is earning BGE's most current authorized rate of return. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an authorized rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC order requires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. Therefore, the commencement and timing of the amortization of these deferred costs is currently unknown. BGE's AMI regulatory asset excludes costs for non-AMI meters being replaced by AMI meters, as the MDPSC has ordered that the cost recovery for non-AMI meters will be considered in a future depreciation proceeding. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
AMI Meter Events. This amount represents the remaining cost value of the original smart meters, net of accumulated depreciation, DOE reimbursements and amounts recovered from the vendor, of smart meter deployment that will no longer be used, including installation and removal costs. PECO intended to seek through regulatory rate recovery in a future filing with the PAPUC, any amounts no recovered from the vendor. PECO believed the amounts incurred for the original meters and related installation and removal costs were probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO has deferred these costs on Exelon's and PECO's Consolidated Balance Sheet. PECO will not earn a return on the recovery of these costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Under-recovered distribution services costs. Under EIMA, which became effective in the fourth quarter of 2011, ComEd is allowed recovery of distribution services costs through a formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to reflect the actual costs that the ICC determines are prudently and reasonably incurred in a given year. The over recovery associated with the 2011 reconciliation was recovered through rates over a one-year period, that began in January 2013. The under recovery associated with the 2012 reconciliation will be recovered through rates over a one-year period beginning in January 2014. ComEd is earning a return on these costs. The regulatory asset also includes costs associated with certain one-time events, such as large storms, which will be recovered over a five-year period. As of December 31, 2013, the regulatory asset was comprised of $377 million for the annual reconciliation and $86 million related to significant one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2013 balance related to significant one-time events contains $28 million of merger and integration related costs, net of amortization, incurred as a result of the merger. As of December 31, 2012, the regulatory asset was comprised of $125 million for the annual reconciliation and $84 million related to significant one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2012 balance related to significant one-time events contains $26 million of merger and integration related costs, net of amortization, incurred as a result of the merger. See Note 4 – Mergers and Acquisitions for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd's, PECO's and BGE's recoverable losses on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on the recovery of these costs, while PECO is earning a return on the premium of the cost of the reacquired debt through base rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of BGE long-term debt. These amounts represent the regulatory asset recorded at Exelon for the difference in the fair value of the long-term debt of BGE as of the merger date based on the MDPSC practice to allow BGE to recover its debt costs through rates. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair value of BGE supply contract. These amounts represent the regulatory asset recorded at Exelon representing the fair value of BGE's supply contracts as of the close of the merger date based on the MDPSC practice to allow BGE to recover its supply contracts through rates. Exelon is amortizing the regulatory asset and the associated fair value over a period of approximately three years. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance. For ComEd, these costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006, ICC rehearing rate order and the May 24, 2011, ICC order in ComEd's 2010 rate case. The recovery periods are through June 30, 2014, and May 31, 2014, respectively. ComEd is not earning a return on these costs. For BGE, these costs represent deferred severance costs that BGE has previously been granted recovery of in rates. Costs include the portion of costs associated with a 2008 workforce reduction that relate to BGE's gas business which were deferred in 2009 as a regulatory asset in accordance with the MDPSC's orders in prior rate cases and are being amortized over a 5-year period that began in January 2009. Also included are costs associated with a 2010 workforce reduction that were deferred as a regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC's March 2011 rate order. Finally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with the MDPSC's orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on the regulatory asset included in base rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd and BGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. See Note 15—Asset Retirement Obligations for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
MGP remediation costs. Recovery of these items was granted to ComEd in the July 26, 2006, ICC rate order. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. These costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. BGE is earning a return on this regulatory asset. See Note 22—Commitments and Contingencies for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
RTO start-up costs. Recovery of these RTO start-up costs was approved by FERC. The recovery period is through March 31, 2015. ComEd is earning a return on these costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Under (Over)-recovered universal service fund costs. The universal service fund cost is a recovery mechanism that allows PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2013, PECO was over-recovered for both its electric and gas programs. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial swap with Generation. To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap contract with Generation that expired on May 31, 2013. Since the swap contract was deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period were recorded by ComEd as well as an offsetting regulatory asset or liability. ComEd did not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position was based on the difference between ComEd's cost to purchase energy on the spot market and the contracted price. In Exelon's consolidated financial statements, the fair value of the intercompany swap recorded by Generation and ComEd was eliminated. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable Energy. On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd's cost to purchase energy on the spot market and the contracted price. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy and transmission programs. Starting in 2007, ComEd's energy and transmission costs are recoverable (refundable) under ComEd's ICC and/or FERC-approved rates. ComEd earns interest on under-recovered costs and pays interest on over-recovered costs to customers. The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO's GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. In addition, beginning in 2013, the deferred DSP I and II Program costs are presented on a net basis with PECO's GSA under (over)-recovered energy costs. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2013, PECO had a regulatory liability that included the over-recovered electric transmission costs of $8 million, $34 million related to the DSP program and $16 million related to over-recovered natural gas supply costs under the PGC. As of December 31, 2012, PECO had a regulatory asset related to under-recovered transmission costs of $1 million and a regulatory liability that included $47 million related to over-recovered electric supply costs under the GSA and $1 million related to over-recovered natural gas supply costs under the PGC. The BGE energy costs represent the electric and gas supply related costs recoverable (refundable) from (to) customers under BGE's market-based SOS and MBR programs, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. As of December 31, 2013, BGE had a regulatory asset of $1 million related to under-recovered electric supply costs and a regulatory liability of $11 million related to over-recovered natural gas supply costs. As of December 31, 2012, BGE had a regulatory asset of $9 million related to under-recovered electric supply costs and a regulatory asset of $19 million related to under-recovered natural gas supply costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
DSP Program costs. These amounts represent recoverable administrative costs incurred relating to filing, procurement, and information technology improvements associated with PECO's PAPUC-approved DSP Program for the procurement of electric supply following the expiration of PECO's generation rate caps on December 31, 2010. The filing and implementation costs of this DSP Program are recoverable through the GSA over its 29-month term, that began January 1, 2011. The independent evaluator costs associated with conducting procurements is recoverable over a 12-month period after the PAPUC approves the results of the procurements. Costs relating to information technology improvements are recoverable over a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology costs. Beginning in 2013, these costs are included within the energy and transmission programs line item. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
DSP II Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO's second PAPUC-approved DSP program for the procurement of electric supply. The filing and procurement of this DSP Program are recoverable through the GSA over its 24-month term, that began June 1, 2013. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earning a return on these costs. Beginning in 2013, these costs are included within the energy and transmission programs line item. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred storm costs. In the MDPSC's March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. These costs are being amortized over a 5-year period that began in December 2010. BGE is earning a return on this regulatory asset. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion of this regulatory asset that does not earn a regulated rate of return were $37 million as of December 31, 2013, and $47 million as of December 31, 2012. BGE will continue to amortize this amount through 2017. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006, to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007, to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2013 and 2012, BGE recovered $66 million and $67 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy efficiency and demand response programs. These amounts represent costs recoverable (refundable) under ComEd's ICC approved Energy Efficiency and Demand Response Plan, PECO's PAPUC-approved EE&C Plan, and the BGE Smart Energy Savers Program®. ComEd began recovering these costs or refunding over-collections of these costs on June 1, 2008 through a rider. ComEd earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. For PECO, this amount represents an over-collection of program costs related to both Phase I and Phase II of its EE&C Plan. PECO does not earn (pay) interest on under (over) collections. PECO began recovering the costs of its Phase I and Phase II EE&C Plans through a surcharge in January 2010 and June 2013, respectively, based on projected spending under the programs. Phase I recovery continued over the life of the program, which expired on May 31, 2013 and excess funds collected began being refunded in June 2013. Phase II of the program began on June 1, 2013, and will continue over the life of the program, which will expire on May 31, 2016. Excess funds collected are required to be refunded beginning in June 2016. PECO earned a return on the capital investment incurred under Phase I of the program. BGE's Smart Energy Savers Program® includes both MDPSC approved demand response and energy efficiency programs. For the BGE Peak RewardsSM demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Also included in the demand response program are customer bill credits related to BGE's Smart Energy Rewards program which began in July 2013. Actual costs incurred in the conservation program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger integration costs. These amounts represent integration costs to achieve distribution synergies related to the merger transaction. As a result of the MDPSC's February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC's December 2013 rate order, BGE was authorized to recover the remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset included in base rates. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Under (Over)-recovered electric and gas revenue decoupling. These amounts represent the electric and gas distribution costs recoverable from or refundable to customers under BGE's decoupling mechanism, which does not earn a rate of return. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling. As of December 31, 2012, BGE had a regulatory asset of $5 million related to under-recovered electric revenue decoupling and a regulatory liability of $7 million related to over-recovered natural gas revenue decoupling. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for former ComEd and PECO plants that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated future decommissioning costs at the time of decommissioning. See Note 15—Asset Retirement Obligations for additional information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Removal costs. These amounts represent funds ComEd and BGE have received from customers through depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability is reduced as costs are incurred. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
DLC Program Costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the DLC Program under PECO's EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining useful life of the assets. PECO is not paying interest on these over-recoverd costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric distribution tax repairs. PECO's 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. No interest will be paid to customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs. PECO's 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits began being reflected in customer bills on January 1, 2013. No interest will be paid to customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Under (Over)-recovered uncollectible accounts. As a result of the February 2010 ICC order approving recovery of ComEd's uncollectible accounts, ComEd has the ability to adjust its rates annually to reflect the increases and decreases in annual uncollectible accounts expense starting with year 2008. ComEd recorded a regulatory asset for the cumulative under-collections in 2008 and 2009. Recovery of the initial regulatory asset was completed over an approximate 14-month time frame which began in April 2010. The recovery or refund of the difference in the uncollectible accounts expense applicable to the years starting with January 1, 2010, will take place over a 12-month time frame beginning in June of the following year. ComEd is not earning a return or paying interest on these under (over)-recovered costs. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Under (Over)-recovered AEPS costs current asset (liability). The AEPS costs represent the administrative and AEC costs incurred to comply with the requirements of the AEPS Act, which are recoverable on a full and current basis. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. Beginning in 2013, these costs are included within the energy and transmission programs line item. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue subject to refund. These amounts represent refunds of $37 million and associated interest of $1 million ComEd owes to customers primarily related to the treatment of post-test year accumulated depreciation issue in the 2007 Rate Case. See above discussion of the 2007 Rate Case for further information. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE) | ||||||||||||||||||||||||||||||||||||||||||||||||||||
ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities' consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd purchases receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. BGE's tariff provides that receivables are to be purchased at a discount, primarily to recover uncollectible accounts expense from the suppliers. However, if the discount rate is negative, the tariff provides that the receivable is purchased at a zero discount rate. BGE is currently purchasing certain receivables at a zero discount rate. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are classified in other accounts receivable, net on Exelon's, ComEd's, PECO's and BGE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of December 31, 2013 and 2012. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 263 | $ | 105 | $ | 72 | $ | 86 | ||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -30 | -16 | -7 | -7 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables, net | $ | 233 | $ | 89 | $ | 65 | $ | 79 | ||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 191 | $ | 55 | $ | 65 | $ | 71 | ||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -21 | -9 | -6 | -6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables, net | $ | 170 | $ | 46 | $ | 59 | $ | 65 | ||||||||||||||||||||||||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Investment_in_Constellation_En
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | 12 Months Ended | ||||||
Dec. 31, 2013 | |||||||
Equity Method Investments and Joint Ventures [Line Items] | ' | ||||||
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ' | ||||||
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | |||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | |||||||
Year Ended | Period March 12, | ||||||
Ended December 31, | through December 31, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 123 | $ | 73 | |||
Amortization of basis difference in CENG | -114 | -172 | |||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 | |||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | |||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | |||||||
Generation has various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements see Note 25 – Related Party Transactions. | |||||||
On July 29, 2013, Exelon, Generation and subsidiaries of Generation entered into a Master Agreement with EDF, EDF Inc. (EDFI) (a subsidiary of EDF) and CENG. The Master Agreement contemplates that the parties will execute a series of additional agreements at a closing that will occur following the receipt of regulatory approvals and the satisfaction of other customary closing conditions. Exelon currently expects that the closing will occur early in the second quarter of 2014. | |||||||
The Master Agreement requires CENG to make two pre-closing cash distributions to EDF and Generation, if CENG has cash in excess of reserves and the amount of an outstanding credit facility are available, through one of its wholly owned subsidiaries, as owners of the joint venture. Generation received the first distribution of $115 million in December 2013 and recorded it as a reduction to the Investment in CENG on Exelon's and Generation's Consolidated Balance Sheets. A second distribution will occur prior to the closing provided that CENG has sufficient available cash. | |||||||
At the closing, Generation, CENG and subsidiaries of CENG will execute a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG. CENG will reimburse Generation for its direct and allocated costs for such services. The NOSA will replace the SSA. At the closing, Nine Mile Point Nuclear Station, a subsidiary of CENG, will also assign to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with the co-owner. In addition, at the closing the PSAA will be amended and extended until the permanent cessation of power generation by the CENG generation plants. | |||||||
In addition, at closing, Generation will make a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and in any event, payable upon the settlement of the Put Option Agreement discussed below, if the put option is exercised, or payable upon the maturity date of the note (which will be 20 years from the closing), whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG will make a $400 million special distribution to EDFI. The parties will also execute a Fourth Amended and Restated Operating Agreement for CENG, pursuant to which, among other things, CENG will commit to make preferred distributions to Generation (after repayment of the $400 million loan) quarterly out of specified available cash flows, until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from the date of the special distribution to EDFI. | |||||||
Generation and EDFI will also enter into a Put Option Agreement at closing pursuant to which EDFI will have the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the Nuclear Operating Services Agreement. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | |||||||
Also at closing, Generation will execute an Indemnity Agreement pursuant to which Generation will indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon will guarantee Generation's obligations under this indemnity. | |||||||
Currently, Exelon and Generation account for their investment in CENG under the equity method of accounting. The transfer of the operating licenses and corresponding operational control to Exelon and Generation will result in Exelon and Generation being required to consolidate the financial position and results of operations of CENG. When that accounting change occurs, Exelon and Generation will derecognize their equity method investment in CENG and will record all assets, liabilities and the non-controlling interest in CENG at fair value on Exelon and Generation's balance sheets. Any difference between the former carrying value and newly recorded fair value at that date will be recognized as a gain or loss upon consolidation, which could be material to Exelon's and Generation's results of operations. | |||||||
Exelon Generation Co L L C [Member] | ' | ||||||
Equity Method Investments and Joint Ventures [Line Items] | ' | ||||||
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | ' | ||||||
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | |||||||
As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation's total equity in earnings (losses) on the investment in CENG is as follows: | |||||||
Year Ended | Period March 12, | ||||||
Ended December 31, | through December 31, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 123 | $ | 73 | |||
Amortization of basis difference in CENG | -114 | -172 | |||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 | |||
As of March 12, 2012, Generation had an initial basis difference of approximately $204 million between the initial carrying value of its investment in CENG and its underlying equity in CENG. This basis difference resulted from the requirement to record the investment in CENG at fair value under purchase accounting while the underlying assets and liabilities within CENG continue to be accounted for on a historical cost basis. Generation is amortizing this basis difference over the respective useful lives of the assets and liabilities of CENG or as those assets and liabilities affect the earnings of CENG. | |||||||
Based on tax sharing provisions contained in the operating agreement for CENG, Generation may be eligible for distributions from its investment in CENG in excess of its 50.01% ownership interest. Through purchase accounting, Generation has recorded the fair value of expected future distributions. When these distributions are realized, Generation will record a reduction in its investment in CENG. Any distributions in excess of Generation's investment in CENG would be recorded in earnings. | |||||||
Generation has various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements see Note 25 – Related Party Transactions. | |||||||
On July 29, 2013, Exelon, Generation and subsidiaries of Generation entered into a Master Agreement with EDF, EDF Inc. (EDFI) (a subsidiary of EDF) and CENG. The Master Agreement contemplates that the parties will execute a series of additional agreements at a closing that will occur following the receipt of regulatory approvals and the satisfaction of other customary closing conditions. Exelon currently expects that the closing will occur early in the second quarter of 2014. | |||||||
The Master Agreement requires CENG to make two pre-closing cash distributions to EDF and Generation, if CENG has cash in excess of reserves and the amount of an outstanding credit facility are available, through one of its wholly owned subsidiaries, as owners of the joint venture. Generation received the first distribution of $115 million in December 2013 and recorded it as a reduction to the Investment in CENG on Exelon's and Generation's Consolidated Balance Sheets. A second distribution will occur prior to the closing provided that CENG has sufficient available cash. | |||||||
At the closing, Generation, CENG and subsidiaries of CENG will execute a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG. CENG will reimburse Generation for its direct and allocated costs for such services. The NOSA will replace the SSA. At the closing, Nine Mile Point Nuclear Station, a subsidiary of CENG, will also assign to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with the co-owner. In addition, at the closing the PSAA will be amended and extended until the permanent cessation of power generation by the CENG generation plants. | |||||||
In addition, at closing, Generation will make a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and in any event, payable upon the settlement of the Put Option Agreement discussed below, if the put option is exercised, or payable upon the maturity date of the note (which will be 20 years from the closing), whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG will make a $400 million special distribution to EDFI. The parties will also execute a Fourth Amended and Restated Operating Agreement for CENG, pursuant to which, among other things, CENG will commit to make preferred distributions to Generation (after repayment of the $400 million loan) quarterly out of specified available cash flows, until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from the date of the special distribution to EDFI. | |||||||
Generation and EDFI will also enter into a Put Option Agreement at closing pursuant to which EDFI will have the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the Nuclear Operating Services Agreement. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | |||||||
Also at closing, Generation will execute an Indemnity Agreement pursuant to which Generation will indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon will guarantee Generation's obligations under this indemnity. | |||||||
Currently, Exelon and Generation account for their investment in CENG under the equity method of accounting. The transfer of the operating licenses and corresponding operational control to Exelon and Generation will result in Exelon and Generation being required to consolidate the financial position and results of operations of CENG. When that accounting change occurs, Exelon and Generation will derecognize their equity method investment in CENG and will record all assets, liabilities and the non-controlling interest in CENG at fair value on Exelon and Generation's balance sheets. Any difference between the former carrying value and newly recorded fair value at that date will be recognized as a gain or loss upon consolidation, which could be material to Exelon's and Generation's results of operations. |
Accounts_Receivable_Exelon_Gen
Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Accounts Receivables [Line Items] | ' | ||||||||||||
Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||
6. Accounts Receivable (Exelon, Generation, ComEd PECO and BGE) | |||||||||||||
Accounts receivable at December 31, 2013 and 2012 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows: | |||||||||||||
2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||
Unbilled customer revenues | $ | 1,151 | $ | 584 | (a) | $ | 201 | $ | 161 | $ | 205 | ||
Allowance for uncollectible accounts(b) | -272 | -57 | -62 | -107 | (c) | -46 | |||||||
2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||
Unbilled customer revenues | $ | 1,094 | $ | 535 | (a) | $ | 213 | $ | 164 | $ | 182 | ||
Allowance for uncollectible accounts(b) | -293 | -84 | -70 | -99 | (c) | -40 | |||||||
________________ | |||||||||||||
(a) Represents unbilled portion of retail receivables estimated under Exelon's unbilled critical accounting policy. | |||||||||||||
(b) Includes the allowance for uncollectible accounts on customer and other accounts receivable. | |||||||||||||
(c) Includes an allowance for uncollectible accounts of $8 million and $7 million at December 31, 2013 and 2012, respectively, related to PECO's current installment plan receivables described below. | |||||||||||||
PECO Installment Plan Receivables (Exelon and PECO). PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $19 million and $18 million as of December 31, 2013 and 2012, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 – Significant Accounting Policies. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2013 of $18 million consists of $1 million, $4 million and $13 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2012 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of December 31, 2013 and 2012 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 – Significant Accounting Policies. | |||||||||||||
Accounts Receivable Agreement (Exelon and PECO). PECO was party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its accounts receivable designated under the agreement in exchange for proceeds of $210 million, which was classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets as of December 31, 2012. The agreement terminated on August 30, 2013 and PECO paid down the outstanding principal of $210 million. The financial institution no longer has an undivided interest in the accounts receivable designated under the agreement. As of December 31, 2012, the financial institution's undivided interest in Exelon's and PECO's gross accounts receivable was equivalent to $289 million, which represented the financial institution's interest in PECO's eligible receivables as calculated under the terms of the agreement. The agreement required PECO to maintain eligible receivables at least equivalent to the financial institution's undivided interest. | |||||||||||||
Impairment_of_Longlived_Assets
Impairment of Long-lived Assets (Exelon and Generation) | 12 Months Ended | |||||
Dec. 31, 2013 | ||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ' | |||||
Impairment Of Long Lived Assets Held [Text Block] | ' | |||||
8. Impairment of Long-Lived Assets (Exelon and Generation) | ||||||
Long-Lived Assets (Exelon and Generation) | ||||||
Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the third quarter of 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $43 million was recorded during the third quarter in operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations. Of the $43 million, $4 million was attributable to non-controlling interests for certain of the wind projects. | ||||||
Nuclear Uprate Program (Exelon and Generation) | ||||||
Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. When economically viable, the projects take advantage of new production and measurement technologies, new materials and application of expertise gained from a half-century of nuclear power operations. Based on ongoing reviews, the nuclear uprate implementation plan was adjusted during 2013 to cancel certain projects. The Measurement Uncertainty Recapture (MUR) uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then current market conditions, made the projects not economically viable. Additionally, the market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge to operating and maintenance expense and interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs. | ||||||
Like-Kind Exchange Transaction (Exelon) | ||||||
Prior to the PECO/Unicom Merger in October 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in coal-fired generating station leases located in Georgia and Texas with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. See Note 14 – Income Taxes for further information. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to require the lessees to return the leasehold interests or to arrange for a third-party to bid on a service contract for a period following the lease term. If Exelon chooses the service contract option, the leasehold interests will be returned to Exelon at the end of the term of the service contract. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon's exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases. | ||||||
Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, which takes into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements. | ||||||
Based on the review performed in the second quarter of 2013, the estimated residual value of one of Exelon's direct financing leases experienced an other than temporary decline given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $14 million pre-tax impairment charge in the second quarter of 2013, which was recorded in investments and operating and maintenance expense in the Consolidated Balance Sheet and the Consolidated Statement of Operations, respectively. Changes in the assumptions described above could potentially result in future impairments of Exelon's direct financing lease investments, which could be material. Through December 31, 2013, no events have occurred that would require Exelon to review the estimated residual values of its direct financing lease investments subsequent to the review performed in the second quarter of 2013. | ||||||
As of December 31, 2012, Exelon concluded that the estimated fair values of the residual values at the end of the lease terms exceeded the residual values established at the lease dates. | ||||||
At December 31, 2013 and December 31, 2012, the components of the net investment in long-term leases were as follows: | ||||||
31-Dec-13 | 31-Dec-12 | |||||
Estimated residual value of leased assets | $ | 1,465 | $ | 1,492 | ||
Less: unearned income | 767 | 807 | ||||
Net investment in long-term leases | $ | 698 | $ | 685 |
Property_Plant_and_Equipment_E
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Property, Plant and Equipment Disclosure [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
7. Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||
Exelon | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 28,123 | $ | 26,576 | ||||
Electric—generation | 1 | - | 52 | 20,420 | 19,004 | ||||||
Gas—transportation and distribution | 5 | - | 90 | 3,296 | 3,108 | ||||||
Common—electric and gas | 5 | - | 50 | 1,101 | 1,029 | ||||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,890 | 1,926 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 1,017 | 912 | ||||||
Total property, plant and equipment | 61,043 | 57,370 | |||||||||
Less: accumulated depreciation (c) | 13,713 | 12,184 | |||||||||
Property, plant and equipment, net | $ | 47,330 | $ | 45,186 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes Generation's buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. Also includes ComEd's buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. Includes land held for future use and non utility property at PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category. | |||||||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes Generation's buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. Also includes ComEd's buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. Includes land held for future use and non utility property at PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.76 | % | 2.59 | % | |||||
Electric—generation | 3.35 | % | 3.15 | % | 3.12 | % | |||||
Gas | 2.06 | % | 2.03 | % | 1.73 | % | |||||
Common—electric and gas | 7.53 | % | 7.61 | % | 8.05 | % | |||||
Generation | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—generation | 1 | - | 52 | $ | 20,420 | $ | 19,004 | ||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,129 | 1,352 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 400 | 374 | ||||||
Total property, plant and equipment | 27,145 | 25,545 | |||||||||
Less: accumulated depreciation (c) | 7,034 | 6,014 | |||||||||
Property, plant and equipment, net | $ | 20,111 | $ | 19,531 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.35%, 3.15% and 3.12% for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||
License Renewals. Generation's depreciation provisions are based on the estimated useful lives of its generating stations, which assume the renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information regarding license renewals. | |||||||||||
Plant Retirements | |||||||||||
Schuylkill Station and Riverside Station. On October 31, 2012, Generation notified PJM of its intention to permanently retire Schuylkill Generating Station Unit 1 by February 1, 2013, and Riverside Generating Station Unit 6 by June 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, Pennsylvania, which was placed in service in 1958. Riverside Unit 6 is a 115 MW peaking gas/kerosene unit that was placed in service in 1970, located in Baltimore, Maryland. On December 1, 2013, Generation notified PJM of its intention to permanently retire Riverside Generating Station Unit 4 by June 1, 2016. Riverside Unit 4 is a 74 MW intermediate gas unit that was placed in service in 1951 also located in Baltimore, Maryland. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and declining revenue expectations. On November 30, 2012, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Schuylkill Unit 1 retirement date, and as a result, Schuylkill Unit 1 was retired on January 1, 2013. On January 7, 2013 and December 23, 2013, PJM notified Generation that it did not identify any transmission system reliability issues associated with the retirements of Riverside Units 6 and 4, respectively. The early retirements will not have a material impact on Generation or Exelon's results of operations, cash flows or financial position. | |||||||||||
Eddystone Station and Cromby Station. In December 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit Generation's retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defined compensation to be paid to Generation for continuing to operate Cromby Unit 2 and Eddystone Unit 2. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 was approximately $6 million, and covered operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation was reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 operated under the reliability-must-run agreement from June 1, 2011 until their respective retirement dates, Cromby Unit 2 on December 31, 2011 and Eddystone Unit 2 on May 31, 2012. | |||||||||||
During the years ended December 31, 2013, 2012, and 2011, Generation incurred $1 million, $11 million, and $2 million of shut down costs reflected within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Expense for the write down of inventory was not material for the years ended December 31, 2013, 2012 and 2011. | |||||||||||
ComEd | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 75 | $ | 17,334 | $ | 16,480 | ||||
Construction work in progress | N/A | 456 | 294 | ||||||||
Other property, plant and equipment (a) | 50 | 60 | 50 | ||||||||
Total property, plant and equipment | 17,850 | 16,824 | |||||||||
Less: accumulated depreciation | 3,184 | 2,998 | |||||||||
Property, plant and equipment, net | $ | 14,666 | $ | 13,826 | |||||||
(a) Includes buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.97%, 2.79% and 2.67% for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||
PECO | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 65 | $ | 6,669 | $ | 6,355 | ||||
Gas—transportation and distribution | 5 | - | 70 | 1,932 | 1,859 | ||||||
Common—electric and gas | 5 | - | 50 | 600 | 568 | ||||||
Construction work in progress | N/A | 101 | 76 | ||||||||
Other property, plant and equipment (a) | 50 | 17 | 17 | ||||||||
Total property, plant and equipment | 9,319 | 8,875 | |||||||||
Less: accumulated depreciation | 2,935 | 2,797 | |||||||||
Property, plant and equipment, net | $ | 6,384 | $ | 6,078 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.73 | % | 2.51 | % | 2.33 | % | |||||
Gas | 1.79 | % | 1.77 | % | 1.73 | % | |||||
Common—electric and gas | 6.65 | % | 7.54 | % | 8.05 | % | |||||
BGE | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 6,100 | $ | 5,767 | ||||
Gas—distribution | 5 | - | 90 | 1,660 | 1,548 | ||||||
Common—electric and gas | 5 | - | 40 | 578 | 554 | ||||||
Construction work in progress | N/A | 196 | 193 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 31 | ||||||||
Total property, plant and equipment | 8,566 | 8,093 | |||||||||
Less: accumulated depreciation | 2,702 | 2,595 | |||||||||
Property, plant and equipment, net | $ | 5,864 | $ | 5,498 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.92 | % | 2.89 | % | |||||
Gas | 2.36 | % | 2.33 | % | 2.41 | % | |||||
Common—electric and gas | 8.45 | % | 7.68 | % | 8.4 | % | |||||
See Note 1—Significant Accounting Polices for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 13—Debt and Credit Agreements for further information regarding Exelon's, ComEd's, and PECO's property, plant and equipment subject to mortgage liens. | |||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||
Property, Plant and Equipment Disclosure [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—generation | 1 | - | 52 | $ | 20,420 | $ | 19,004 | ||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,129 | 1,352 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 400 | 374 | ||||||
Total property, plant and equipment | 27,145 | 25,545 | |||||||||
Less: accumulated depreciation (c) | 7,034 | 6,014 | |||||||||
Property, plant and equipment, net | $ | 20,111 | $ | 19,531 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
Commonwealth Edison Co [Member] | ' | ||||||||||
Property, Plant and Equipment Disclosure [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 75 | $ | 17,334 | $ | 16,480 | ||||
Construction work in progress | N/A | 456 | 294 | ||||||||
Other property, plant and equipment (a) | 50 | 60 | 50 | ||||||||
Total property, plant and equipment | 17,850 | 16,824 | |||||||||
Less: accumulated depreciation | 3,184 | 2,998 | |||||||||
Property, plant and equipment, net | $ | 14,666 | $ | 13,826 | |||||||
(a) Includes buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. | |||||||||||
PECO Energy Co [Member] | ' | ||||||||||
Property, Plant and Equipment Disclosure [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 65 | $ | 6,669 | $ | 6,355 | ||||
Gas—transportation and distribution | 5 | - | 70 | 1,932 | 1,859 | ||||||
Common—electric and gas | 5 | - | 50 | 600 | 568 | ||||||
Construction work in progress | N/A | 101 | 76 | ||||||||
Other property, plant and equipment (a) | 50 | 17 | 17 | ||||||||
Total property, plant and equipment | 9,319 | 8,875 | |||||||||
Less: accumulated depreciation | 2,935 | 2,797 | |||||||||
Property, plant and equipment, net | $ | 6,384 | $ | 6,078 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||
Property, Plant and Equipment Disclosure [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 6,100 | $ | 5,767 | ||||
Gas—distribution | 5 | - | 90 | 1,660 | 1,548 | ||||||
Common—electric and gas | 5 | - | 40 | 578 | 554 | ||||||
Construction work in progress | N/A | 196 | 193 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 31 | ||||||||
Total property, plant and equipment | 8,566 | 8,093 | |||||||||
Less: accumulated depreciation | 2,702 | 2,595 | |||||||||
Property, plant and equipment, net | $ | 5,864 | $ | 5,498 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Jointly_Owned_Electric_Utility
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||||||
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | ' | ' | ||||||||||||||||||||||||||||||||||||
Nuclear generation | Fossil fuel generation | Transmission | Other | 9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | ||||||||||||||||||||||||||||||||||
Peach | Exelon, Generation, PECO and BGE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2013 and 2012 were as follows: | |||||||||||||||||||||||||||||||||||||
Quad Cities | Bottom | Salem (a) | Keystone (b) | Conemaugh (b) | Wyman | PA (c) | DE/NJ (d) | Other (e) | ||||||||||||||||||||||||||||||
Operator | Generation | Generation | PSEG Nuclear | GenOn | GenOn | FP&L | First Energy | PSEG | ||||||||||||||||||||||||||||||
Ownership interest | 75 | % | 50 | % | 42.59 | % | 41.98 | % | 31.28 | % | 5.89 | % | Various | 42.55 | % | 44.24 | % | |||||||||||||||||||||
Exelon’s share at | ||||||||||||||||||||||||||||||||||||||
December 31, 2013: | ||||||||||||||||||||||||||||||||||||||
Plant (f) | $ | 941 | $ | 883 | $ | 501 | $ | 725 | $ | 399 | $ | 3 | $ | 14 | $ | 64 | $ | 2 | ||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||||||||||||
depreciation (f) | 226 | 326 | 134 | 268 | 220 | 3 | 7 | 34 | 1 | |||||||||||||||||||||||||||||
Construction | ||||||||||||||||||||||||||||||||||||||
work in progress | 27 | 174 | 24 | 6 | 121 | — | — | — | — | |||||||||||||||||||||||||||||
Exelon’s share at | ||||||||||||||||||||||||||||||||||||||
December 31, 2012: | ||||||||||||||||||||||||||||||||||||||
Plant (f) | $ | 874 | $ | 796 | $ | 494 | $ | 624 | $ | 322 | $ | 3 | $ | 13 | $ | 65 | $ | 1 | ||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||||||||||||
depreciation (f) | 187 | 302 | 119 | 153 | 158 | 3 | 7 | 33 | — | |||||||||||||||||||||||||||||
Construction | ||||||||||||||||||||||||||||||||||||||
work in progress | 44 | 115 | 11 | 10 | 57 | — | 1 | — | — |
Goodwill_Exelon_Generation_Com
Goodwill (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||
Goodwill [Line Items] | ' | |||||||||||||||||||||||||||
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||||||
10. Intangible Assets (Exelon, Generation, ComEd and PECO) | ||||||||||||||||||||||||||||
Goodwill | ||||||||||||||||||||||||||||
Exelon's and ComEd's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2013 and 2012 were as follows: | ||||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||
Gross | Impairment | Carrying | ||||||||||||||||||||||||||
Amount(a) | Losses | Amount | ||||||||||||||||||||||||||
Balance, January 1, 2012 | $ | 4,608 | $ | 1,983 | $ | 2,625 | ||||||||||||||||||||||
Impairment losses | 0 | 0 | 0 | |||||||||||||||||||||||||
Balance, December 31, 2013 | $ | 4,608 | $ | 1,983 | $ | 2,625 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||
(a) Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance. | ||||||||||||||||||||||||||||
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. Under the authoritative guidance for goodwill, a reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and is regularly reviewed by segment management. ComEd has a single operating segment for its combined business. There is no level below this operating segment for which discrete financial information is regularly reviewed by segment management. Therefore, ComEd's operating segment is considered its only reporting unit. | ||||||||||||||||||||||||||||
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test is required. Otherwise, no further testing is required. | ||||||||||||||||||||||||||||
If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative two-step, fair value based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Any goodwill impairment charge at ComEd will affect Exelon's consolidated results of operations. | ||||||||||||||||||||||||||||
ComEd's valuation approach is based on a market participant view, pursuant to authoritative guidance for fair value measurement, and utilizes a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd's business and includes an estimate of ComEd's terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity's residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd's business and the fair value of debt. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon's enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiple analysis. | ||||||||||||||||||||||||||||
2013 Goodwill Impairment Assessments. Management concluded the remeasurement of the like-kind exchange position and the charge to ComEd's earnings in the first quarter of 2013 triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of January 31, 2013. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. | ||||||||||||||||||||||||||||
ComEd performed a quantitative assessment as of November 1, 2013, for its 2013 annual goodwill impairment assessment. The first step of the annual impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. | ||||||||||||||||||||||||||||
In both the interim and annual assessments, the discounted cash flow analysis reflected Exelon's indemnity to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts related to the like-kind exchange position on ComEd's equity. While neither the interim nor the annual assessments indicated an impairment of ComEd's goodwill, certain assumptions used to estimate the fair value of ComEd are highly sensitive to changes. Adverse regulatory actions, such as early termination of EIMA, or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd's business, and the fair value of debt could potentially result in a future impairment of ComEd's goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2013, the estimated fair value of ComEd would have needed to decrease by more than 10% for ComEd to fail the first step of the impairment test. | ||||||||||||||||||||||||||||
Prior Goodwill Impairment Assessments. Management concluded that the May 2012 ICC final Order in ComEd's 2011 formula rate proceeding triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of May 31, 2012. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitative assessment, ComEd evaluated, among other things, management's best estimate of projected operating and capital cash flows for ComEd's business (including the impacts of the May 2012 Order) as well as changes in certain other market conditions, such as the discount rate and EBITDA multiples. | ||||||||||||||||||||||||||||
Other Intangible Assets | ||||||||||||||||||||||||||||
For discussion surrounding Exelon's and Generation's unamortized energy contracts, trade name and retail relationships recorded in conjunction with the Merger, refer to Note 4 – Merger and Acquisitions. | ||||||||||||||||||||||||||||
Exelon's, Generation's and ComEd's other intangible assets, included in unamortized energy contract assets and deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2013: | ||||||||||||||||||||||||||||
Estimated amortization expense | ||||||||||||||||||||||||||||
Weighted Average Amortization Years (e) | Gross | Accumulated Amortization | Net | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||||
Generation (f) | ||||||||||||||||||||||||||||
Exelon Wind acquisition (a) | 18 | $ | 224 | $ | -41 | $ | 183 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | |||||||||||
Antelope Valley acquisition (b) | 25 | 190 | -4 | 186 | 8 | 8 | 8 | 8 | 8 | |||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||
Chicago settlement – 1999 agreement (c) | 21.8 | 100 | -76 | 24 | 3 | 3 | 3 | 4 | 4 | |||||||||||||||||||
Chicago settlement – 2003 agreement (d) | 17.9 | 62 | -38 | 24 | 4 | 4 | 4 | 3 | 3 | |||||||||||||||||||
Total intangible assets | $ | 576 | $ | -159 | $ | 417 | $ | 29 | $ | 29 | $ | 29 | $ | 29 | $ | 29 | ||||||||||||
__________ | ||||||||||||||||||||||||||||
(a) In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735 MWs of installed, operating wind capacity located in eight states. | ||||||||||||||||||||||||||||
(b) Refer to Note 4 – Merger and Acquisitions for additional information regarding Antelope Valley. | ||||||||||||||||||||||||||||
(c) In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd's franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020. | ||||||||||||||||||||||||||||
(d) In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago's behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation's obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement. | ||||||||||||||||||||||||||||
(e) Weighted-average amortization period was calculated at the date of acquisition for acquired assets or settlement agreement. | ||||||||||||||||||||||||||||
(f) Excludes $67 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. | ||||||||||||||||||||||||||||
The following table summarizes the amortization expense related to intangible assets for each of the years ended December 31, 2013, 2012 and 2011: | ||||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | |||||||||||||||||||||||||
2013 | $ | 27 | $ | 20 | $ | 7 | ||||||||||||||||||||||
2012 | 20 | 13 | 7 | |||||||||||||||||||||||||
2011 | 19 | 12 | 7 | |||||||||||||||||||||||||
Acquired Intangible Assets | ||||||||||||||||||||||||||||
Accounting guidance for business combinations requires that the acquirer must recognize separately identifiable intangible assets in the application of purchase accounting. The valuation of the acquired intangible assets discussed below were estimated by applying the income approach, which is based upon discounted projected future cash flows associated with the respective PPAs. Key assumptions used in the valuation of these intangible assets include forecasted power prices and discount rates. Those measures are based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. The intangible assets are amortized as a decrease in operating revenue within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income over the term of the underlying PPAs. | ||||||||||||||||||||||||||||
Exelon Wind. The output of the acquired wind turbines has been sold under PPA contracts. The excess of the contract price of the PPAs over market prices was recognized as intangible assets at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible assets was approximately $224 million, which is recorded in unamortized energy contract assets within Exelon's and Generation's Consolidated Balance Sheets. The intangible assets are amortized on a straight-line basis over the period in which the associated contract revenues are recognized. | ||||||||||||||||||||||||||||
Antelope Valley. Upon completion of the development project, all of the output will be sold under a PPA with Pacific Gas & Electric Company. The excess of the contract price of the PPA over forecasted MPR-based market prices was recognized as an intangible asset at the acquisition date. Generation determined that the estimated acquisition-date fair value of the intangible asset was approximately $190 million, which is recorded in unamortized energy contract assets within Exelon's and Generation's Consolidated Balance Sheets. The fair value is amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition date. | ||||||||||||||||||||||||||||
Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, ComEd and PECO). | ||||||||||||||||||||||||||||
Exelon's, Generation's, ComEd's and PECO's other intangible assets, included in other current assets and other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As of December 31, 2013, and 2012, PECO had current AECs of $19 million and $17 million, respectively, and noncurrent AECs of $5 million and $9 million, respectively. As of December 31, 2013, and 2012, Generation had current RECs of $158 million and $61 million, respectively, and noncurrent RECs of $0 million and $45 million, respectively. As of December 31, 2013, and 2012, ComEd, had current RECs of $3 million and $4 million, respectively. See Note 3 - Regulatory Matters and Note 22 - Commitments and Contingencies for additional information on RECs and AECs. |
Fair_Value_of_Financial_Assets
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities [Line items] | ' | ' | ||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Text Block] | ' | ' | ||||||||||||||||||||||||||||||||||
11. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | For the Year Ended December 31, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Decommissioning | Mark-to-Market Derivatives (b) | Other Investments | Total | ||||||||||||||||||||||||||||||
Balance as of January 1, 2012 | $ | 13 | $ | 37 | $ | 17 | $ | 0 | $ | 67 | ||||||||||||||||||||||||||
Fair Value of Financial Liabilities Recorded at the Carrying Amount | Total realized / unrealized gains (losses) | |||||||||||||||||||||||||||||||||||
Included in income | 0 | 0 | 59 | (a) | 0 | 59 | ||||||||||||||||||||||||||||||
The following tables present the carrying amounts and fair values of the Registrants' short-term liabilities, long-term debt, SNF obligation, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures), and preferred securities as of December 31, 2013, and 2012: | Included in regulatory liabilities | 1 | 0 | 39 | 0 | 40 | ||||||||||||||||||||||||||||||
Change in collateral | 0 | 0 | -32 | 0 | -32 | |||||||||||||||||||||||||||||||
Exelon | Purchases, sales, issuances and settlements | |||||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | Purchases | 169 | 63 | 334 | (c) | 17 | 583 | ||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | Sales | 0 | -11 | 0 | 0 | -11 | |||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | Transfers into Level 3 | 0 | 0 | 39 | 0 | 39 | |||||||||||||||||||||||||
Short-term liabilities | $ | 344 | $ | 3 | $ | 341 | $ | 0 | $ | 214 | $ | 214 | Transfers out of Level 3 | 0 | 0 | -89 | 0 | -89 | ||||||||||||||||||
Long-term debt (including amounts | Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 367 | $ | 17 | $ | 656 | |||||||||||||||||||||||||
due within one year) | 19,132 | 0 | 18,672 | 1,079 | 18,745 | 20,520 | The amount of total gains included in income | |||||||||||||||||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 648 | 664 | attributed to the change in unrealized gains related to assets and liabilities as of December 31, 2012 | $ | 0 | $ | 0 | $ | 214 | $ | 0 | $ | 214 | |||||||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 1,020 | 763 | For the Year Ended December 31, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | ||||||||||||||||||||||||
Preferred securities of subsidiary | 0 | 0 | 0 | 0 | 87 | 82 | Balance as of January 1, 2012 | $ | 13 | $ | 37 | $ | 817 | $ | 0 | $ | 867 | |||||||||||||||||||
Generation | Total realized / unrealized gains (losses) | |||||||||||||||||||||||||||||||||||
Included in income | 0 | 0 | 66 | (a) | 0 | 66 | ||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | Included in other comprehensive income | 0 | 0 | -475 | (b) | 0 | -475 | ||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | Included in noncurrent payables to affiliates | 1 | 0 | 0 | 0 | 1 | |||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | Changes in collateral | 0 | 0 | -32 | 0 | -32 | |||||||||||||||||||||||||
Short-term liabilities | $ | 22 | $ | 0 | $ | 22 | $ | 0 | $ | 0 | $ | 0 | Purchases, sales, issuances and settlements | |||||||||||||||||||||||
Long-term debt (including amounts | Purchases | 169 | 63 | 334 | (c) | 17 | 583 | |||||||||||||||||||||||||||||
due within one year) | 7,729 | 0 | 6,586 | 1,062 | 7,483 | 7,849 | Sales | 0 | -11 | 0 | 0 | -11 | ||||||||||||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 1,020 | 763 | Transfers into Level 3 | 0 | 0 | 39 | 0 | 39 | ||||||||||||||||||||||||
ComEd | Transfers out of Level 3 | 0 | 0 | -89 | 0 | -89 | ||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 660 | 17 | $ | 949 | |||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||||
Short-term liabilities | $ | 184 | $ | 0 | $ | 184 | $ | 0 | $ | 0 | $ | 0 | The amount of total gains included in income | |||||||||||||||||||||||
Long-term debt (including amounts | attributed to the change in unrealized gains related to assets and liabilities as of December 31, 2012 | $ | 0 | $ | 0 | $ | 165 | $ | 0 | $ | 165 | |||||||||||||||||||||||||
due within one year) | 5,675 | 0 | 6,238 | 17 | 5,567 | 6,548 | ||||||||||||||||||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 206 | 212 | (a) Includes a reduction for the reclassification of $99 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | |||||||||||||||||||||||||||||
PECO | (b) Includes $98 million of increases in fair value and $566 million of realized losses reclassified from OCI due to settlements associated with Generation's financial swap contract with ComEd for the year ended December 31, 2012. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | (c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | ||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||||
Short-term liabilities | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 210 | $ | 210 | ||||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||||
due within one year) | 2,197 | 0 | 2,358 | 0 | 1,947 | 2,264 | ||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 180 | 184 | 188 | ||||||||||||||||||||||||||||||
Preferred securities | 0 | 0 | 0 | 0 | 87 | 82 | ||||||||||||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||||
Short-term liabilities | $ | 138 | $ | 3 | $ | 135 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||||
due within one year) | 2,011 | 0 | 2,148 | 0 | 2,178 | 2,468 | ||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 249 | 258 | 263 | ||||||||||||||||||||||||||||||
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2), short-term notes payable related to PECO's accounts receivable agreement (Level 2), and dividends payable (Level 1). The Registrants' carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments. See Note 13 - Debt and Credit Agreements for additional information on PECO's accounts receivable agreement. | ||||||||||||||||||||||||||||||||||||
Long-Term Debt. The fair value amounts of Exelon's taxable debt securities (Level 2) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants' debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. | ||||||||||||||||||||||||||||||||||||
The fair value of Generation's non-government-backed fixed rate project financing debt (Level 3) is based on market and quoted prices for its own and other project financing debt with similar risk profiles. Given the low trading volume in the project financing debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation's government-back fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a quarterly basis and the carrying value approximates fair value. | ||||||||||||||||||||||||||||||||||||
The Registrants also have tax-exempt debt (Level 3). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (i.e., political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. | ||||||||||||||||||||||||||||||||||||
SNF Obligation. The carrying amount of Generation's SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation's nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation's discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025. | ||||||||||||||||||||||||||||||||||||
Long-Term Debt to Financing Trusts. Exelon's long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3. | ||||||||||||||||||||||||||||||||||||
Preferred Securities. The fair value of these securities is determined based on the last closing price prior to quarter end, less accrued interest. The securities are registered with the SEC and are public. PECO redeemed all outstanding series of preferred securities on May 1, 2013. See Note 20 - Earnings Per Share and Equity for additional information. | ||||||||||||||||||||||||||||||||||||
Recurring Fair Value Measurements | ||||||||||||||||||||||||||||||||||||
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: | ||||||||||||||||||||||||||||||||||||
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded equity securities and funds, certain exchange-based derivatives, and money market funds. | ||||||||||||||||||||||||||||||||||||
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, derivatives, commingled and mutual investment funds priced at NAV per fund share and fair value hedges. | ||||||||||||||||||||||||||||||||||||
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded securities and derivatives, and investments priced using an alternative pricing mechanism or third party valuation. | ||||||||||||||||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 1,230 | $ | 0 | $ | 0 | $ | 1,230 | ||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | ||||||||||||||||||||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 882 | 0 | 0 | 882 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 294 | 0 | 294 | ||||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | ||||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | ||||||||||||||||||||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | ||||||||||||||||||||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 45 | 4 | 0 | 49 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 20 | 0 | 20 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning subtotal(c) | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | ||||||||||||||||||||||||||||||||
Mutual funds(d)(e) | 54 | 0 | 0 | 54 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 56 | 0 | 0 | 56 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -863 | -3,131 | -430 | -4,424 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | -46 | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 30 | 39 | 0 | 69 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||||
Other Investments | 0 | 0 | 15 | 15 | ||||||||||||||||||||||||||||||||
Total assets | 4,533 | 5,575 | 1,054 | 11,162 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||||
Economic hedges | -540 | -1,890 | -590 | -3,020 | ||||||||||||||||||||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal(h) | 1 | -139 | -305 | -443 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | -31 | -17 | 0 | -48 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -16 | 0 | -16 | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -114 | 0 | -114 | ||||||||||||||||||||||||||||||||
Total liabilities | 1 | -269 | -305 | -573 | ||||||||||||||||||||||||||||||||
Total net assets | $ | 4,534 | $ | 5,306 | $ | 749 | $ | 10,589 | ||||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 995 | $ | 0 | $ | 0 | $ | 995 | ||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 1,057 | 0 | 0 | 1,057 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 321 | 0 | 321 | ||||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | ||||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | ||||||||||||||||||||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 118 | 12 | 0 | 130 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning subtotal(c) | 132 | 386 | 89 | 607 | ||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | ||||||||||||||||||||||||||||||||
Mutual funds(d)(e) | 69 | 0 | 0 | 69 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 71 | 0 | 0 | 71 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||||
Economic hedges | 861 | 3,173 | 641 | 4,675 | ||||||||||||||||||||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal(g) | 80 | 1,076 | 656 | 1,812 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 0 | 114 | 0 | 114 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 63 | 0 | 63 | ||||||||||||||||||||||||||||||||
Other Investments | 2 | 0 | 17 | 19 | ||||||||||||||||||||||||||||||||
Total assets | 4,062 | 5,778 | 945 | 10,785 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -236 | -3,566 | ||||||||||||||||||||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities(g)(h) | -83 | -228 | -289 | -600 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market liabilities | 0 | -84 | 0 | -84 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -33 | 0 | -33 | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -102 | 0 | -102 | ||||||||||||||||||||||||||||||||
Total liabilities | -83 | -363 | -289 | -735 | ||||||||||||||||||||||||||||||||
Total net assets | $ | 3,979 | $ | 5,415 | $ | 656 | $ | 10,050 | ||||||||||||||||||||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||||||||||||||||||||||||||||||||||
(b) Excludes net assets (liabilities) of $(5) million and $30 million at December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||||
(c) Excludes net assets of $7 million at both December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||||
(d) The mutual funds held by the Rabbi trusts include $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. | ||||||||||||||||||||||||||||||||||||
(e) Excludes $32 million and $28 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||||
(f) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||||
(g) The Level 3 balance does not include current assets for Generation and current liabilities for ComEd of $226 million at December 31, 2012 related to the fair value of Generation's financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||||
(h) The Level 3 balance includes the current and noncurrent liability of $17 million and $176 million at December 31, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2013 and 2012: | ||||||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Nuclear Decommissioning Trust Fund Investment | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 367 | $ | 17 | $ | 656 | ||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||||||
Included in net income | 2 | 0 | -44 | (a) | 0 | -42 | ||||||||||||||||||||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 2 | 2 | |||||||||||||||||||||||||||||||
Included in regulatory assets | 8 | 0 | -126 | (b) | 0 | -118 | ||||||||||||||||||||||||||||||
Change in collateral | 0 | 0 | 7 | 0 | 7 | |||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | |||||||||||||||||||||||||||||||
Sales | -28 | -39 | -11 | -8 | -86 | |||||||||||||||||||||||||||||||
Settlements | -18 | - | -18 | |||||||||||||||||||||||||||||||||
Transfers into Level 3 | 0 | 0 | 86 | (c) | 1 | 87 | ||||||||||||||||||||||||||||||
Transfers out of Level 3 | 0 | 0 | -35 | -1 | -36 | |||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 272 | $ | 15 | $ | 749 | ||||||||||||||||||||||||||
The amount of total gains included in income | ||||||||||||||||||||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | 0 | $ | 167 | $ | 0 | $ | 168 | ||||||||||||||||||||||||||
(a) Includes a reduction for the reclassification of $211 million of realized gains due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2013. | ||||||||||||||||||||||||||||||||||||
(b) Excludes decreases in fair value of $11 million of and realized losses reclassified due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
(c) Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | ||||||||||||||||||||||||||||||||||||
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2013 and 2012: | ||||||||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | ||||||||||||||||||||||||||||||||||
Total gains (losses) included in income for the year ended | ||||||||||||||||||||||||||||||||||||
31-Dec-13 | $ | -152 | $ | 108 | $ | 2 | ||||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and liabilities | ||||||||||||||||||||||||||||||||||||
held for the year ended December 31, 2013 | $ | 40 | $ | 127 | $ | 1 | ||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | ||||||||||||||||||||||||||||||||||
Total gains included in income for the year ended | ||||||||||||||||||||||||||||||||||||
31-Dec-12 | $ | 54 | $ | 5 | $ | 0 | ||||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities | ||||||||||||||||||||||||||||||||||||
held for the year ended December 31, 2012 | $ | 230 | $ | -16 | $ | 0 | ||||||||||||||||||||||||||||||
_____________ | ||||||||||||||||||||||||||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | ||||||||||||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on Generation's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 1,006 | $ | 0 | $ | 0 | $ | 1,006 | ||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | ||||||||||||||||||||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||||
government corporations and agencies | 882 | 0 | 0 | 882 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 294 | 0 | 294 | ||||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | ||||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | ||||||||||||||||||||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | ||||||||||||||||||||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||||
government corporations and agencies | 45 | 4 | 0 | 49 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 20 | 0 | 20 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(e) | -863 | -3,131 | -430 | -4,424 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | -46 | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||||
Interest Rate mark-to-market derivative assets | 30 | 32 | 0 | 62 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | ||||||||||||||||||||||||||||||||
Interest Rate mark-to-market derivative assets subtotal | 0 | 30 | 0 | 30 | ||||||||||||||||||||||||||||||||
Other investments | 0 | 0 | 15 | 15 | ||||||||||||||||||||||||||||||||
Total assets | 4,266 | 5,568 | 1,054 | 10,888 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||||
Economic hedges | -540 | -1,890 | -397 | -2,827 | ||||||||||||||||||||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(e) | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal | 1 | -139 | -112 | -250 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | -31 | -13 | 0 | -44 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -12 | 0 | -12 | ||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -29 | 0 | -29 | ||||||||||||||||||||||||||||||||
Total liabilities | 1 | -180 | -112 | -291 | ||||||||||||||||||||||||||||||||
Total net assets | $ | 4,267 | $ | 5,388 | $ | 942 | $ | 10,597 | ||||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 487 | $ | 0 | $ | 0 | $ | 487 | ||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||||
government corporations and agencies | 1,057 | 0 | 0 | 1,057 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 321 | 0 | 321 | ||||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | ||||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | ||||||||||||||||||||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | ||||||||||||||||||||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | ||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||||
government corporations and agencies | 118 | 12 | 0 | 130 | ||||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | ||||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | ||||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | ||||||||||||||||||||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | ||||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | ||||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | ||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Cash equivalents | 1 | 0 | 0 | 1 | ||||||||||||||||||||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||||
Economic hedges | 861 | 3,173 | 867 | 4,901 | ||||||||||||||||||||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | 80 | 1,076 | 882 | 2,038 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 0 | 101 | 0 | 101 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 50 | 0 | 50 | ||||||||||||||||||||||||||||||||
Other investments | 2 | 0 | 17 | 19 | ||||||||||||||||||||||||||||||||
Total assets | 3,497 | 5,765 | 1,171 | 10,433 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -169 | -3,499 | ||||||||||||||||||||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | ||||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal | -83 | -228 | -222 | -533 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | 0 | -84 | 0 | -84 | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | ||||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -33 | 0 | 0 | -33 | |||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -28 | 0 | -28 | ||||||||||||||||||||||||||||||||
Total liabilities | -83 | -289 | -222 | -594 | ||||||||||||||||||||||||||||||||
Total net assets | $ | 3,414 | $ | 5,476 | $ | 949 | $ | 9,839 | ||||||||||||||||||||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||||||||||||||||||||||||||||||||||
(b) Excludes net assets (liabilities) of $(5) million and $30 million at December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||||
(c) Excludes net assets of $7 million at both December 31, 2013 December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||||
(d) Excludes $10 million and $8 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||||
(e) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||||
(f) The Level 3 balance includes current assets for Generation of $226 million at December 31, 2012 related to the fair value of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2013, and 2012:. | ||||||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | ||||||||||||||||||||||||||
Total unrealized / realized gains (losses) | ||||||||||||||||||||||||||||||||||||
Included in income | 2 | 0 | -51 | (a)(b) | 0 | -49 | ||||||||||||||||||||||||||||||
Included in other comprehensive income | 0 | 0 | -219 | (b) | 2 | -217 | ||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 8 | 0 | 0 | 0 | 8 | |||||||||||||||||||||||||||||||
Change in collateral | 0 | 0 | 7 | 0 | 7 | |||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | |||||||||||||||||||||||||||||||
Sales | -28 | -39 | -11 | -8 | -86 | |||||||||||||||||||||||||||||||
Settlements | -18 | 0 | 0 | 0 | -18 | |||||||||||||||||||||||||||||||
Transfers into Level 3 | 0 | 0 | 86 | (c) | 1 | 87 | ||||||||||||||||||||||||||||||
Transfers out of Level 3 | 0 | 0 | -35 | -1 | -36 | |||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | ||||||||||||||||||||||||||
The amount of total losses included in income | ||||||||||||||||||||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | 0 | $ | 156 | $ | 0 | $ | 157 | ||||||||||||||||||||||||||
(a) Includes a reduction for the reclassification of $207 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2013. | ||||||||||||||||||||||||||||||||||||
(b) Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
(c) Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | ||||||||||||||||||||||||||||||||||||
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2013, and 2012: | ||||||||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other - net (a) | ||||||||||||||||||||||||||||||||||
Total gains (losses) included in income for the year ended | ||||||||||||||||||||||||||||||||||||
31-Dec-13 | $ | -158 | $ | 107 | $ | 2 | ||||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and | ||||||||||||||||||||||||||||||||||||
liabilities held for the year ended December 31, 2013 | $ | 30 | $ | 126 | $ | 1 | ||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other - net (a) | ||||||||||||||||||||||||||||||||||
Total gains included in income for the year ended | ||||||||||||||||||||||||||||||||||||
31-Dec-12 | $ | 61 | $ | 5 | $ | 0 | ||||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | ||||||||||||||||||||||||||||||||||||
liabilities held for the year ended December 31, 2012 | $ | 181 | $ | -16 | $ | 0 | ||||||||||||||||||||||||||||||
_____________ | ||||||||||||||||||||||||||||||||||||
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | ||||||||||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on ComEd's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||||
Total assets | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (b) | 0 | 0 | -193 | -193 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -8 | -193 | -201 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | -8 | $ | -193 | $ | -196 | ||||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 111 | $ | 0 | $ | 0 | $ | 111 | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds | 8 | 0 | 0 | 8 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 8 | 0 | 0 | 8 | ||||||||||||||||||||||||||||||||
Total assets | 119 | 0 | 0 | 119 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | ||||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (a)(b) | 0 | 0 | -293 | -293 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -8 | -293 | -301 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 119 | $ | -8 | $ | -293 | $ | -182 | ||||||||||||||||||||||||||||
(a) The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
(b) The Level 3 balance includes the current and noncurrent liability of $17 million and $176 million at December 31, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||||
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended and December 31, 2013, and 2012: | ||||||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Mark-to-Market Derivatives | |||||||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | -293 | ||||||||||||||||||||||||||||||||||
Total realized / unrealized gains included in regulatory assets (a)(b) | 100 | |||||||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | -193 | ||||||||||||||||||||||||||||||||||
(a) Includes $11 million of decrease in fair value and realized gains due to settlements of $215 million associated with ComEd's financial swap contract with Generation for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
(b) Includes $126 million of increases in the fair value and realized losses due to settlements of $7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2013 . | ||||||||||||||||||||||||||||||||||||
Includes $98 million of increases in fair value and $566 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the year ended December 31, 2012. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||||
Includes $34 million of decreases in the fair value and realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2012 . | ||||||||||||||||||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on PECO's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 175 | $ | 0 | $ | 0 | $ | 175 | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds (a) | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||||
Total assets | 184 | 0 | 0 | 184 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -17 | 0 | -17 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -17 | 0 | -17 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 184 | $ | -17 | $ | 0 | $ | 167 | ||||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 346 | $ | 0 | $ | 0 | $ | 346 | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds (a) | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||||
Total assets | 355 | 0 | 0 | 355 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -18 | 0 | -18 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -18 | 0 | -18 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 355 | $ | -18 | $ | 0 | $ | 337 | ||||||||||||||||||||||||||||
(a) Excludes $14 million and $13 million of the cash surrender value of life insurance investments at December 31, 2013 and 2012, respectively. | ||||||||||||||||||||||||||||||||||||
PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2013 and 2012. | ||||||||||||||||||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2013 and December 31, 2012: | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 31 | $ | 0 | $ | 0 | $ | 31 | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds | 6 | 0 | 0 | 6 | ||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 6 | 0 | 0 | 6 | ||||||||||||||||||||||||||||||||
Total assets | 37 | 0 | 0 | 37 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -6 | 0 | -6 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -6 | 0 | -6 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 37 | $ | -6 | $ | 0 | $ | 31 | ||||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 33 | $ | 0 | $ | 0 | $ | 33 | ||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||||
Rabbit trust investments subtotal | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||||
Total assets | 38 | 0 | 0 | 38 | ||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | ||||||||||||||||||||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | ||||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 38 | $ | -5 | $ | 0 | $ | 33 | ||||||||||||||||||||||||||||
BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the year ended December 31, 2013. | ||||||||||||||||||||||||||||||||||||
Valuation Techniques Used to Determine Fair Value | ||||||||||||||||||||||||||||||||||||
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. | ||||||||||||||||||||||||||||||||||||
Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE). The Registrants' cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy. | ||||||||||||||||||||||||||||||||||||
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds' exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2. | ||||||||||||||||||||||||||||||||||||
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges. | ||||||||||||||||||||||||||||||||||||
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities are determined using a third party valuation that contains certain significant unobservable inputs and are categorized in Level 3. | ||||||||||||||||||||||||||||||||||||
Equity and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon and Generation invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Commingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. | ||||||||||||||||||||||||||||||||||||
Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. | ||||||||||||||||||||||||||||||||||||
Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon's executive management and directors. The investments in the Rabbi trusts are included in investments in the Registrants' Consolidated Balance Sheets and consist primarily of mutual funds. These funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. | ||||||||||||||||||||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives' pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants' derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. | ||||||||||||||||||||||||||||||||||||
Transfers in and out of levels are recognized as of the end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. | ||||||||||||||||||||||||||||||||||||
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 12 — Derivative Financial Instruments for further discussion on mark-to-market derivatives. | ||||||||||||||||||||||||||||||||||||
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). The Registrants' deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants' deferred compensation obligations is based on the market value of the participants' notional investment accounts. The notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy. | ||||||||||||||||||||||||||||||||||||
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd) | ||||||||||||||||||||||||||||||||||||
Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon's business units. The RMC reports to the Exelon board of directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio are reviewed and verified by the middle office and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements. | ||||||||||||||||||||||||||||||||||||
Disclosed below is detail surrounding the Registrants' significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and notional size. Generation's Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, certain transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. | ||||||||||||||||||||||||||||||||||||
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation's own credit quality for liabilities. The level of observability of a forward commodity price is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are highly liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.92 and $0.12 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See Item 7A. – Quantitative and Qualitative Disclosures About Market Risk for information regarding the maturity by year of the Registrant's mark-to-market derivative assets and liabilities. | ||||||||||||||||||||||||||||||||||||
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 12 – Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. | ||||||||||||||||||||||||||||||||||||
The table below discloses the significant inputs to the forward curve used to value these positions. | ||||||||||||||||||||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 (c) | Valuation Technique | Unobservable Input | Range | ||||||||||||||||||||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 488 | Discounted Cash Flow | Forward power price | $ | 8 | - | $ | 176 | (d) | ||||||||||||||||||||||||||
Forward gas price | $ | 2.98 | - | $ | 16.63 | (d) | ||||||||||||||||||||||||||||||
Option Model | Volatility percentage | 15 | % | - | 142 | % | ||||||||||||||||||||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 3 | Discounted Cash Flow | Forward power price | $ | 10 | - | $ | 176 | (d) | ||||||||||||||||||||||||||
Option Model | Volatility percentage | 14 | % | - | 19 | % | ||||||||||||||||||||||||||||||
Mark-to-market derivatives (ComEd) | $ | -193 | Discounted Cash Flow | Forward heat rate (b) | 8 | - | 9 | |||||||||||||||||||||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | |||||||||||||||||||||||||||||||
Renewable factor | 84 | % | - | 128 | % | |||||||||||||||||||||||||||||||
____________________ | ||||||||||||||||||||||||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | ||||||||||||||||||||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | ||||||||||||||||||||||||||||||||||||
The fair values do not include cash collateral held on Level 3 positions of $26 million as of December 31, 2013. | ||||||||||||||||||||||||||||||||||||
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively. | ||||||||||||||||||||||||||||||||||||
_____________________ | ||||||||||||||||||||||||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | ||||||||||||||||||||||||||||||||||||
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd that ended in May 2013, which eliminates in consolidation. | ||||||||||||||||||||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | ||||||||||||||||||||||||||||||||||||
The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012. | ||||||||||||||||||||||||||||||||||||
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation's commodity derivatives are forward commodity prices and for options is volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. | ||||||||||||||||||||||||||||||||||||
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending, certain corporate debt securities, and private equity investments the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance. | ||||||||||||||||||||||||||||||||||||
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its' Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers' inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its' Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers. | ||||||||||||||||||||||||||||||||||||
As of December 31, 2013, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, and private equity investments of approximately $448 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds. | ||||||||||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ' | ||||||||||||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities [Line items] | ' | ' | ||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Text Block] | ' | ' | ||||||||||||||||||||||||||||||||||
(a) Includes a reduction for the reclassification of $155 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | ||||||||||||||||||||||||||||||||||||
(b) Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. | ||||||||||||||||||||||||||||||||||||
(c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | ||||||||||||||||||||||||||||||||||||
Derivative_Financial_Instrumen
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Derivative Financial Instruments [Line Items] | ' | ||||||||||||||||||||||||||||
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||||||||
12. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
The Registrants are exposed to certain risks related to ongoing business operations. The primary risks managed by using derivative instruments are commodity price risk and interest rate risk. | |||||||||||||||||||||||||||||
Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices. | |||||||||||||||||||||||||||||
Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 22 – Commitments and Contingencies. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall energy marketing activities. | |||||||||||||||||||||||||||||
Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management's policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. | |||||||||||||||||||||||||||||
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2013, the percentage of expected generation hedged for the major reportable segments was 92%-95%, 62%-65% and 30%-33% for 2014, 2015, and 2016, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including Generation's sales to ComEd, PECO and BGE to serve their retail load. | |||||||||||||||||||||||||||||
In order to fulfill a requirement of the Illinois Settlement Legislation, Generation and ComEd entered into a five-year financial swap contract that expired May 31, 2013. The financial swap was designed to hedge spot market purchases, which, along with ComEd's remaining energy procurement contracts, met its load service requirements. The terms of the financial swap contract required Generation to pay the around-the-clock market price for a portion of ComEd's electricity supply requirement, while ComEd paid a fixed price. | |||||||||||||||||||||||||||||
As the contract expired May 31, 2013, all realized impacts have been included in Generation's and ComEd's results of operations. In Exelon's consolidated financial statements, all financial statement effects of the financial swap recorded by Generation and ComEd are eliminated. | |||||||||||||||||||||||||||||
In addition, the physical contracts that Generation has entered into with ComEd and that ComEd has entered into with Generation and other suppliers as part of the ComEd power procurement process, which are further discussed in Note 3 – Regulatory Matters, qualify and are accounted for under the NPNS exception. Based on the Illinois Settlement Legislation and ICC-approved procurement methodologies permitting ComEd to recover its electricity procurement costs from retail customers with no mark-up, ComEd's price risk related to power procurement is limited. | |||||||||||||||||||||||||||||
On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associated RECs were reduced in the first quarter of 2013. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 – Regulatory Matters for additional information. | |||||||||||||||||||||||||||||
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 3 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO's price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts, that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance. | |||||||||||||||||||||||||||||
PECO's natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO's reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO's natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2013 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2013 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO's gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO's financial position or results of operations as natural gas costs are fully recovered from customers under the PGC. | |||||||||||||||||||||||||||||
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE's price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives. | |||||||||||||||||||||||||||||
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE's actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE's actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE's natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery. | |||||||||||||||||||||||||||||
Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon's RMC. The proprietary trading activities, which included settled physical sales volumes of 8,762 GWh, 12,958 GWh and 5,742 Gwh for the years ended December 31, 2013, 2012 and 2011, are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes. | |||||||||||||||||||||||||||||
Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2013, Exelon had $1,425 million of notional amounts of fixed-to-floating hedges outstanding and $190 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximate $5 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2013. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedges as of December 31, 2013. | |||||||||||||||||||||||||||||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||||||||||||||
The following table provides a summary of the interest rate hedge balances recorded by the Registrants as of December 31, 2012: | |||||||||||||||||||||||||||||
Generation | Other | Exelon | |||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | ||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | 0 | $ | 3 | $ | 20 | $ | -19 | $ | 4 | $ | 0 | $ | 4 | |||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 38 | 8 | 32 | -32 | 46 | 13 | 59 | ||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 38 | $ | 11 | $ | 52 | $ | -51 | $ | 50 | $ | 13 | $ | 63 | |||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | 0 | $ | -2 | |||||||||||||||
Mark-to-market derivative liabilities (Noncurrent Liabilities) | -31 | 0 | -32 | 32 | -31 | 0 | -31 | ||||||||||||||||||||||
Total mark-to-market derivative liabilities | -32 | -1 | -51 | 51 | -33 | 0 | -33 | ||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 6 | $ | 10 | $ | 1 | $ | 0 | $ | 17 | $ | 13 | $ | 30 | |||||||||||||||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||||||||||||||
Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows: | |||||||||||||||||||||||||||||
Twelve Months Ended December 31, | |||||||||||||||||||||||||||||
Income Statement | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Location | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||
Generation | Interest expense(a) | $ | -15 | $ | -6 | $ | 0 | $ | 0 | $ | -6 | $ | 0 | ||||||||||||||||
Exelon | Interest expense | $ | -24 | $ | -9 | $ | 1 | $ | 11 | $ | -3 | $ | -1 | ||||||||||||||||
______ ____ | |||||||||||||||||||||||||||||
For the years ended December 31, 2013 and 2012, the loss on Generation swaps included $16 million and $12 realized in earnings, respectively, with $2 million and an immaterial amount excluded from hedge effectiveness testing, respectively. | |||||||||||||||||||||||||||||
During the third and fourth quarters of 2013, Exelon entered into $625 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2020. At December 31, 2013, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with unrealized gains of $26 million and $23 million, respectively. At December 31, 2012, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $650 million and $550 million that expire in 2015, with unrealized gains of $49 million and $38 million, respectively. During the years ended December 31, 2013 and 2012, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $2 million gain and immaterial, respectively. | |||||||||||||||||||||||||||||
Cash Flow Hedges. In anticipation of the Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013, Exelon entered into forward-starting interest rate swaps that were designated as cash flow hedges to hedge the change in benchmark interest rates. Upon settlement of the swaps, a $26 million effective gain in OCI was deferred and will be amortized into interest expense over the life of the debt. See Note 13 – Debt and Credit Agreements for additional information on the project financing. | |||||||||||||||||||||||||||||
In connection with the DOE guaranteed loan for the Antelope Valley acquisition, as discussed in Note 13 – Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of April 5, 2014. The swap hedges approximately 75% of Generation's future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge is recorded in other comprehensive income within Generation's Consolidated Balance Sheets, with any ineffectiveness recorded in Generation's Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, are amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan. | |||||||||||||||||||||||||||||
Every time Generation draws down on the loan, an offsetting hedge (fixed-to-floating) is executed and a portion of the cash flow hedge with a notional amount equal to the offsetting hedge, is de-designated and the related gains or losses going forward are reflected in earnings, which are largely offset by the losses or gains in the offsetting hedge. | |||||||||||||||||||||||||||||
Antelope Valley received its first loan advance on April 5, 2012, and a series of additional advances subsequently. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $350 million, approximately 75% of the loan advance amount to offset portions of the original interest rate hedge, which are not designated as cash flow hedges. The remaining cash flow hedge has a notional amount of $135 million. At December 31, 2013, Generation's mark-to-market non-current derivative liability relating to the interest rate swaps in connection with the loan agreement to fund Antelope Valley was $10 million. | |||||||||||||||||||||||||||||
During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $28 million as of December 31, 2013 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At December 31, 2013, the subsidiary had a $1 million derivative liability related to these swaps. | |||||||||||||||||||||||||||||
During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure of anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $27 million as of December 31, 2013, and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2013, the subsidiary had a $2 million derivative asset related to the swap. | |||||||||||||||||||||||||||||
During the years ended December 31, 2013, and 2012, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. | |||||||||||||||||||||||||||||
Economic Hedges. At December 31, 2013, Generation had $144 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $195 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars. | |||||||||||||||||||||||||||||
At December 31, 2013, Exelon and Generation had $150 million in notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with unrealized gains of $2 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the year ended December 31, 2013, and the period from March 12 to December 31, 2012, the impact on the results of operations was immaterial. | |||||||||||||||||||||||||||||
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place either as the contracts deliver, when collateral is requested or in the event of default. Generation's use of cash collateral is generally unrestricted unless Generation is downgraded below investment grade (i.e. to BB+ or Ba1). In the table below, Generation's energy-related economic hedges and proprietary trading derivatives are shown gross and the impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column. As of December 31, 2013 and 2012, $10 million of cash collateral posted and $3 million of cash collateral received, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting. | |||||||||||||||||||||||||||||
ComEd's use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1). | |||||||||||||||||||||||||||||
Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications. | |||||||||||||||||||||||||||||
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2013: | |||||||||||||||||||||||||||||
Generation | ComEd | Exelon | |||||||||||||||||||||||||||
Collateral | |||||||||||||||||||||||||||||
Economic | Proprietary | and | Subtotal | Economic | Total | ||||||||||||||||||||||||
Derivatives | Hedges | Trading | Netting(a) | (b) | Hedges(c) | Derivatives | |||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(current assets) | $ | 2,616 | $ | 1,476 | $ | -3,364 | $ | 728 | $ | 0 | $ | 728 | |||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(noncurrent assets) | 1,344 | 285 | -1,060 | 569 | 0 | 569 | |||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
assets | $ | 3,960 | $ | 1,761 | $ | -4,424 | $ | 1,297 | $ | 0 | $ | 1,297 | |||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(current liabilities) | $ | -2,023 | $ | -1,410 | $ | 3,292 | $ | -141 | $ | -17 | $ | -158 | |||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(noncurrent liabilities) | -804 | -293 | 988 | -109 | -176 | -285 | |||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
liabilities | $ | -2,827 | $ | -1,703 | $ | 4,280 | $ | -250 | $ | -193 | $ | -443 | |||||||||||||||||
Total mark-to-market derivative net | |||||||||||||||||||||||||||||
assets (liabilities) | $ | 1,133 | $ | 58 | $ | -144 | $ | 1,047 | $ | -193 | $ | 854 | |||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above. | |||||||||||||||||||||||||||||
(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | |||||||||||||||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2012: | |||||||||||||||||||||||||||||
Generation | ComEd | Exelon | |||||||||||||||||||||||||||
Economic | Collateral | Economic | Intercompany | ||||||||||||||||||||||||||
Hedges | Proprietary | and | Subtotal | Hedges | Eliminations | Total | |||||||||||||||||||||||
Derivatives | (a) | Trading | Netting(b) | (c) | (a)(d) | (a) | Derivatives | ||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(current assets) | $ | 2,883 | $ | 2,469 | $ | -4,418 | $ | 934 | $ | 0 | $ | 0 | $ | 934 | |||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
with affiliate (current assets) | 226 | 0 | 0 | 226 | 0 | -226 | 0 | ||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(noncurrent assets) | 1,792 | 724 | -1,638 | 878 | 0 | 0 | 878 | ||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
assets | $ | 4,901 | $ | 3,193 | $ | -6,056 | $ | 2,038 | $ | 0 | $ | -226 | $ | 1,812 | |||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(current liabilities) | $ | -2,419 | $ | -2,432 | $ | 4,519 | $ | -332 | $ | -18 | $ | 0 | $ | -350 | |||||||||||||||
Mark-to-market derivative liability | |||||||||||||||||||||||||||||
with affiliate (current liabilities) | 0 | 0 | 0 | 0 | -226 | 226 | 0 | ||||||||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(noncurrent liabilities) | -1,080 | -689 | 1,568 | -201 | -49 | 0 | -250 | ||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
liabilities | $ | -3,499 | $ | -3,121 | $ | 6,087 | $ | -533 | $ | -293 | $ | 226 | $ | -600 | |||||||||||||||
Total mark-to-market derivative net | |||||||||||||||||||||||||||||
assets (liabilities) | $ | 1,402 | $ | 72 | $ | 31 | $ | 1,505 | $ | -293 | $ | 0 | $ | 1,212 | |||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above. | |||||||||||||||||||||||||||||
(b) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | |||||||||||||||||||||||||||||
(c) Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $ (31) million at December 31, 2012. | |||||||||||||||||||||||||||||
(d) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||
Cash Flow Hedges (Exelon, Generation and ComEd). As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and is reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. Approximately $195 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation. Generation expects the settlement of the majority of its cash flow hedges will occur during 2013 through 2014. | |||||||||||||||||||||||||||||
Exelon discontinues hedge accounting when it determines that the derivative is no longer effective in offsetting changes in the cash flows of a hedged item or when it is no longer probable that the forecasted transaction will occur. For the year ended 2012, the amount reclassified into earnings as a result of the discontinuance of cash flow hedges was immaterial. | |||||||||||||||||||||||||||||
The tables below provide the activity of accumulated OCI related to cash flow hedges for the years ended December 31, 2013 and 2012, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price. | |||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
1-Jan-12 | $ | 925 | (a)(d) | $ | 488 | ||||||||||||||||||||||||
Effective portion of changes in fair value | 432 | (b) | 330 | (e) | |||||||||||||||||||||||||
Reclassifications from accumulated OCI to | |||||||||||||||||||||||||||||
net income | Operating Revenues | -828 | (c) | -453 | |||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | 3 | 3 | ||||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
31-Dec-12 | 532 | (a)(d) | 368 | ||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 29 | (e) | ||||||||||||||||||||||||||
Reclassifications from accumulated OCI to | |||||||||||||||||||||||||||||
net income | Operating Revenues | -413 | (c) | -277 | |||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
31-Dec-13 | $ | 119 | (d) | $ | 120 | ||||||||||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Includes $133 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011 . | |||||||||||||||||||||||||||||
(b) Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the year ended December 31, 2012. As of the merger date, cash flow hedges were discontinued, as such, this amount represents changes in fair value prior to the merger date. | |||||||||||||||||||||||||||||
(c) Includes $133 million and $375 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||||||
(d) Excludes $5 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||||||
(e) Includes $15 million and $9 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2013 and 2012, respectively | |||||||||||||||||||||||||||||
During the years ended December 31, 2013, 2012, and 2011 Generation's former energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $683 million, $1,368 million and $968 million pre-tax gain, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include power and gas options or sales, the ineffectiveness of Generation's cash flow hedges was primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. Changes in cash flow hedge ineffectiveness were losses of $5 million and a gain of $10 million for the years ended 2012 and 2011, respectively. | |||||||||||||||||||||||||||||
Exelon's former energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $464 million, $747 million and $512 million pre-tax gain for the years ended December 31, 2013, 2012 and 2011, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million and gains of $10 million for the years ended 2012 and 2011, respectively. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the merger date. | |||||||||||||||||||||||||||||
Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the years ended December 31, 2013, 2012 and 2011, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon's and Generation's Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period. | |||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | |||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | Operating | |||||||||||||||||||||||||||
Year Ended December 31, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | ||||||||||||||||||||||||
Change in fair value | $ | 285 | $ | 180 | $ | 465 | $ | -6 | $ | 459 | |||||||||||||||||||
Reclassification to realized at settlement | -65 | 104 | 39 | 13 | 52 | ||||||||||||||||||||||||
Net mark-to-market gains | $ | 220 | $ | 284 | $ | 504 | $ | 7 | $ | 511 | |||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | |||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | Operating | |||||||||||||||||||||||||||
Year Ended December 31, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | ||||||||||||||||||||||||
Change in fair value | $ | -362 | $ | 215 | $ | -147 | $ | -94 | $ | -241 | |||||||||||||||||||
Reclassification to realized at settlement | 429 | 238 | 667 | 101 | 768 | ||||||||||||||||||||||||
Net mark-to-market gains | $ | 67 | $ | 453 | $ | 520 | $ | 7 | $ | 527 | |||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | ||||||||||||||||||||||||||||
Year Ended December 31, 2011 (As Reported) | Revenues | and Fuel | Total | ||||||||||||||||||||||||||
Change in fair value | $ | 87 | $ | 131 | $ | 218 | |||||||||||||||||||||||
Reclassification to realized at settlement | -296 | -219 | -515 | ||||||||||||||||||||||||||
Net mark-to-market (losses)(b) | $ | -209 | $ | -88 | $ | -297 | |||||||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | ||||||||||||||||||||||||||||
Year Ended December 31, 2011 (Pro Forma) | Revenues | and Fuel | Total | ||||||||||||||||||||||||||
Change in fair value | $ | 258 | $ | -40 | $ | 218 | |||||||||||||||||||||||
Reclassification to realized at settlement | -516 | 1 | -515 | ||||||||||||||||||||||||||
Net mark-to-market (losses)(b) | $ | -258 | $ | -39 | $ | -297 | |||||||||||||||||||||||
Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. | |||||||||||||||||||||||||||||
Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues. | |||||||||||||||||||||||||||||
For the Years Ended | |||||||||||||||||||||||||||||
Location on Income | December 31, | ||||||||||||||||||||||||||||
Statement | 2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Change in fair value | Operating Revenue | $ | -21 | $ | -12 | $ | 23 | ||||||||||||||||||||||
Reclassification to realized at settlement | Operating Revenue | -18 | 108 | -26 | |||||||||||||||||||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | -39 | $ | 96 | $ | -3 | ||||||||||||||||||||||
Credit Risk (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation's credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty's margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation's credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. | |||||||||||||||||||||||||||||
The following tables provide information on Generation's credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2013. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below do not include credit risk exposure from uranium procurement contracts or exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in Item 7A - Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below do not include exposures with affiliates, including net receivables with ComEd, PECO and BGE of $38 million, $38 million and $27 million, respectively. | |||||||||||||||||||||||||||||
Total | Number of | Net Exposure of | |||||||||||||||||||||||||||
Exposure | Counterparties | Counterparties | |||||||||||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | |||||||||||||||||||||||||
Rating as of December 31, 2013 | Collateral | Collateral (a) | Exposure | of Net Exposure | of Net Exposure | ||||||||||||||||||||||||
Investment grade | $ | 1,621 | $ | 172 | $ | 1,449 | $ | 1 | $ | 491 | |||||||||||||||||||
Non-investment grade | 27 | 9 | 18 | 0 | 0 | ||||||||||||||||||||||||
No external ratings | |||||||||||||||||||||||||||||
Internally rated - investment grade | 416 | 1 | 415 | 1 | 226 | ||||||||||||||||||||||||
Internally rated - non-investment grade | 30 | 2 | 28 | 0 | 0 | ||||||||||||||||||||||||
Total | $ | 2,094 | $ | 184 | $ | 1,910 | $ | 2 | $ | 717 | |||||||||||||||||||
Net Credit Exposure by Type of Counterparty | 31-Dec-13 | ||||||||||||||||||||||||||||
Financial Institutions | $ | 256 | |||||||||||||||||||||||||||
Investor-owned utilities, marketers, power producers | 684 | ||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 907 | ||||||||||||||||||||||||||||
Other | 63 | ||||||||||||||||||||||||||||
Total | $ | 1,910 | |||||||||||||||||||||||||||
(a) As of December 31, 2013, credit collateral held from counterparties where Generation had credit exposure included $155 million of cash and $29 million of letters of credit . | |||||||||||||||||||||||||||||
ComEd's power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd's net credit exposure. As of December 31, 2013, ComEd's credit exposure to suppliers was immaterial. | |||||||||||||||||||||||||||||
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||||
PECO's supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier's performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier's lowest credit rating from the major credit rating agencies and the supplier's tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier's unsecured credit limit. The unsecured credit used by the suppliers represents PECO's net credit exposure. As of December 31, 2013, PECO had no net credit exposure with suppliers. | |||||||||||||||||||||||||||||
PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||||
PECO's natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO's counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of December 31, 2013, PECO had credit exposure of $9 million under its natural gas supply and asset management agreements with investment grade suppliers. | |||||||||||||||||||||||||||||
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||||
BGE's full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier's performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier's lowest credit rating from the major credit rating agencies and the supplier's tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier's unsecured credit limit. The unsecured credit used by the suppliers represents BGE's net credit exposure. The seller's credit exposure is calculated each business day. As of December 31, 2013, BGE had no net credit exposure to suppliers. | |||||||||||||||||||||||||||||
BGE's regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE's recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers' demands, which are not covered by the gas cost adjustment clause. At December 31, 2013, BGE had credit exposure of $14 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers. | |||||||||||||||||||||||||||||
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation's derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation 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. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. | |||||||||||||||||||||||||||||
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below: | |||||||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 2013 | 2012 | |||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | $ | ($1,056) | $ | ($1,849) | |||||||||||||||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | $846 | $1,426 | |||||||||||||||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature (c) | $ | ($210) | $ | ($423) | |||||||||||||||||||||||||
____________________ | |||||||||||||||||||||||||||||
Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent ignoring the effects of master netting agreements. | |||||||||||||||||||||||||||||
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | |||||||||||||||||||||||||||||
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. | |||||||||||||||||||||||||||||
Generation had cash collateral posted of $72 million, letters of credit posted of $364 million, cash collateral held of $206 million and letters of credit held of $34 million as of December 31, 2013 for counterparties with derivative positions. Generation had cash collateral posted of $527 million and letters of credit posted of $563 million and cash collateral held of $499 million and letters of credit held of $45 million at December 31, 2012 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. BB+ or Ba1), Generation could be required to post additional collateral of $2.0 billion as of December 31, 2013 and December 31, 2012. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. | |||||||||||||||||||||||||||||
Generation's and Exelon's interest rate swaps contain provisions that, in the event of a merger, if Generation's debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2013, Generation's and Exelon's swaps were in an asset position, with a fair value of $18 million and $21 million, respectively. | |||||||||||||||||||||||||||||
See Note 24 – Segment Information for additional information regarding the letters of credit supporting the cash collateral. | |||||||||||||||||||||||||||||
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd's standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2013, ComEd held neither cash nor letters of credit for the purpose of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd's long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2013, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 1 – Significant Accounting Policies for additional information. | |||||||||||||||||||||||||||||
PECO's natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2013, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2013, PECO could have been required to post approximately $42 million of collateral to its counterparties. | |||||||||||||||||||||||||||||
PECO's supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral. | |||||||||||||||||||||||||||||
BGE's full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral. | |||||||||||||||||||||||||||||
BGE's natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2013, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2013, BGE could have been required to post approximately $85 million of collateral to its counterparties. |
Debt_and_Credit_Agreements_Exe
Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Debt and Credit Agreements [Line Items] | ' | ||||||||||||||||||
Debt Disclosure [Text Block] | ' | ||||||||||||||||||
13. Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||
Short-Term Borrowings | |||||||||||||||||||
Exelon, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. | |||||||||||||||||||
Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2013 and 2012: | |||||||||||||||||||
Maximum Program Size at December 31, | Outstanding Commercial Paper at December 31, | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | |||||||||||||||||
Commercial Paper Issuer | 2013 (a) | 2012 (a) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Exelon Corporate | $ | 500 | $ | 500 | $ | 0 | $ | 0 | 0.27 | % | 0.47 | % | |||||||
Generation | 5,600 | 5,600 | 0 | 0 | 0.32 | % | 0.45 | % | |||||||||||
ComEd | 1,000 | 1,000 | 184 | 0 | 0.4 | % | 0.5 | % | |||||||||||
PECO | 600 | 600 | 0 | 0 | n.a. | n.a. | |||||||||||||
BGE | 600 | 600 | 135 | 0 | 0.31 | % | 0.43 | % | |||||||||||
Total | $ | 8,300 | $ | 8,300 | $ | 319 | $ | 0 | |||||||||||
(a) Equals aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of a $75 million bilateral agreement) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||||
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its outstanding commercial paper does not reduce available capacity under a Registrant's credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit agreement. | |||||||||||||||||||
At December 31, 2013, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements: | |||||||||||||||||||
Available Capacity at December 31, 2013 | |||||||||||||||||||
Borrower | Aggregate Bank Commitment (a) | Facility Draws | Outstanding Letters of Credit | Actual | To Support Additional Commercial Paper (b) | ||||||||||||||
Exelon Corporate | $ | 500 | $ | — | $ | 2 | $ | 498 | $ | 498 | |||||||||
Generation | 5,675 | — | 1,413 | 4,262 | 4,187 | ||||||||||||||
ComEd | 1,000 | — | — | 1,000 | 816 | ||||||||||||||
PECO | 600 | — | 1 | 599 | 599 | ||||||||||||||
BGE | 600 | — | — | 600 | 465 | ||||||||||||||
Total | $ | 8,375 | $ | — | $ | 1,416 | $ | 6,959 | $ | 6,565 | |||||||||
Exelon | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 254 | $ | 199 | $ | 218 | |||||||||||||
Maximum borrowings outstanding | 682 | 505 | 600 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.37 | % | 0.48 | % | 0.5 | % | |||||||||||||
Average interest rates, at December 31 | 0.35 | % | n.a. | 0.44 | % | ||||||||||||||
Generation | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 42 | $ | 4 | $ | 51 | |||||||||||||
Maximum borrowings outstanding | 291 | 165 | 304 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.45 | % | 0.48 | ||||||||||||||
Average interest rates, at December 31 | n.a. | n.a. | n.a. | ||||||||||||||||
ComEd | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 203 | $ | 110 | $ | 36 | |||||||||||||
Maximum borrowings outstanding | 446 | 366 | 407 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.4 | % | 0.5 | % | 0.71 | % | |||||||||||||
Average interest rates, at December 31 | 0.37 | % | n.a. | n.a. | |||||||||||||||
BGE | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 35 | $ | 6 | $ | 26 | |||||||||||||
Maximum borrowings outstanding | 135 | 76 | 190 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.31 | % | 0.43 | % | 0.38 | % | |||||||||||||
Average interest rates, computed at December 31 | 0.31 | % | n.a. | n.a. | |||||||||||||||
Credit Agreements | |||||||||||||||||||
On January 23, 2013, Generation entered into a two year $75 million bilateral letter of credit facility with a bank. The credit agreement expires in January 2015. This facility will solely be utilized by Generation to issue letters of credit. | |||||||||||||||||||
On March 14, 2013, ComEd extended its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2018, and ComEd may request another one-year extension of that term. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any such extension or increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material. | |||||||||||||||||||
On August 10, 2013, Exelon Corporate, Generation, PECO and BGE amended and extended their respective unsecured syndicated revolving credit facilities, with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively. The new covenants are substantially consistent with existing covenants. Costs incurred to amend and extend the facilities for Exelon Corporate, Generation, PECO and BGE were not material. | |||||||||||||||||||
Effective August 10, 2013, Exelon and ComEd entered into amendments to each of their respective revolving credit facilities (the Amendments). The Amendments relate to the IRS's challenge to the position taken by Exelon on its 1999 federal income tax return with respect to the sale of ComEd's fossil generating assets in a like-kind exchange tax position. The Amendments are intended to exclude the non-cash impact of the like-kind exchange tax position from the calculation of the interest coverage ratio under each of Exelon and ComEd's respective credit facilities. See Note 12 — Income Taxes for additional information. | |||||||||||||||||||
On January 27, 2014 ComEd began the process of extending its unsecured syndicated revolving credit facility, with aggregate bank commitments of $1.0 billion. The transaction is expected to close and become effective in March 2014, with a maturity of five years from the close of the transaction. No changes are expected to be made to the facility other than extension of the term for an additional one year period. Generally, it is expected that costs incurred to extend the facility will be amortized over the newly extended life of the facility. | |||||||||||||||||||
Borrowings under Exelon Corporate's, Generation's, ComEd's, PECO's and BGE's credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular registrant's credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 27.5, 0.0 and 7.5 basis points for prime based borrowings and 127.5, 127.5, 127.5, 100.0 and 107.5 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower. | |||||||||||||||||||
An event of default under any of the Registrants' credit facilities would not constitute an event of default under any of the other Registrants' credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit facility would constitute an event of default under the Exelon Corporate credit facility. | |||||||||||||||||||
On October 18, 2013, Generation, ComEd, PECO and BGE refinanced their respective minority and community bank credit facility agreements in the amounts of $50 million, $34 million, $34 million and $5 million, respectively. These facilities, which expire in October 2014, are solely utilized to issue letters of credit. | |||||||||||||||||||
Each credit facility requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2013: | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Credit facility threshold | 2.50 to 1 | 3.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 | ||||||||||||||
At December 31, 2013, the interest coverage ratios at the Registrants were as follows: | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Interest coverage ratio | 7.67 | 11.45 | 5.2 | 8.29 | 7.85 | ||||||||||||||
Accounts Receivable Agreement | |||||||||||||||||||
PECO was party to an agreement with a financial institution under which it transferred an undivided interest, adjusted daily, in its accounts receivable designated under the agreement in exchange for proceeds of $210 million, which was classified as a short-term note payable on Exelon's and PECO's Consolidated Balance Sheets as of December 31, 2012. The agreement terminated on August 30, 2013 and PECO paid down the outstanding principal of $210 million. The financial institution no longer has an undivided interest in the accounts receivable designated under the agreement. As of December 31, 2012, the financial institution's undivided interest in Exelon's and PECO's gross accounts receivable was equivalent to $289 million, which represented the financial institution's interest in PECO's eligible receivables as calculated under the terms of the agreement. The agreement required PECO to maintain eligible receivables at least equivalent to the financial institution's undivided interest. | |||||||||||||||||||
Willis Tower Capital Lease | |||||||||||||||||||
In the second quarter of 2013, ComEd entered into a 20-year capital lease for distribution substation space at Willis Tower in Chicago, Illinois. Exelon and ComEd recorded $8 million on their Consolidated Balance Sheets within property plant and equipment and long-term debt at the inception of the lease. ComEd will make lease payments of less than $1 million annually in 2013-2017 and approximately $7 million in aggregate thereafter. | |||||||||||||||||||
Long-Term Debt | |||||||||||||||||||
The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2013 and 2012: | |||||||||||||||||||
Exelon | |||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b) : | |||||||||||||||||||
Fixed rates | 1.2 | % | - | 7.63 | % | 2013-2043 | $ | 7,746 | $ | 7,397 | |||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2013-2036 | 1,750 | 1,850 | |||||||||||
Rate stabilization bonds | 5.68 | % | - | 5.82 | % | 2016-2017 | 265 | 332 | |||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2014-2042 | 7,571 | 8,021 | |||||||||||
Pollution control notes: | |||||||||||||||||||
Fixed rates | 4.1 | % | 2014 | 20 | 20 | ||||||||||||||
Non-recourse debt: | |||||||||||||||||||
Fixed rates | 2.33 | % | - | 5.5 | % | 2031-2037 | 1,077 | 238 | |||||||||||
Variable rates | 1.96 | % | - | 2.77 | % | 2013-2053 | 150 | 262 | |||||||||||
Notes payable and other (c) | 4.5 | % | - | 7.83 | % | 2014-2053 | 181 | 177 | |||||||||||
Total long-term debt | 18,760 | 18,297 | |||||||||||||||||
Unamortized debt discount and premium, net | -19 | -17 | |||||||||||||||||
Fair value adjustment | 384 | 448 | |||||||||||||||||
Fair value hedge carrying value adjustment, net | 7 | 17 | |||||||||||||||||
Long-term debt due within one year | -1,509 | -1,047 | |||||||||||||||||
Long-term debt | $ | 17,623 | $ | 17,698 | |||||||||||||||
Long-term debt to financing trusts (d) | |||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2033 | $ | 206 | $ | 206 | ||||||||||||
Subordinated debentures to PECO Trust III | 7.38 | % | 2028 | 81 | 81 | ||||||||||||||
Subordinated debentures to PECO Trust IV | 5.75 | % | 2033 | 103 | 103 | ||||||||||||||
Subordinated debentures to BGE Trust | 6.2 | % | 2043 | 258 | 258 | ||||||||||||||
Total long-term debt to financing trusts | $ | 648 | $ | 648 | |||||||||||||||
(a) Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes. | |||||||||||||||||||
(c) Includes capital lease obligations of $41 million and $30 million at December 31, 2013 and 2012, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $5 million and $19 million will be made in 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. | |||||||||||||||||||
(d) Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets. | |||||||||||||||||||
Generation | |||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | 2014-2042 | $ | 6,271 | $ | 6,721 | ||||||||||
Social Security Administration | 2.93 | % | 2015 | 1 | — | ||||||||||||||
Pollution control notes: | |||||||||||||||||||
Fixed rates | 4.1 | % | 2014 | 20 | 20 | ||||||||||||||
Non-recourse debt: | |||||||||||||||||||
Fixed rates | 2.33 | % | - | 5.5 | % | 2031-2037 | 1,077 | 238 | |||||||||||
Variable rates | 1.96 | % | - | 2.77 | % | 2014-2030 | 150 | 262 | |||||||||||
Notes payable and other (a) | 4.5 | % | - | 7.83 | % | 2014-2022 | 33 | 30 | |||||||||||
1 | |||||||||||||||||||
Total long-term debt | 7,552 | 7,271 | |||||||||||||||||
Fair value adjustment | 166 | 199 | |||||||||||||||||
Unamortized debt discount and premium, net | 11 | 13 | |||||||||||||||||
Long-term debt due within one year | -561 | -28 | |||||||||||||||||
Long-term debt | $ | 7,168 | $ | 7,455 | |||||||||||||||
Includes Generation's capital lease obligations of $33 million and $30 million at December 31, 2013 and 2012, respectively. Generation will make lease payments of $4 million, $4 million, $4 million, $5 million, $5 million and $11 million in 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. | |||||||||||||||||||
During January 2014, Generation redeemed its $20 million 4.10% pollution control revenue bonds due July 1, 2014 and its $500 million 5.35% senior unsecured notes at maturity. | |||||||||||||||||||
ComEd | |||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b): | |||||||||||||||||||
Fixed rates | 1.63 | % | - | 7.63 | % | 2013-2043 | $ | 5,546 | $ | 5,447 | |||||||||
Notes payable and other (c) | 6.95 | % | - | 7.49 | % | 2014-2053 | 148 | 140 | |||||||||||
Total long-term debt | 5,694 | 5,587 | |||||||||||||||||
Unamortized debt discount and premium, net | -19 | -20 | |||||||||||||||||
Long-term debt due within one year | -617 | -252 | |||||||||||||||||
Long-term debt | $ | 5,058 | $ | 5,315 | |||||||||||||||
Long-term debt to financing trust (d) | |||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2042 | $ | 206 | $ | 206 | ||||||||||||
(a) Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes. | |||||||||||||||||||
(c) Includes ComEd's capital lease obligations of $ 8 million at December 31, 2013. Lease payments of less than $1 million will be made from 2014 through expiration at 2053. | |||||||||||||||||||
(d) Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets. | |||||||||||||||||||
On January 10, 2014, ComEd issued $300 million aggregate principal amount of its First Mortgage 2.150% Bonds, Series 115, due January 15, 2019, and $350 million aggregate principal amount of its First Mortgage 4.700% Bonds, Series 116, due January 15, 2044. The proceeds of the Bonds were used by ComEd to refinance the $17 million outstanding principal amount of its First Mortgage 5.850% Bonds, Pollution Control Series 1994C, due January 15, 2014, and the $600 million outstanding principal amount of its First Mortgage 1.625% Bonds, Series 110, due January 15, 2014, and to fund other general corporate purposes in 2014. | |||||||||||||||||||
PECO | |||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b): | |||||||||||||||||||
Fixed rates | 1.2 | % | - | 5.95 | % | 2013-2043 | $ | 2,200 | $ | 1,950 | |||||||||
Total long-term debt | 2,200 | 1,950 | |||||||||||||||||
Unamortized debt discount and premium, net | -3 | -3 | |||||||||||||||||
Long-term debt due within one year | -250 | -300 | |||||||||||||||||
Long-term debt | $ | 1,947 | $ | 1,647 | |||||||||||||||
Long-term debt to financing trusts (c) | |||||||||||||||||||
Subordinated debentures to PECO Trust III | 7.38 | % | 2028 | $ | 81 | $ | 81 | ||||||||||||
Subordinated debentures to PECO Trust IV | 5.75 | % | 2033 | 103 | 103 | ||||||||||||||
Long-term debt to financing trusts | $ | 184 | $ | 184 | |||||||||||||||
(a) Substantially all of PECO's assets are subject to the lien of its mortgage indenture. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes. | |||||||||||||||||||
(c) Amounts owed to this financing trust are recorded as debt to financing trusts within PECO's Consolidated Balance Sheets. | |||||||||||||||||||
BGE | |||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2013-2036 | $ | 1,750 | $ | 1,850 | |||||||||
Rate stabilization bonds | 5.68 | % | 5.82 | % | 2016-2017 | 265 | $ | 332 | |||||||||||
Total long-term debt | 2,015 | 2,182 | |||||||||||||||||
Unamortized debt discount and premium, net | -4 | -4 | |||||||||||||||||
Long-term debt due within one year | -70 | -467 | |||||||||||||||||
Long-term debt | $ | 1,941 | $ | 1,711 | |||||||||||||||
Long-term debt to financing trusts (a) | |||||||||||||||||||
Subordinated debentures to BGE Capital Trust II | 6.2 | % | 2043 | $ | 258 | $ | 258 | ||||||||||||
(a) Amount owed to this financing trust is recorded as debt to financing trust within BGE's Consolidated Balance Sheets. | |||||||||||||||||||
Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2014 through 2018 and thereafter are as follows: | |||||||||||||||||||
Year | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
2014 | $ | 1,428 | $ | 561 | $ | 617 | $ | 250 | $ | — | |||||||||
2015 | 1,615 | 555 | 260 | — | — | ||||||||||||||
2016 | 1,346 | 81 | 665 | 300 | 300 | ||||||||||||||
2017 | 1,396 | 706 | 425 | — | 265 | ||||||||||||||
2018 | 1,345 | 5 | 840 | 500 | — | ||||||||||||||
Thereafter | 12,278 | (a) | 5,644 | 3,093 | (b) | 1,334 | (c) | 1,708 | (d) | ||||||||||
Total | $ | 19,408 | $ | 7,552 | $ | 5,900 | $ | 2,384 | $ | 2,273 | |||||||||
(a) Includes $648 million due to ComEd, PECO and BGE financing trusts. | |||||||||||||||||||
(b) Includes $206 million due to ComEd financing trust. | |||||||||||||||||||
(c) Includes $184 million due to PECO financing trusts. | |||||||||||||||||||
(d) Includes $258 million due to BGE financing trust. | |||||||||||||||||||
Non-Recourse Debt | |||||||||||||||||||
The following are descriptions of activity with respect to certain indebtedness of Exelon's project subsidiaries that is outstanding as of December 31, 2013. The indebtedness described below is specific to certain generating facilities pledged as collateral with a net book value of approximately $1.9 billion at December 31, 2013, and all associated project financing liabilities are non-recourse to Exelon and Generation. | |||||||||||||||||||
Continental Wind. On September 30, 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million aggregate principal amount of Continental Wind's 6.00% senior secured notes due February 28, 2033. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MW. The net proceeds were distributed to Generation for its general business purposes. In connection with this non-recourse project financing, Exelon terminated existing interest rate swaps with a total notional amount of $350 million during the third quarter of 2013, and realized a total gain of $26 million upon termination. The gain on the interest rate swaps was recorded within OCI and will reduce the effective interest rate over the life of the debt for Exelon. See Note 12 — Derivative Financial Instruments for additional information on the interest rate swaps. | |||||||||||||||||||
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2013, the Continental Wind letter of credit facility had $93 million in letters of credit outstanding related to the project. | |||||||||||||||||||
ExGen Renewables Energy I LLC. On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $300 million aggregate principal amount of EGR's LIBOR plus 425 bps non-recourse senior secured loan, due February 6, 2021. EGR indirectly owns Continental Wind LLC (Continental). | |||||||||||||||||||
Antelope Valley Project Development Debt Agreement. The DOE Loan Programs Office issued a guarantee for up to $646 million for a non-recourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project is expected to be completed in the first half of 2014. The loan will mature on January 5, 2037. Interest rates on the loan are fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. | |||||||||||||||||||
In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2013, Generation had $334 million in letters of credit outstanding related to the project The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made. | |||||||||||||||||||
In connection with this agreement, Generation entered into a floating-for-fixed interest rate swap with a notional amount of $485 million to mitigate interest-rate risk associated with the financing. As Generation received additional loan advances, it subsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps associated with Antelope Valley. | |||||||||||||||||||
Sacramento PV Energy. In July, 2011, a subsidiary of Generation entered into a $41 million non-recourse project financing for a 30MW solar facility in Sacramento, California. As of December 31, 2013, $37 million was outstanding. Borrowings under the facility bear interest at a variable rate, payable quarterly, and are secured by equity interests and assets of the subsidiary. As of December 31, 2013, the subsidiary had interest rate swaps with a notional value of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $41 million facility. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps. | |||||||||||||||||||
Constellation Solar Horizons Financing. In September 2012, a subsidiary of Generation entered into an 18-year $38 million non-recourse variable interest note to recover capital used to build a 16 MW solar facility in Emmitsburg, Maryland. Interest is payable quarterly, and the note is secured by the equity interests and assets of the subsidiary. As of December 31, 2013, $36 million was outstanding. The subsidiary also executed interest rate swaps for a notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount. See Note 12—Derivative Financial Instruments for additional information regarding interest rate swaps. | |||||||||||||||||||
Secured Solar Credit Lending Agreement. In December 2013, a Generation subsidiary, Constellation Solar, LLC, paid off the remaining balance of the three-year senior secured credit facility that is designed to support the growth of solar operations in the amount of $94 million and terminated the facility. The facility was scheduled to mature in June of 2014. | |||||||||||||||||||
Other Solar Project Financings. Generation has the following amounts outstanding under solar project loan agreements: | |||||||||||||||||||
• $7 million fully amortizing by June 30, 2031 related to a solar project at the Denver International Airport, and | |||||||||||||||||||
• $10 million fully amortizing by December 31, 2031 related to a solar project in Holyoke, Massachusetts. | |||||||||||||||||||
Upstream Gas Property Asset-Based Lending Agreement. Generation has a five year asset-based lending agreement associated with certain upstream gas properties that it owns. The borrowing base committed under the facility is $110 million and can increase to a total of $500 million if the assets support a higher borrowing base and Generation is able to obtain additional commitments from lenders. The facility was amended and extended through January 2019. Borrowings under this facility are secured by the upstream gas properties, and the lenders do not have recourse against Exelon or Generation in the event of a default. As of December 31, 2013, $77 million was outstanding under the facility with interest payable quarterly. The facility includes a provision that requires the Generation entities owning the upstream gas properties subject to the agreement to maintain a current ratio of one-to-one. As of December 31, 2013, Generation was in compliance with this provision. | |||||||||||||||||||
Income_Taxes_Exelon_Generation
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||
14. Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||
Income tax expense (benefit) from continuing operations is comprised of the following components: | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 744 | $ | 250 | $ | 160 | $ | 126 | $ | 9 | ||||||||
Deferred | 140 | 360 | -27 | 23 | 100 | |||||||||||||
Investment tax credit amortization | -15 | -11 | -2 | -1 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | 181 | 50 | 50 | 16 | — | |||||||||||||
Deferred | -6 | -34 | -29 | -2 | 26 | |||||||||||||
Total | $ | 1,044 | $ | 615 | $ | 152 | $ | 162 | $ | 134 | ||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 37 | $ | 104 | $ | -40 | $ | 88 | $ | -97 | ||||||||
Deferred | 701 | 326 | 237 | 25 | 101 | |||||||||||||
Investment tax credit amortization | -11 | -6 | -2 | -2 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | -25 | -12 | 6 | 4 | — | |||||||||||||
Deferred | -75 | 88 | 38 | 12 | 4 | |||||||||||||
Total | $ | 627 | $ | 500 | $ | 239 | $ | 127 | $ | 7 | ||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 1 | $ | 431 | $ | -329 | $ | -71 | $ | -71 | ||||||||
Deferred | 1,200 | 435 | 544 | 223 | 130 | |||||||||||||
Investment tax credit amortization | -12 | -7 | -3 | -2 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | -3 | 74 | -123 | -37 | — | |||||||||||||
Deferred | 271 | 123 | 161 | 33 | 17 | |||||||||||||
Total | $ | 1,457 | $ | 1,056 | $ | 250 | $ | 146 | $ | 75 | ||||||||
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following: | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | 4.7 | 1.6 | 3.4 | 1.6 | 4.9 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 3.7 | 6.1 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.3 | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.7 | — | 0.2 | |||||||||||||
Amortization of investment tax credit, net deferred taxes | -1.9 | -3 | -0.6 | -0.1 | — | |||||||||||||
Production tax credits and other credits | -2.1 | -3.4 | -0.1 | — | — | |||||||||||||
Plant basis differences | -1.6 | — | -0.8 | -7.1 | -0.2 | |||||||||||||
Other | -0.1 | 0.7 | 0.3 | -0.3 | -0.9 | |||||||||||||
Effective income tax rate | 37.6 | % | 36.7 | % | 37.9 | % | 29.1 | % | 39 | % | ||||||||
For the Year Ended December 31, 2012 | Exelon (a) | Generation (a) | ComEd | PECO | BGE (b) | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | -3.6 | 4.7 | 4.6 | 2 | 24.3 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 5.4 | 9.1 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.4 | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.4 | — | 11.6 | |||||||||||||
Amortization of investment tax credit, net deferred taxes | -1.1 | -1.3 | -0.4 | -0.3 | -8.6 | |||||||||||||
Production tax credits and other credits | -2.2 | -3.7 | — | — | — | |||||||||||||
Plant basis differences | -2.4 | — | -0.3 | -11.5 | -9 | |||||||||||||
Merger expenses (c) | 2.4 | — | — | — | 24.2 | |||||||||||||
Fines and Penalties | 2.6 | 4.4 | — | — | — | |||||||||||||
Other | -1.1 | -0.5 | -0.6 | -0.2 | -13.9 | |||||||||||||
Effective income tax rate | 34.9 | % | 47.3 | % | 38.7 | % | 25 | % | 63.6 | % | ||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE (b) | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | 4.4 | 4.5 | 3.6 | -0.5 | 5.2 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 0.5 | 0.7 | — | — | — | |||||||||||||
Domestic production activities deduction | -0.3 | -0.4 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.2 | — | — | — | |||||||||||||
Health care reform legislation | -0.2 | — | -1 | — | -0.5 | |||||||||||||
Amortization of investment tax credit | -0.3 | -0.3 | -0.4 | -0.3 | -0.5 | |||||||||||||
Production tax credits | -0.9 | -1.2 | — | — | — | |||||||||||||
Plant basis differences | -1 | — | -0.3 | -6.9 | -2 | |||||||||||||
Other | -0.2 | -0.7 | 0.6 | — | -1.7 | |||||||||||||
Effective income tax rate | 36.8 | % | 37.4 | % | 37.5 | % | 27.3 | % | 35.5 | % | ||||||||
__________ | ||||||||||||||||||
(a) Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 - December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012 - December 31, 2012. | ||||||||||||||||||
(b) BGE activity represents the activity for the twelve months ended December 31, 2012 and 2011. | ||||||||||||||||||
(c) Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger. | ||||||||||||||||||
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2013 and 2012 are presented below: | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Plant basis differences | $ | -11,612 | $ | -3,879 | $ | -3,523 | $ | -2,573 | $ | -1,538 | ||||||||
Accrual based contracts | -214 | -214 | — | — | — | |||||||||||||
Derivatives and other financial instruments | -509 | -505 | -4 | — | — | |||||||||||||
Deferred pension and post-retirement obligation | 1,489 | -362 | -522 | — | -74 | |||||||||||||
Nuclear decommissioning activities | -647 | -646 | — | — | — | |||||||||||||
Deferred debt refinancing costs | 173 | 79 | -21 | -3 | -5 | |||||||||||||
Regulatory | -1,611 | — | -241 | 42 | -253 | |||||||||||||
Tax loss carryforward | 252 | 76 | 47 | 11 | 52 | |||||||||||||
Tax credit carryforward | 534 | 534 | — | — | — | |||||||||||||
Investment in CENG | -541 | -541 | — | — | — | |||||||||||||
Other, net | 804 | 67 | 154 | 122 | 26 | |||||||||||||
Deferred income tax liabilities (net) | $ | -11,882 | $ | -5,391 | $ | -4,110 | $ | -2,401 | $ | -1,792 | ||||||||
Unamortized investment tax credits | -490 | -454 | -22 | -3 | -6 | |||||||||||||
Total deferred income tax liabilities (net) and | ||||||||||||||||||
unamortized investment tax credits | $ | -12,372 | $ | -5,845 | $ | -4,132 | $ | -2,404 | $ | -1,798 | ||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Plant basis differences | $ | -10,689 | $ | -3,545 | $ | -3,537 | $ | -2,437 | $ | -1,553 | ||||||||
Accrual based contracts | -389 | -389 | — | — | — | |||||||||||||
Derivatives and other financial instruments | -392 | -479 | -4 | — | — | |||||||||||||
Deferred pension and post-retirement obligation | 2,356 | -439 | -598 | -11 | -12 | |||||||||||||
Nuclear decommissioning activities | -604 | -604 | — | — | — | |||||||||||||
Deferred debt refinancing costs | -537 | 163 | -25 | -4 | -4 | |||||||||||||
Regulatory | -1,857 | — | -116 | 50 | -253 | |||||||||||||
Tax loss carryforward | 421 | 226 | 32 | 14 | 105 | |||||||||||||
Tax credit carryforward | 226 | 226 | — | — | — | |||||||||||||
Investment in CENG | -405 | -419 | — | — | — | |||||||||||||
Other, net | 701 | 9 | 83 | 100 | 67 | |||||||||||||
Deferred income tax liabilities (net) | $ | -11,169 | $ | -5,251 | $ | -4,165 | $ | -2,288 | $ | -1,650 | ||||||||
Unamortized investment tax credits | -251 | -216 | -24 | -3 | -6 | |||||||||||||
Total deferred income tax liabilities (net) and | ||||||||||||||||||
unamortized investment tax credits | $ | -11,420 | $ | -5,467 | $ | -4,189 | $ | -2,291 | $ | -1,656 | ||||||||
The following table provides the Registrants' carryforwards and any corresponding valuation allowances as of December 31, 2013. | ||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Federal | ||||||||||||||||||
Federal net operating loss | $ | 377 | (a) | $ | 36 | $ | 139 | $ | 0 | $ | 31 | |||||||
Deferred taxes on Federal net operating loss | 132 | 13 | 49 | 0 | 11 | |||||||||||||
Federal general business credits carryforward | 556 | (b) | 556 | 0 | 0 | 0 | ||||||||||||
State | ||||||||||||||||||
State net operating losses and other credit | ||||||||||||||||||
carryforwards | 3,061 | (c) | 1,498 | (d) | 0 | 167 | (e) | 768 | (f) | |||||||||
Deferred taxes on state tax attributes (net) | 161 | 82 | 0 | 11 | 41 | |||||||||||||
Valuation allowance on state tax attributes | 13 | 11 | 0 | 0 | 1 | |||||||||||||
__________ | ||||||||||||||||||
Exelon's federal net operating loss will expire beginning in 2031 | ||||||||||||||||||
Exelon's federal general business credit carryforwards will expire beginning in 2032 | ||||||||||||||||||
Exelon's state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||||||||||||
Generation's state net operating losses losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||||||||||||
PECO's state net operating losses will expire beginning in 2031 | ||||||||||||||||||
BGE's state net operating losses will expire beginning in 2026 | ||||||||||||||||||
Tabular reconciliation of unrecognized tax benefits | ||||||||||||||||||
The following table provides a reconciliation of the Registrants' unrecognized tax benefits as of December 31, 2013, 2012 and 2011: | ||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2013 | $ | 1,024 | $ | 876 | $ | 67 | $ | 44 | $ | — | ||||||||
Increases based on tax positions related to 2013 | 19 | 19 | — | — | — | |||||||||||||
Change to positions that only affect timing | 649 | 36 | 257 | — | — | |||||||||||||
Increases based on tax positions prior to 2013 | 493 | 493 | — | — | — | |||||||||||||
Decreases based on tax positions prior to 2013 | -6 | -5 | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | -4 | -4 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2013 | $ | 2,175 | $ | 1,415 | $ | 324 | $ | 44 | $ | — | ||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2012 | $ | 807 | $ | 683 | $ | 70 | $ | 48 | $ | 11 | ||||||||
Merger Balance Transfer | 195 | 183 | — | — | — | |||||||||||||
Increases based on tax positions related to 2012 | 34 | 3 | — | — | — | |||||||||||||
Change to positions that only affect timing | -88 | -69 | -3 | -4 | -11 | |||||||||||||
Increases based on tax positions prior to 2012 | 91 | 91 | — | — | — | |||||||||||||
Decreases based on tax positions prior to 2012 | -6 | -6 | — | — | — | |||||||||||||
Decreases related to settlements with taxing authorities | -2 | -2 | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | -7 | -7 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2012 | $ | 1,024 | $ | 876 | $ | 67 | $ | 44 | $ | — | ||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2011 | $ | 787 | $ | 664 | $ | 72 | $ | 44 | $ | 73 | ||||||||
Increases based on tax positions related to 2011 | 5 | 1 | — | 4 | — | |||||||||||||
Change to positions that only affect timing | 21 | 24 | -2 | — | -62 | |||||||||||||
Decreases based on tax positions prior to 2011 | -3 | -3 | — | — | — | |||||||||||||
Decrease from expiration of statute of limitations | -3 | -3 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2011 | $ | 807 | $ | 683 | $ | 70 | $ | 48 | $ | 11 | ||||||||
Included in Exelon's unrecognized tax benefits balance at December 31, 2013 and 2012 are approximately $1,387 million and $730 million, respectively, of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively. | ||||||||||||||||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | ||||||||||||||||||
Exelon and Generation have $788 million and $768 million, respectively, of unrecognized tax benefits at December 31, 2013 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $294 million and $263 million, respectively, of unrecognized tax benefits at December 31, 2012 that, if recognized, would decrease the effective tax rate. | ||||||||||||||||||
Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date | ||||||||||||||||||
Nuclear Decommissioning Liabilities (Exelon and Generation) | ||||||||||||||||||
AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen's refund claims. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government's motion denying AmerGen's claims for refund. Exelon is expecting to appeal this decision to the United States Court of Appeals for the Federal Circuit during 2014. | ||||||||||||||||||
Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the total amount of unrecognized tax benefits will significantly decrease in the next twelve months. | ||||||||||||||||||
Settlement of Income Tax Audits and Litigation | ||||||||||||||||||
As of December 31, 2013, Exelon and Generation had approximately $256 million of other federal and state unrecognized tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing federal and state audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. In January 2014, certain of these unrecognized tax benefits were effectively settled and thus will result in reduced tax expense of $33 million at Generation in the first quarter of 2014. | ||||||||||||||||||
See Other Tax Matters – Like Kind Exchange section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months. | ||||||||||||||||||
Total amounts of interest and penalties recognized | ||||||||||||||||||
The following table represents the net interest receivable (payable), including interest related to uncertain tax positions reflected in the Registrants' Consolidated Balance Sheets. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest. | ||||||||||||||||||
Net interest receivable (payable) as of | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
31-Dec-13 | $ | -349 | $ | -37 | $ | -174 | $ | 3 | $ | — | ||||||||
31-Dec-12 | 31 | -20 | 107 | 2 | — | |||||||||||||
The following table sets forth the net interest expense, including interest related to uncertain tax positions, recognized in interest expense (income) in other income and deductions in the Registrants' Consolidated Statements of Operations. The Registrants have not accrued any penalties with respect to uncertain tax positions. Prior to the merger legacy Constellation recorded interest related to uncertain tax positions as a tax and not interest. | ||||||||||||||||||
Net interest expense (income) for the years ended | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
31-Dec-13 | $ | 391 | $ | 17 | $ | 281 | $ | -1 | $ | — | ||||||||
31-Dec-12 | -1 | 11 | -20 | -1 | 9 | |||||||||||||
31-Dec-11 | -56 | -40 | -14 | -1 | -3 | |||||||||||||
Description of tax years that remain open to assessment by major jurisdiction | ||||||||||||||||||
Taxpayer | Open Years | |||||||||||||||||
Exelon (and predecessors) and subsidiaries consolidated Federal income | ||||||||||||||||||
tax returns | 1999-2012 | |||||||||||||||||
Constellation and subsidiaries consolidated Federal income tax returns | 2009-March 2012 | |||||||||||||||||
Exelon and subsidiaries Illinois unitary income tax returns | 2007-2012 | |||||||||||||||||
Constellation combined New York corporate income tax returns | 2008-2012 | |||||||||||||||||
Various separate company Pennsylvania corporate net income tax returns | 2008-2012 | |||||||||||||||||
BGE Maryland Corporate net income tax returns | 2004-2007,2009-2012 | |||||||||||||||||
Various other (Non-BGE) Maryland Corporate net income tax returns | 2009-2012 | |||||||||||||||||
Other Tax Matters | ||||||||||||||||||
Like-Kind Exchange | ||||||||||||||||||
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $2.8 billion of tax gain on the sale of ComEd's fossil generating assets. The gain was deferred by reinvesting the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $2.8 billion was taxable in 1999. | ||||||||||||||||||
Exelon has been unable to reach agreement with the IRS regarding the dispute over the like kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $87 million for a substantial understatement of tax. | ||||||||||||||||||
Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like-kind exchange position. | ||||||||||||||||||
On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison's deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter. | ||||||||||||||||||
In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon's current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013, Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd's equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the $87 million penalty assertion will ultimately be sustained and therefore no liability for the penalty has been recorded. | ||||||||||||||||||
On September 30, 2013, the Internal Revenue Service issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit's decision in Consolidated Edison. | ||||||||||||||||||
As of December 31, 2013, in the event of a fully successful IRS challenge to Exelon's like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable may be as much as $840 million, of which approximately $305 million would be attributable to ComEd after consideration of Exelon's agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash impacts would likely change by a material amount. | ||||||||||||||||||
Accounting for Generation Repairs (Exelon and Generation) | ||||||||||||||||||
On April 30, 2013, the IRS issued Revenue Procedure 2013-24 providing guidance for determining the appropriate tax treatment of costs incurred to repair electric generation assets. Generation expects to change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has estimated that adoption of the new method will result in a cash tax detriment of approximately $100 - $120 million. | ||||||||||||||||||
Accounting for Electric Transmission and Distribution Property Repairs (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||
On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. ComEd and PECO adopted the safe harbor in the Revenue Procedure for the 2011 and 2010 tax years, respectively. For the year ended December 31, 2011, the adoption of the safe harbor resulted in a $35 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $28 million due to a decrease in its domestic production activities deduction, which are reflected in the effective income tax rate reconciliation above in the plant basis differences and domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoption of the safe harbor resulted in a cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million, $95 million respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million related to a decreased domestic production activities deduction. | ||||||||||||||||||
BGE adopted the safe harbor for the short period 2012 pre-merger tax year. For the year ended December 31, 2012, the adoption of the safe harbor resulted in a cash tax benefit at BGE in the amount of $27 million. | ||||||||||||||||||
See Note 3 – Regulatory Matters for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO's cash tax benefit resulting from the application of the method change to years prior to 2010. | ||||||||||||||||||
Accounting for Gas Distribution Property Repairs (Exelon, PECO and BGE). | ||||||||||||||||||
In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The change to the newly adopted method for the 2011 tax year and 2012 resulted in a tax benefit of $26 million at Exelon, of which $29 million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic production activities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. The IRS is expected to issue industry guidance in the near future. Exelon, PECO and BGE will then determine the financial statement impacts of the gas distribution repair costs accounting method changes after guidance is issued. | ||||||||||||||||||
Accounting for Final Tangible Property Regulations (Exelon, Generation, ComEd, PECO, and BGE) | ||||||||||||||||||
On September 19, 2013, the Treasury Department and the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have a material impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant's 2014 taxable year. | ||||||||||||||||||
2011 Illinois State Tax Rate Legislation (Exelon, Generation and ComEd) | ||||||||||||||||||
The Taxpayer Accountability and Budget Stabilization Act, (SB 2505), enacted into law in Illinois on January 13, 2011, increases the corporate tax rate in Illinois from 7.3% to 9.5% for tax years 2011 – 2014, provides for a reduction in the rate from 9.5% to 7.75% for tax years 2015 – 2024 and further reduces the rate from 7.75% to 7.3% for tax years 2025 and thereafter. Pursuant to the rate change, Exelon re-evaluated its deferred state income taxes during the first quarter of 2011. Illinois' corporate income tax rate changes resulted in a charge to state deferred taxes (net of Federal taxes) during the first quarter of 2011 of $7 million, $11 million and $4 million for Exelon, Generation and ComEd, respectively. Exelon's and ComEd's charge is net of a regulatory asset of $15 million. | ||||||||||||||||||
In 2011, the income tax rate change increased Exelon's Illinois income tax provision (net of Federal taxes) by approximately $7 million, of which $12 million and $5 million of additional tax relates to Exelon Corporate and Generation, respectively, and a $10 million benefit for ComEd. The 2011 tax benefit at ComEd reflects the impact of a 2011 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010 and the electric transmission and distribution property repairs deduction discussed below. | ||||||||||||||||||
Long-Term State Tax Apportionment (Exelon and Generation) | ||||||||||||||||||
Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of Exelon's and Generation's deferred state income taxes. In 2011 as a result of the 2011 Illinois State Tax Rate Legislation discussed above, Exelon and Generation re-evaluated their long-term state tax apportionment for Illinois and all other states where they have state income tax obligations, resulting in recording a deferred state tax expense during the first quarter of 2011 of $22 million and $11 million (net of Federal taxes) for Exelon and Generation, respectively. The long-term state tax apportionment also was revised in the fourth quarter of 2011 pursuant to long-term state tax apportionment policy, resulting in recording an additional deferred state tax expense of $1 million and a deferred state tax benefit of $8 million (net of Federal taxes) for Exelon and Generation, respectively. | ||||||||||||||||||
As a result of the merger with Constellation, Exelon and Generation re-evaluated their long-term state tax apportionment in the first quarter of 2012. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. The long-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3 million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no change to the long-term state tax apportionment for BGE, ComEd and PECO. | ||||||||||||||||||
The long-term state tax apportionment was revised in the fourth quarter of 2013 pursuant to its long-term state tax apportionment policy, resulting in the recording of amounts that are immaterial for Exelon and Generation, respectively. | ||||||||||||||||||
Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||
Generation, ComEd, PECO and BGE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2013, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $26 million and $27 million, respectively. During 2013, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd's and BGE's 2013 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010. During 2012, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $48 million and $9 million, respectively. During 2012, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd's and BGE's 2012 tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010. | ||||||||||||||||||
ComEd received a non-cash contribution to equity from Exelon in 2012 of $11, related to tax benefits associated with capital projects constructed by ComEd on behalf of Exelon and Generation. |
Asset_Retirement_Obligations_E
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Asset Retirement Obligations [Line Items] | ' | |||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | |||||||||||
15. Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Nuclear Decommissioning Asset Retirement Obligations | ||||||||||||
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. | ||||||||||||
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2012 to December 31, 2013: | ||||||||||||
Exelon and Generation | ||||||||||||
Nuclear decommissioning ARO at January 1, 2012 | $ | 3,680 | ||||||||||
Accretion expense | 231 | |||||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 833 | |||||||||||
Costs incurred to decommission retired plants | -3 | |||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | 4,741 | |||||||||||
Accretion expense | 259 | |||||||||||
Net decrease due to changes in, and timing of, estimated future cash flows | -140 | |||||||||||
Costs incurred to decommission retired plants | -5 | |||||||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | ||||||||||
(a) Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2013, Generation's ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2012, Generation's ARO increased by $1,061 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
During 2013, Generation's ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2012, Generation's ARO increased by $1,061 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
Nuclear Decommissioning Trust Fund Investments | ||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. | ||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | ||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | ||||||||||||
During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investment strategy. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities. At December 31, 2012, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities. | ||||||||||||
At December 31, 2013, and 2012, Exelon and Generation had NDT fund investments totaling $8,071 million and $7,248 million, respectively. | ||||||||||||
The following table provides unrealized gains (losses) on NDT funds for 2013, 2012 and 2011: | ||||||||||||
Exelon and Generation | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Regulatory Agreement Units (a) | $ | 406 | $ | 386 | $ | -74 | ||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Non-Regulatory Agreement Units (b) (c) | 146 | 105 | -4 | |||||||||
__________ | ||||||||||||
(a) Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | ||||||||||||
(b) Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
(c) Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income. | ||||||||||||
Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation's obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds are expected to exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon's and Generation's results of operations and financial position could be material. As of December 31, 2013, the NDT funds of each of the former ComEd units are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines. | ||||||||||||
Based on the regulatory agreement supported by the PAPUC that dictates Generation's rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon's and Generation's ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon's and Generation's results of operations and financial position could be material. | ||||||||||||
The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the portions of the Peach Bottom nuclear plants that are not subject to regulatory agreements with respect to the NDT funds are reflected in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, as there are no regulatory agreements associated with these units. | ||||||||||||
Refer to Note 3 – Regulatory Matters and Note 25 - Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations. | ||||||||||||
Zion Station Decommissioning | ||||||||||||
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation's transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA. | ||||||||||||
On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. On July 29, 2013, United States District Court for the Northern District of Illinois dismissed the amended complaint. On August 26, 2013, the plaintiffs filed a notice of appeal with the United States Court of Appeals for the Seventh Circuit. On January 31, 2014, the United States Court of Appeals for the Seventh Circuit dismissed the appeal. | ||||||||||||
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation to the SNF following ZionSolutions completion of its contractual obligations, to transfer the SNF at Zion Station to the DOE for ultimate disposal, and to complete all remaining decommissioning activities associated with the SNF storage facility. Generation has a liability of approximately $82 million, which is included within the nuclear decommissioning ARO at December 31, 2013. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2013 and 2012: | ||||||||||||
Exelon and Generation | ||||||||||||
2013 | 2012 | |||||||||||
Carrying value of Zion Station pledged assets | $ | 458 | $ | 614 | ||||||||
Payable to Zion Solutions (a) | 414 | 564 | ||||||||||
Current portion of payable to Zion Solutions (b) | 109 | 132 | ||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 498 | 335 | ||||||||||
__________ | ||||||||||||
(a) Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | ||||||||||||
(b) Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
(c) Cumulative withdrawals since September 1, 2010. | ||||||||||||
ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station. | ||||||||||||
NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation's and Exelon's Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees. | ||||||||||||
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2013 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC). | ||||||||||||
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2013 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.9% to 6.7% (as compared to a historical 5-year annual average pre-tax return of approximately 11.7%). | ||||||||||||
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation's ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon's and Generation's cash flows and financial position may be significantly adversely affected. | ||||||||||||
On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | ||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. | ||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | ||||||||||||
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation's units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. | ||||||||||||
Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 - Significant Accounting Policies for additional information on the Registrants' accounting policy for AROs. | ||||||||||||
The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants' Consolidated Balance Sheets from January 1, 2012 to December 31, 2013: | ||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||
Non-nuclear AROs at January 1, 2012 | $ | 209 | $ | 92 | $ | 89 | $ | 28 | $ | 1 | ||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 27 | 18 | 8 | 1 | 7 | |||||||
Development projects | 47 | 47 | — | — | — | |||||||
Accretion expense (b) | 13 | 8 | 4 | 1 | — | |||||||
Merger with Constellation (c) | 58 | 50 | — | — | — | |||||||
Payments | -11 | -8 | -2 | -1 | — | |||||||
Non-nuclear AROs at December 31, 2012 | 343 | 207 | 99 | 29 | 8 | |||||||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 1 | -11 | — | — | 12 | |||||||
Development projects | 2 | 2 | — | — | — | |||||||
Accretion expense (b) | 18 | 13 | 4 | 1 | — | |||||||
Payments | -13 | -10 | -2 | — | -1 | |||||||
Non-nuclear AROs at December 31, 2013 (d) | $ | 351 | $ | 201 | $ | 101 | $ | 30 | $ | 19 | ||
During the year ended December 31, 2013, Generation recorded an increase in operating and maintenance expense of $13 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2013. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd, PECO, and BGE did not record any reductions in operating and maintenance expense for the year ended December 31, 2012. | ||||||||||||
For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | ||||||||||||
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information. | ||||||||||||
Includes $ 2 million, $ 1 million, and $0 million as the current portion of the ARO at December 31, 2013 for ComEd, PECO, and BGE, respectively, which is included in other current liabilities on Exelon's and each of the respective utilities' Consolidated Balance Sheets. | ||||||||||||
Exelon Generation Co L L C [Member] | ' | |||||||||||
Asset Retirement Obligations [Line Items] | ' | |||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | ' | |||||||||||
15. Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Nuclear Decommissioning Asset Retirement Obligations | ||||||||||||
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. | ||||||||||||
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2012 to December 31, 2013: |
Nuclear_Decommissioning_Exelon
Nuclear Decommissioning (Exelon and Generation) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | |||||||||||
Nuclear Decommissioning (Exelon and Generation) | ' | |||||||||||
15. Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Nuclear Decommissioning Asset Retirement Obligations | ||||||||||||
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. | ||||||||||||
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2012 to December 31, 2013: | ||||||||||||
Exelon and Generation | ||||||||||||
Nuclear decommissioning ARO at January 1, 2012 | $ | 3,680 | ||||||||||
Accretion expense | 231 | |||||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 833 | |||||||||||
Costs incurred to decommission retired plants | -3 | |||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | 4,741 | |||||||||||
Accretion expense | 259 | |||||||||||
Net decrease due to changes in, and timing of, estimated future cash flows | -140 | |||||||||||
Costs incurred to decommission retired plants | -5 | |||||||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | ||||||||||
(a) Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2013, Generation's ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2012, Generation's ARO increased by $1,061 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
During 2013, Generation's ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were entirely offset by decreases in Property, plant and equipment within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
During 2012, Generation's ARO increased by $1,061 million. The increase in the ARO was largely driven by four factors: i) changes in the timing of the future nominal cash flows resulting from an assumed five year deferral to 2025 of the acceptance date of spent nuclear fuel by the DOE coupled with the fact that; ii) cash flows affected by this change in timing are re-measured and discounted at current CARFRs, which had dramatically decreased given the lower interest rate environment; iii) an increase in the estimated costs to decommission the Quad Cities, Dresden and Clinton nuclear units resulting from the completion of updated decommissioning costs studies received during 2012; and iv) accretion of the obligation. The increase in the ARO due to the changes in, and timing of, estimated cash flows resulted in $10 million of expense, which is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
Nuclear Decommissioning Trust Fund Investments | ||||||||||||
NDT funds have been established for each generating station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit. | ||||||||||||
The NDT funds associated with the former ComEd, former PECO and former AmerGen units have been funded with amounts collected from ComEd customers, PECO customers and the previous owners of the former AmerGen plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts collected from ComEd and PECO customers, Generation has not made contributions to the NDT funds. | ||||||||||||
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below). Generation has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units, Generation retains any funds remaining in the funds after decommissioning. | ||||||||||||
During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investment strategy. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities. At December 31, 2012, approximately 47% of the funds were invested in equity securities and 53% were invested in fixed income securities. | ||||||||||||
At December 31, 2013, and 2012, Exelon and Generation had NDT fund investments totaling $8,071 million and $7,248 million, respectively. | ||||||||||||
The following table provides unrealized gains (losses) on NDT funds for 2013, 2012 and 2011: | ||||||||||||
Exelon and Generation | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Regulatory Agreement Units (a) | $ | 406 | $ | 386 | $ | -74 | ||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Non-Regulatory Agreement Units (b) (c) | 146 | 105 | -4 | |||||||||
__________ | ||||||||||||
(a) Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | ||||||||||||
(b) Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
(c) Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income. | ||||||||||||
Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation's obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds are expected to exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon's and Generation's results of operations and financial position could be material. As of December 31, 2013, the NDT funds of each of the former ComEd units are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines. | ||||||||||||
Based on the regulatory agreement supported by the PAPUC that dictates Generation's rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the seven former PECO nuclear units, regardless of whether the funds held in the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon's and Generation's ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon's and Generation's results of operations and financial position could be material. | ||||||||||||
The decommissioning-related activities related to the Clinton, Oyster Creek and Three Mile Island nuclear plants (the former AmerGen units) and the portions of the Peach Bottom nuclear plants that are not subject to regulatory agreements with respect to the NDT funds are reflected in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, as there are no regulatory agreements associated with these units. | ||||||||||||
Refer to Note 3 – Regulatory Matters and Note 25 - Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations. | ||||||||||||
Zion Station Decommissioning | ||||||||||||
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation's transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA. | ||||||||||||
On July 14, 2011, three people filed a purported class action lawsuit in the United States District Court for the Northern District of Illinois naming ZionSolutions and Bank of New York Mellon as defendants and seeking, among other things, an accounting for use of NDT funds, an injunction against the use of NDT funds, the appointment of a trustee for the NDT funds, and the return of NDT funds to customers of ComEd to the extent legally entitled thereto. On July 20, 2012, ZionSolutions and Bank of New York Mellon filed a motion to dismiss the amended complaint for failing to state a claim. On July 29, 2013, United States District Court for the Northern District of Illinois dismissed the amended complaint. On August 26, 2013, the plaintiffs filed a notice of appeal with the United States Court of Appeals for the Seventh Circuit. On January 31, 2014, the United States Court of Appeals for the Seventh Circuit dismissed the appeal. | ||||||||||||
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation to the SNF following ZionSolutions completion of its contractual obligations, to transfer the SNF at Zion Station to the DOE for ultimate disposal, and to complete all remaining decommissioning activities associated with the SNF storage facility. Generation has a liability of approximately $82 million, which is included within the nuclear decommissioning ARO at December 31, 2013. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2013 and 2012: | ||||||||||||
Exelon and Generation | ||||||||||||
2013 | 2012 | |||||||||||
Carrying value of Zion Station pledged assets | $ | 458 | $ | 614 | ||||||||
Payable to Zion Solutions (a) | 414 | 564 | ||||||||||
Current portion of payable to Zion Solutions (b) | 109 | 132 | ||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 498 | 335 | ||||||||||
__________ | ||||||||||||
(a) Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | ||||||||||||
(b) Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
(c) Cumulative withdrawals since September 1, 2010. | ||||||||||||
ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and will construct a dry cask storage facility on the land for the SNF currently held in SNF pools at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by EnergySolutions or ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions has also provided a performance guarantee and entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station. | ||||||||||||
NRC Minimum Funding Requirements. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation's and Exelon's Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees. | ||||||||||||
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2013 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC). | ||||||||||||
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2013 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.9% to 6.7% (as compared to a historical 5-year annual average pre-tax return of approximately 11.7%). | ||||||||||||
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation's ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon's and Generation's cash flows and financial position may be significantly adversely affected. | ||||||||||||
On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. | ||||||||||||
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. While Generation does not believe that any sanction is appropriate, the ultimate outcome of this proceeding including the amount of a potential fine or sanction, if any, is uncertain. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. In the normal course of NRC review, Generation has received a series of data requests that are unrelated to the potential apparent violations and the pre-decisional enforcement conference. Generation continues to cooperate with the NRC and provide the requested information. Generation does not have a definite date on which it will receive a response from the NRC. | ||||||||||||
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Exelon's nuclear power plants. Exelon and Generation are cooperating with the SEC and providing the requested documents. | ||||||||||||
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation's units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO nuclear plants, the NRC minimum funding status of those plants could change at subsequent NRC filing dates. | ||||||||||||
Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 - Significant Accounting Policies for additional information on the Registrants' accounting policy for AROs. | ||||||||||||
The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants' Consolidated Balance Sheets from January 1, 2012 to December 31, 2013: | ||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||
Non-nuclear AROs at January 1, 2012 | $ | 209 | $ | 92 | $ | 89 | $ | 28 | $ | 1 | ||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 27 | 18 | 8 | 1 | 7 | |||||||
Development projects | 47 | 47 | — | — | — | |||||||
Accretion expense (b) | 13 | 8 | 4 | 1 | — | |||||||
Merger with Constellation (c) | 58 | 50 | — | — | — | |||||||
Payments | -11 | -8 | -2 | -1 | — | |||||||
Non-nuclear AROs at December 31, 2012 | 343 | 207 | 99 | 29 | 8 | |||||||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 1 | -11 | — | — | 12 | |||||||
Development projects | 2 | 2 | — | — | — | |||||||
Accretion expense (b) | 18 | 13 | 4 | 1 | — | |||||||
Payments | -13 | -10 | -2 | — | -1 | |||||||
Non-nuclear AROs at December 31, 2013 (d) | $ | 351 | $ | 201 | $ | 101 | $ | 30 | $ | 19 | ||
During the year ended December 31, 2013, Generation recorded an increase in operating and maintenance expense of $13 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2013. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd, PECO, and BGE did not record any reductions in operating and maintenance expense for the year ended December 31, 2012. | ||||||||||||
For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | ||||||||||||
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information. | ||||||||||||
Includes $ 2 million, $ 1 million, and $0 million as the current portion of the ARO at December 31, 2013 for ComEd, PECO, and BGE, respectively, which is included in other current liabilities on Exelon's and each of the respective utilities' Consolidated Balance Sheets. | ||||||||||||
Exelon Generation Co L L C [Member] | ' | |||||||||||
Nuclear Decommissioning Disclosure [Line Items] | ' | |||||||||||
Nuclear Decommissioning (Exelon and Generation) | ' | |||||||||||
15. Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
Nuclear Decommissioning Asset Retirement Obligations | ||||||||||||
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. | ||||||||||||
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2012 to December 31, 2013: |
Retirement_Benefits_Exelon_Gen
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Retirement Benefits [Line Items] | ' | |||||||||||||||||||
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||
16. Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||
As of December 31, 2013, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's benefit plans and its related assets. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2013. | ||||||||||||||||||||
Operating Company | ||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||
Qualified Pension Plans: | ||||||||||||||||||||
Exelon Corporation Retirement Program | X | X | X | X | ||||||||||||||||
Exelon Corporation Cash Balance Pension Plan | X | X | X | X | ||||||||||||||||
Exelon Corporation Pension Plan for | ||||||||||||||||||||
Bargaining Unit Employees | X | X | X | |||||||||||||||||
Exelon New England Union Employees Pension Plan | X | |||||||||||||||||||
Exelon Employee Pension Plan for Clinton, | ||||||||||||||||||||
TMI and Oyster Creek | X | X | X | |||||||||||||||||
Pension Plan of Constellation Energy Group, Inc. | X | X | X | |||||||||||||||||
Constellation Mystic Power, LLC Union Employees | ||||||||||||||||||||
Pension Plan Including Plan A and Plan B | X | |||||||||||||||||||
Non-Qualified Pension Plans: | ||||||||||||||||||||
Exelon Corporation Supplemental Pension Benefit Plan | ||||||||||||||||||||
and 2000 Excess Benefit Plan | X | X | X | X | ||||||||||||||||
Exelon Corporation Supplemental Management | ||||||||||||||||||||
Retirement Plan | X | X | X | X | ||||||||||||||||
Constellation Energy Group, Inc. Senior Executive | ||||||||||||||||||||
Supplemental Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Supplemental | ||||||||||||||||||||
Pension Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Benefits Restoration | ||||||||||||||||||||
Plan | X | X | X | |||||||||||||||||
Baltimore Gas & Electric Company Executive | ||||||||||||||||||||
Benefit Plan | X | X | X | |||||||||||||||||
Baltimore Gas & Electric Company Manager | ||||||||||||||||||||
Benefit Plan | X | X | X | |||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||
PECO Energy Company Retiree Medical Plan | X | X | X | |||||||||||||||||
Exelon Corporation Health Care Program | X | X | X | |||||||||||||||||
Exelon Corporation Employees' Life Insurance Plan | X | X | X | X | ||||||||||||||||
Constellation Energy Group, Inc. Retiree Medical Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Retiree Dental Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Employee Life | ||||||||||||||||||||
Insurance Plan and Family Life Insurance Plan | X | X | X | |||||||||||||||||
Constellation Mystic Power, LLC Post-Employment | ||||||||||||||||||||
Medical Account Savings Plan | X | |||||||||||||||||||
Exelon New England Union Post-Employment | ||||||||||||||||||||
Medical Savings Account Plan | X | |||||||||||||||||||
Exelon's traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying these plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations. | ||||||||||||||||||||
Benefit Obligations, Plan Assets and Funded Status | ||||||||||||||||||||
Exelon recognizes the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated Other Comprehensive Income (AOCI) and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31. | ||||||||||||||||||||
During the first quarter of 2013, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2013. This valuation resulted in an increase to the pension obligation of $8 million and a decrease to the other postretirement benefit obligation of $39 million. Additionally, accumulated other comprehensive loss decreased by approximately $75 million (after tax) and regulatory assets increased by approximately $93 million. During the second quarter of 2013, Exelon received the updated valuation for the legacy Constellation pension and other postretirement obligations to reflect actual census data as of January 1, 2013. This valuation resulted in an increase to the pension obligation of $23 million and a decrease to the other postretirement benefit obligation of $12 million. Additionally, accumulated other comprehensive loss increased by approximately $2 million (after tax) and regulatory assets increased by approximately $14 million. | ||||||||||||||||||||
The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined: | ||||||||||||||||||||
Other | ||||||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||
Net benefit obligation at beginning of year | $ | 16,800 | $ | 13,538 | $ | 4,820 | $ | 4,062 | ||||||||||||
Service cost | 317 | 280 | 162 | 156 | ||||||||||||||||
Interest cost | 650 | 698 | 194 | 205 | ||||||||||||||||
Plan participants’ contributions | 0 | 0 | 34 | 34 | ||||||||||||||||
Actuarial loss (gain) | -1,363 | 1,520 | -551 | 313 | ||||||||||||||||
Plan amendments | 1 | 0 | 15 | -103 | ||||||||||||||||
Acquisitions/divestitures | 0 | 1,880 | 0 | 362 | ||||||||||||||||
Curtailments | 0 | -10 | 0 | -8 | ||||||||||||||||
Settlements(a) | -69 | -169 | 0 | 0 | ||||||||||||||||
Contractual termination benefits | 0 | 15 | 0 | 6 | ||||||||||||||||
Gross benefits paid | -877 | -952 | -223 | -219 | ||||||||||||||||
Federal subsidy on benefits paid | 0 | 0 | 0 | 12 | ||||||||||||||||
Net benefit obligation at end of year | $ | 15,459 | $ | 16,800 | $ | 4,451 | $ | 4,820 | ||||||||||||
Change in plan assets: | ||||||||||||||||||||
Fair value of net plan assets at beginning of year | $ | 13,357 | $ | 11,302 | $ | 2,135 | $ | 1,797 | ||||||||||||
Actual return on plan assets | 821 | 1,484 | 209 | 197 | ||||||||||||||||
Employer contributions | 339 | 149 | 83 | 325 | ||||||||||||||||
Plan participants’ contributions | 0 | 0 | 34 | 34 | ||||||||||||||||
Benefits paid(b) | -877 | -952 | -223 | -218 | ||||||||||||||||
Acquisitions/divestitures | 0 | 1,543 | 0 | 0 | ||||||||||||||||
Settlements(a) | -69 | -169 | 0 | 0 | ||||||||||||||||
Fair value of net plan assets at end of year | $ | 13,571 | $ | 13,357 | $ | 2,238 | $ | 2,135 | ||||||||||||
(a) Represents cash settlements only. | ||||||||||||||||||||
(b) Exelon's other postretirement benefits paid for the year ended December 31, 2012 are net of $1.3 million of reinsurance proceeds received from the Department of Health and Human Services as part of the Early Retiree Reinsurance Program pursuant to the Affordable Care Act of 2010. In 2013, the Program was no longer accepting applications for reimbursement. | ||||||||||||||||||||
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: | ||||||||||||||||||||
Other | ||||||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Other current liabilities | $ | 12 | $ | 15 | $ | 23 | $ | 23 | ||||||||||||
Pension obligations | 1,876 | 3,428 | 0 | 0 | ||||||||||||||||
Non-pension postretirement benefit obligations | 0 | 0 | 2,190 | 2,662 | ||||||||||||||||
Unfunded status (net benefit obligation less | ||||||||||||||||||||
net plan assets) | $ | 1,888 | $ | 3,443 | $ | 2,213 | $ | 2,685 | ||||||||||||
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets. | ||||||||||||||||||||
The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets. | ||||||||||||||||||||
PBO in excess of plan assets | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Projected benefit obligation | $ | 15,452 | $ | 16,800 | ||||||||||||||||
Fair value of net plan assets | 13,564 | 13,357 | ||||||||||||||||||
ABO in excess of plan assets | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Projected benefit obligation | $ | 15,452 | $ | 16,796 | ||||||||||||||||
Accumulated benefit obligation | 14,552 | 15,657 | ||||||||||||||||||
Fair value of net plan assets | 13,564 | 13,353 | ||||||||||||||||||
On a PBO basis, the plans were funded at 88% at December 31, 2013 compared to 80% at December 31, 2012. On an ABO basis, the plans were funded at 93% at December 31, 2013 compared to 85% at December 31, 2012. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels. | ||||||||||||||||||||
Components of Net Periodic Benefit Costs | ||||||||||||||||||||
The following table presents the components of Exelon's net periodic benefit costs for the years ended December 31, 2013, 2012 and 2011. The table reflects an increase in 2012 and a reduction in 2011 of net periodic postretirement benefit costs of approximately $(17) million and $28 million, respectively, related to a Federal subsidy provided under the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Modernization Act), discussed further below. | ||||||||||||||||||||
The 2013 pension benefit cost for all plans is calculated using an expected long-term rate of return on plan assets of 7.50% and a discount rate of 3.92%. Certain plans were remeasured during the year using a discount rate of 4.21%. The 2013 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.45% for funded plans and a discount rate of 4.00% for all plans. Certain plans were remeasured during the year using a discount rate of 4.66%. Certain other postretirement benefit plans are not funded. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets. | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Components of net periodic benefit | ||||||||||||||||||||
cost: | ||||||||||||||||||||
Service cost | $ | 317 | $ | 280 | $ | 212 | $ | 162 | $ | 156 | $ | 142 | ||||||||
Interest cost | 650 | 698 | 649 | 194 | 205 | 207 | ||||||||||||||
Expected return on assets | -1,015 | -988 | -939 | -132 | -115 | -111 | ||||||||||||||
Amortization of: | ||||||||||||||||||||
Transition obligation | 0 | 0 | 0 | 0 | 11 | 9 | ||||||||||||||
Prior service cost (credit) | 14 | 15 | 14 | -19 | -17 | -38 | ||||||||||||||
Actuarial loss | 562 | 450 | 331 | 83 | 81 | 66 | ||||||||||||||
Curtailment benefits | 0 | 0 | 0 | 0 | -7 | 0 | ||||||||||||||
Settlement charges | 9 | 31 | 0 | 0 | 0 | 0 | ||||||||||||||
Contractual termination benefits (a) | 0 | 14 | 0 | 0 | 6 | 0 | ||||||||||||||
Net periodic benefit cost | $ | 537 | $ | 500 | $ | 267 | $ | 288 | $ | 320 | $ | 275 | ||||||||
ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012. | ||||||||||||||||||||
Through Exelon's postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Medicare Modernization Act, enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Management believes the prescription drug benefit provided under Exelon's postretirement benefit plans meets the requirements for the subsidy. In December 2011, the Company decided that beginning in 2013, it will no longer elect to take the direct Part D subsidy. Beginning in 2013, eligible employees are offered an Employee Group Waiver Plan, a Medicare Part D Plan, with a supplemental “wrap” that closely matches the current prescription drug plan design. See the Health Care Reform Legislation section below for further discussion regarding the income tax treatment of Federal subsidies of prescription drug benefits. | ||||||||||||||||||||
The effect of the subsidy on the components of net periodic postretirement benefit cost for the years ended December 31, 2013, 2012 and 2011 included in the consolidated financial statements was as follows: | ||||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
Amortization of the actuarial experience loss | $ | 0 | $ | -17 | $ | 3 | ||||||||||||||
Reduction in current period service cost | 0 | 0 | 9 | |||||||||||||||||
Reduction in interest cost on the APBO | 0 | 0 | 16 | |||||||||||||||||
Total effect of subsidy on net periodic postretirement benefit cost | $ | 0 | $ | -17 | $ | 28 | ||||||||||||||
Components of AOCI and Regulatory Assets | ||||||||||||||||||||
Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon's Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2013, 2012 and 2011 for all plans combined. | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Changes in plan assets and benefit | ||||||||||||||||||||
obligations recognized in AOCI | ||||||||||||||||||||
and regulatory assets (liabilities): | ||||||||||||||||||||
Current year actuarial (gain) loss | $ | -1,169 | $ | 1,693 | $ | 744 | $ | -628 | $ | 304 | $ | 74 | ||||||||
Amortization of actuarial gain (loss) | -562 | -450 | -331 | -83 | -81 | -66 | ||||||||||||||
Current year prior service (credit) cost | 0 | 1 | 0 | 15 | -109 | 0 | ||||||||||||||
Amortization of prior service (cost) | ||||||||||||||||||||
credit | -14 | -15 | -14 | 19 | 17 | 38 | ||||||||||||||
Current year transition (asset) obligation | 0 | 0 | 0 | 0 | 1 | 0 | ||||||||||||||
Amortization of transition asset | ||||||||||||||||||||
(obligation) | 0 | 0 | 0 | 0 | -11 | -9 | ||||||||||||||
Curtailments | 0 | -10 | 0 | 0 | -1 | 0 | ||||||||||||||
Settlements | -8 | -31 | 0 | 0 | 0 | 0 | ||||||||||||||
Total recognized in AOCI and | ||||||||||||||||||||
regulatory assets (liabilities)(a) | $ | -1,753 | $ | 1,188 | $ | 399 | $ | -677 | $ | 120 | $ | 37 | ||||||||
________________ | ||||||||||||||||||||
(a) Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million loss related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million loss related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. | ||||||||||||||||||||
The following table provides the components of Exelon's gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 2013 and 2012, respectively, for all plans combined: | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Prior service cost (credit) | $ | 62 | $ | 76 | $ | -73 | $ | -107 | ||||||||||||
Actuarial loss | 6,192 | 7,931 | 474 | 1,185 | ||||||||||||||||
Total(a) | $ | 6,254 | $ | 8,007 | $ | 401 | $ | 1,078 | ||||||||||||
(a) Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013. Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. | ||||||||||||||||||||
The following table provides the components of Exelon's AOCI and regulatory assets at December 31, 2013 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2014. These estimates are subject to the completion of an actuarial valuation of Exelon's pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2014 and actual claims activity as of December 31, 2013. The valuation is expected to be completed in the first quarter of 2014 for legacy Exelon plans and in the second quarter of 2014 for legacy Constellation plans. | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
Prior service cost (credit) | $ | 14 | $ | -16 | ||||||||||||||||
Actuarial loss | 427 | 32 | ||||||||||||||||||
Total(a) | $ | 441 | $ | 16 | ||||||||||||||||
(a) Of the $441 million related to pension benefits at December 31, 2013, $232 million and $209 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $16 million related to other postretirement benefits at December 31, 2013, $7 million and $9 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. | ||||||||||||||||||||
Assumptions | ||||||||||||||||||||
The measurement of the plan obligations and costs of providing benefits under Exelon's defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, Exelon's expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors. | ||||||||||||||||||||
Expected Rate of Return. In selecting the expected rate of return on plan assets, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon's target asset class allocations. | ||||||||||||||||||||
The following assumptions were used to determine the benefit obligations for all of the plans at December 31, 2013, 2012 and 2011. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year's net periodic benefit costs. | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Discount rate | 4.80% | 3.92% | 4.74% | 4.90% | 4.00% | 4.80% | ||||||||||||||
Rate of compensation increase | (a) | (b) | 3.75% | (a) | (b) | 3.75% | ||||||||||||||
Mortality table | IRS required mortality table for 2014 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2014 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | ||||||||||||||
Health care cost trend on covered charges | N/A | N/A | N/A | 6.00% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | ||||||||||||||
3.25% for 2014-2018 and 3.75% thereafter. | ||||||||||||||||||||
3.25% for 2013-2017 and 3.75% thereafter. | ||||||||||||||||||||
The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2013, 2012 and 2011: | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Discount rate | 3.92% (a) | 4.74% (b) | 5.26% | 4.00% (a) | 4.80% (b) | 5.30% | ||||||||||||||
Expected return on plan assets | 7.50% (c) | 7.50% (c) | 8.00% (c) | 6.45% (c) | 6.68% (c) | 7.08% (c) | ||||||||||||||
Rate of compensation increase | (d) | 3.75% | 3.75% | (d) | 3.75% | 3.75% | ||||||||||||||
Mortality table | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2011 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2011 funding valuation | ||||||||||||||
Health care cost trend on covered charges | N/A | N/A | N/A | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 7.00% decreasing to ultimate trend of 5.00% in 2015 | ||||||||||||||
(a) The discount rates above represent the initial discount rates used to establish Exelon's pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurements. | ||||||||||||||||||||
(b) The discount rates above represent the initial discounts rates used to establish Exelon's pension and other postretirement benefits costs for 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements. | ||||||||||||||||||||
(c) Not applicable to pension and other postretirement benefit plans that do not have plan assets. | ||||||||||||||||||||
(d) 3.25% for 2013-2017 and 3.75% thereafter. | ||||||||||||||||||||
Assumed health care cost trend rates have a significant effect on the costs reported for the other postretirement benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects: | ||||||||||||||||||||
Effect of a one percentage point increase in assumed health care cost trend: | ||||||||||||||||||||
on 2013 total service and interest cost components | $ | 90 | ||||||||||||||||||
on postretirement benefit obligation at December 31, 2013 | 858 | |||||||||||||||||||
Effect of a one percentage point decrease in assumed health care cost trend: | ||||||||||||||||||||
on 2013 total service and interest cost components | -62 | |||||||||||||||||||
on postretirement benefit obligation at December 31, 2013 | -607 | |||||||||||||||||||
Health Care Reform Legislation | ||||||||||||||||||||
In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers. One such provision reduces the deductibility, for Federal income tax purposes, of retiree health care costs to the extent an employer's postretirement health care plan receives Federal subsidies that provide retiree prescription drug benefits at least equivalent to those offered by Medicare. Although this change did not take effect immediately, the Registrants were required to recognize the full accounting impact in their financial statements in the period in which the legislation was enacted. As a result, in the first quarter of 2010, Exelon recorded total after-tax charges of approximately $65 million to income tax expense to reverse deferred tax assets previously established. Generation, ComEd, PECO and BGE recorded charges of $24 million, $11 million, $9 million and $3 million, respectively. Additionally, as a result of this deductibility change for employers and other Health Care Reform provisions that impact the federal prescription drug subsidy options provided to employers, Exelon has made a change in the manner in which it will receive prescription drug subsidies beginning in 2013. | ||||||||||||||||||||
Additionally, the Health Care Reform Acts also include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of the excise tax on Exelon's other postretirement benefit obligation, including projected inflation rates (based on the CPI) and whether pre- and post-65 retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expected impact in its annual actuarial valuation. | ||||||||||||||||||||
Contributions | ||||||||||||||||||||
The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans: | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 (c) | 2013 (a) | 2012 (a) | 2011 (a) | |||||||||||||||
Generation | $ | 119 | $ | 48 | $ | 954 | $ | 30 | $ | 135 | $ | 121 | ||||||||
ComEd | 118 | 25 | 873 | 4 | 119 | 108 | ||||||||||||||
PECO | 11 | 13 | 110 | 20 | 33 | 28 | ||||||||||||||
BGE (b) | 0 | 0 | 0 | 24 | 12 | 0 | ||||||||||||||
BSC | 91 | 63 | 157 | 5 | 24 | 20 | ||||||||||||||
Exelon | $ | 339 | $ | 149 | $ | 2,094 | $ | 83 | $ | 323 | $ | 277 | ||||||||
(a) The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, and $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011. Effective January 1, 2013, Exelon is no longer receiving this subsidy. | ||||||||||||||||||||
(b) BGE's pension benefit contributions for 2012 and 2011 exclude $0 million and $54 million, respectively, of pension contributions made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's other postretirement benefit payments for 2012 and 2011 exclude $4 million and $13 million, respectively, of other postretirement benefit payments made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. These pre-merger contributions are not included in Exelon's financial statements but are reflected in BGE's financial statements. | ||||||||||||||||||||
(c) The increase in 2011 pension contributions was related to Exelon's $2.1 billion contribution to its pension plans as a result of accelerated cash benefits associated with the Tax Relief Act of 2010. | ||||||||||||||||||||
Exelon plans to contribute $264 million to its qualified pension plans in 2014, of which Generation, ComEd, PECO and BGE will contribute $118 million, $119 million, $11 million and $0 million, respectively. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded. Exelon plans to make non-qualified pension plan benefit payments of $12 million in 2014, of which Generation, ComEd, PECO and BGE will make payments of $5 million, $1 million, $0 million and $1 million, respectively. Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Additionally, for Exelon's largest qualified pension plan, the projected contributions reflect a funding strategy of contributing the greater of $250 million, which approximates service cost, or the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower minimum pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law were applied in 2012 while others were applied in 2013. The estimated impacts of the law are reflected in the projected pension contributions. | ||||||||||||||||||||
Unlike the qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. Exelon's management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). In 2014, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $430 million in 2014, of which Generation, ComEd, PECO, and BGE expect to contribute $168 million, $197 million, $19 million, and $17 million, respectively. | ||||||||||||||||||||
Estimated Future Benefit Payments | ||||||||||||||||||||
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2013 were: | ||||||||||||||||||||
Other Postretirement | ||||||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||||||
2014 | $ | 929 | $ | 204 | ||||||||||||||||
2015 | 851 | 210 | ||||||||||||||||||
2016 | 873 | 219 | ||||||||||||||||||
2017 | 902 | 228 | ||||||||||||||||||
2018 | 1,015 | 238 | ||||||||||||||||||
2019 through 2023 | 5,257 | 1,383 | ||||||||||||||||||
Total estimated future benefit payments through 2023 | $ | 9,827 | $ | 2,482 | ||||||||||||||||
Allocation to Exelon Subsidiaries | ||||||||||||||||||||
Generation, ComEd, PECO, and BGE account for their participation in Exelon's pension and other postretirement benefit plans by applying multiemployer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon's corporate restructuring. Exelon allocates the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each participating unit. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Pension and postretirement benefit contributions are allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. For legacy CEG plans, components of pension and other postretirement benefit costs and contributions are allocated to the subsidiaries based on employee participation (both active and retired). | ||||||||||||||||||||
The amounts below were included in capital expenditures and operating and maintenance expense for the years ended December 31, 2013, 2012 and 2011, respectively, for Generation's, ComEd's, PECO's, BSC's and BGE's allocated portion of the pension and postretirement benefit plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges: | ||||||||||||||||||||
For the Year Ended December 31, | Generation | ComEd | PECO | BSC (a) | BGE (b)(c) | Exelon | ||||||||||||||
2013 | $ | 347 | $ | 309 | $ | 43 | $ | 71 | $ | 55 | $ | 825 | ||||||||
2012 | 341 | 282 | 50 | 99 | 60 | 820 | ||||||||||||||
2011 | 249 | 213 | 32 | 48 | 51 | 542 | ||||||||||||||
___________________ | ||||||||||||||||||||
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||||||||
The amounts included in capital and operating and maintenance expense for the years ended December 31, 2012 and 2011 include $12 million and $51 million, respectively, in costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's capital expenditures and operating and maintenance expense for the years ended December 31, 2012 and 2011. | ||||||||||||||||||||
BGE's pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012. | ||||||||||||||||||||
Plan Assets | ||||||||||||||||||||
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy. | ||||||||||||||||||||
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon's other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility. | ||||||||||||||||||||
Exelon used an EROA of 7.00% and 6.59% to estimate its 2014 pension and other postretirement benefit costs, respectively. | ||||||||||||||||||||
Exelon's pension and other postretirement benefit plan target asset allocations and December 31, 2013 and 2012 asset allocations were as follows: | ||||||||||||||||||||
Pension Plans | Percentage of Plan Assets | |||||||||||||||||||
at December 31, | ||||||||||||||||||||
Asset Category | Target Allocation | 2013 | 2012 | |||||||||||||||||
Equity securities | 31 | % | 35 | % | 35 | % | ||||||||||||||
Fixed income securities | 38 | % | 37 | 40 | ||||||||||||||||
Alternative investments (a) | 31 | % | 28 | 25 | ||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||
Other Postretirement Benefit Plans | Percentage of Plan Assets | |||||||||||||||||||
at December 31, | ||||||||||||||||||||
Asset Category | Target Allocation | 2013 | 2012 | |||||||||||||||||
Equity securities | 41 | % | 45 | % | 46 | % | ||||||||||||||
Fixed income securities | 39 | % | 37 | 40 | ||||||||||||||||
Alternative investments (a) | 20 | % | 18 | 14 | ||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||
(a) Alternative investments include private equity, hedge funds and real estate. | ||||||||||||||||||||
Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans' asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2013. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2013, there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Exelon's pension and other postretirement benefit plan assets. | ||||||||||||||||||||
Fair Value Measurements | ||||||||||||||||||||
The following table presents Exelon's pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2013 and 2012: | ||||||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Pension plan assets | ||||||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 3,090 | 0 | 2 | 3,092 | ||||||||||||||||
Commingled funds | 0 | 1,167 | 0 | 1,167 | ||||||||||||||||
Mutual funds | 270 | 0 | 0 | 270 | ||||||||||||||||
Equity securities subtotal | 3,360 | 1,167 | 2 | 4,529 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 908 | 9 | 0 | 917 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 88 | 0 | 88 | ||||||||||||||||
Foreign debt securities | 0 | 205 | 0 | 205 | ||||||||||||||||
Corporate debt securities | 0 | 2,927 | 41 | 2,968 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 90 | 0 | 90 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 26 | 0 | 26 | ||||||||||||||||
Commingled funds | 0 | 558 | 0 | 558 | ||||||||||||||||
Mutual funds | 5 | 315 | 0 | 320 | ||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||
Assets | 0 | 7 | 0 | 7 | ||||||||||||||||
Liabilities | 0 | -134 | 0 | -134 | ||||||||||||||||
Fixed income securities subtotal | 913 | 4,091 | 41 | 5,045 | ||||||||||||||||
Private equity | 0 | 0 | 806 | 806 | ||||||||||||||||
Hedge funds | 0 | 1,266 | 1,039 | 2,305 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 264 | 0 | 0 | 264 | ||||||||||||||||
Commingled funds | 0 | 2 | 0 | 2 | ||||||||||||||||
Real estate funds | 0 | 0 | 582 | 582 | ||||||||||||||||
Real estate subtotal | 264 | 2 | 582 | 848 | ||||||||||||||||
Pension plan assets subtotal | 4,537 | 6,526 | 2,470 | 13,533 | ||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||
Cash equivalents | 51 | 0 | 0 | 51 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 286 | 0 | 0 | 286 | ||||||||||||||||
Commingled funds | 0 | 515 | 0 | 515 | ||||||||||||||||
Mutual funds | 164 | 0 | 0 | 164 | ||||||||||||||||
Equity securities subtotal | 450 | 515 | 0 | 965 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 17 | 1 | 0 | 18 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 149 | 0 | 149 | ||||||||||||||||
Foreign debt securities | 0 | 2 | 0 | 2 | ||||||||||||||||
Corporate debt securities | 0 | 50 | 0 | 50 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 45 | 0 | 45 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | ||||||||||||||||
Commingled funds | 0 | 218 | 0 | 218 | ||||||||||||||||
Mutual funds | 305 | 0 | 0 | 305 | ||||||||||||||||
Fixed income securities subtotal | 322 | 472 | 0 | 794 | ||||||||||||||||
Private equity | 0 | 0 | 2 | 2 | ||||||||||||||||
Hedge funds | 0 | 295 | 4 | 299 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 8 | 0 | 0 | 8 | ||||||||||||||||
Real estate funds | 0 | 5 | 109 | 114 | ||||||||||||||||
Real estate subtotal | 8 | 5 | 109 | 122 | ||||||||||||||||
Other postretirement benefit plan assets subtotal | 831 | 1,287 | 115 | 2,233 | ||||||||||||||||
Total pension and other postretirement | ||||||||||||||||||||
benefit plan assets (c) | $ | 5,368 | $ | 7,813 | $ | 2,585 | $ | 15,766 | ||||||||||||
At December 31, 2012 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Pension plan assets | ||||||||||||||||||||
Cash equivalents | $ | 1 | $ | 0 | $ | 0 | $ | 1 | ||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 2,562 | 0 | 0 | 2,562 | ||||||||||||||||
Commingled funds | 0 | 1,111 | 0 | 1,111 | ||||||||||||||||
Mutual funds | 323 | 0 | 0 | 323 | ||||||||||||||||
Equity securities subtotal | 2,885 | 1,111 | 0 | 3,996 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 1,037 | 0 | 0 | 1,037 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 108 | 0 | 108 | ||||||||||||||||
Foreign debt securities | 0 | 252 | 0 | 252 | ||||||||||||||||
Corporate debt securities | 0 | 3,330 | 0 | 3,330 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 117 | 0 | 117 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 28 | 0 | 28 | ||||||||||||||||
Commingled funds | 0 | 274 | 0 | 274 | ||||||||||||||||
Mutual funds | 4 | 291 | 0 | 295 | ||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||
Assets | 0 | 9 | 0 | 9 | ||||||||||||||||
Liabilities | 0 | -21 | 0 | -21 | ||||||||||||||||
Fixed income securities subtotal | 1,041 | 4,388 | 0 | 5,429 | ||||||||||||||||
Private equity | 0 | 0 | 754 | 754 | ||||||||||||||||
Hedge funds | 0 | 1,080 | 1,235 | 2,315 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 280 | 0 | 0 | 280 | ||||||||||||||||
Commingled funds | 0 | 75 | 0 | 75 | ||||||||||||||||
Real estate funds | 0 | 0 | 426 | 426 | ||||||||||||||||
Real estate subtotal | 280 | 75 | 426 | 781 | ||||||||||||||||
Pension plan assets subtotal | 4,207 | 6,654 | 2,415 | 13,276 | ||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||
Cash equivalents | 44 | 0 | 0 | 44 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 198 | 0 | 0 | 198 | ||||||||||||||||
Commingled funds | 0 | 530 | 0 | 530 | ||||||||||||||||
Mutual funds | 230 | 0 | 0 | 230 | ||||||||||||||||
Equity securities subtotal | 428 | 530 | 0 | 958 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 18 | 0 | 0 | 18 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 125 | 0 | 125 | ||||||||||||||||
Foreign debt securities | 0 | 3 | 0 | 3 | ||||||||||||||||
Corporate debt securities | 0 | 50 | 0 | 50 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 52 | 0 | 52 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 6 | 0 | 6 | ||||||||||||||||
Commingled funds | 0 | 271 | 0 | 271 | ||||||||||||||||
Mutual funds | 295 | 2 | 0 | 297 | ||||||||||||||||
Fixed income securities subtotal | 313 | 509 | 0 | 822 | ||||||||||||||||
Private equity | 0 | 0 | 1 | 1 | ||||||||||||||||
Hedge funds | 0 | 188 | 12 | 200 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 7 | 0 | 0 | 7 | ||||||||||||||||
Commingled funds | 0 | 2 | 0 | 2 | ||||||||||||||||
Real estate funds | 0 | 6 | 95 | 101 | ||||||||||||||||
Real estate subtotal | 7 | 8 | 95 | 110 | ||||||||||||||||
Other postretirement benefit plan assets subtotal | 792 | 1,235 | 108 | 2,135 | ||||||||||||||||
Total pension and other postretirement | ||||||||||||||||||||
benefit plan assets (c) | $ | 4,999 | $ | 7,889 | $ | 2,523 | $ | 15,411 | ||||||||||||
See Note 11 - Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy. | ||||||||||||||||||||
Derivative instruments have a total notional amount of $2,651 million and $2,498 million at December 31, 2013 and 2012, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss. | ||||||||||||||||||||
Excludes net assets of $43 million and $81 million at December 31, 2013 and 2012, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases. | ||||||||||||||||||||
The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2013 and 2012: | ||||||||||||||||||||
Hedge | Private | Real | Debt | Preferred | ||||||||||||||||
funds | equity | estate | securities | stock | Total | |||||||||||||||
Pension Assets | ||||||||||||||||||||
Balance as of January 1, 2013 | $ | 1,235 | $ | 754 | $ | 426 | $ | 0 | $ | 0 | $ | 2,415 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 143 | 86 | 63 | 0 | 0 | 292 | ||||||||||||||
Relating to assets sold during the period | 3 | 0 | -4 | 0 | 0 | -1 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 360 | 123 | 226 | 41 | 2 | 752 | ||||||||||||||
Sales | -76 | 0 | -91 | 0 | 0 | -167 | ||||||||||||||
Settlements(a) | -3 | -157 | -38 | 0 | 0 | -198 | ||||||||||||||
Transfers into (out of) Level 3(b) | -623 | 0 | 0 | 0 | 0 | -623 | ||||||||||||||
Balance as of December 31, 2013 | $ | 1,039 | $ | 806 | $ | 582 | $ | 41 | $ | 2 | $ | 2,470 | ||||||||
Other Postretirement Benefits | ||||||||||||||||||||
Balance as of January 1, 2013 | $ | 12 | $ | 1 | $ | 95 | $ | 0 | $ | 0 | $ | 108 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 1 | 0 | 11 | 0 | 0 | 12 | ||||||||||||||
Relating to assets sold during the period | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 0 | 1 | 3 | 0 | 0 | 4 | ||||||||||||||
Sales | -1 | 0 | 0 | 0 | 0 | -1 | ||||||||||||||
Settlements(a) | -4 | 0 | 0 | 0 | 0 | -4 | ||||||||||||||
Transfers into (out of) Level 3(b) | -4 | 0 | 0 | 0 | 0 | -4 | ||||||||||||||
Balance as of December 31, 2013 | $ | 4 | $ | 2 | $ | 109 | $ | 0 | $ | 0 | $ | 115 | ||||||||
Hedge | Private | Real | Debt | Preferred | ||||||||||||||||
funds | equity | estate | securities | stock | Total | |||||||||||||||
Pension Assets | ||||||||||||||||||||
Balance as of January 1, 2012 | $ | 1,525 | $ | 672 | $ | 229 | $ | 0 | $ | 0 | $ | 2,426 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 138 | 55 | 24 | 0 | 0 | 217 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 447 | 108 | 134 | 0 | 0 | 689 | ||||||||||||||
Sales | -6 | 0 | 0 | 0 | 0 | -6 | ||||||||||||||
Settlements(a) | -4 | -128 | -28 | 0 | 0 | -160 | ||||||||||||||
Transfers into (out of) Level 3(c)(d)(e) | -865 | 47 | 67 | 0 | 0 | -751 | ||||||||||||||
Balance as of December 31, 2012 | $ | 1,235 | $ | 754 | $ | 426 | $ | 0 | $ | 0 | $ | 2,415 | ||||||||
Other Postretirement Benefits | ||||||||||||||||||||
Balance as of January 1, 2012 | $ | 157 | $ | 1 | $ | 7 | $ | 0 | $ | 0 | $ | 165 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 11 | 0 | 3 | 0 | 0 | 14 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 32 | 0 | 91 | 0 | 0 | 123 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Settlements(a) | 0 | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Transfers into (out of) Level 3(c)(d)(e) | -188 | 0 | -5 | 0 | 0 | -193 | ||||||||||||||
Balance as of December 31, 2012 | $ | 12 | $ | 1 | $ | 95 | $ | 0 | $ | 0 | $ | 108 | ||||||||
Represents cash settlements only. | ||||||||||||||||||||
As of December 31, 2012, hedge fund investments that contained redemption restrictions limiting Exelon's ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $627 million in 2013. | ||||||||||||||||||||
In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's pension plan assets resulting in transfers into Level 3 of $141 million. | ||||||||||||||||||||
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion. | ||||||||||||||||||||
In 2012, the liquidity terms of a certain real estate investment changed to allow redemption within a reasonable period of time from the redemption date which led to a transfer out of Level 3 to Level 2 of $5 million. | ||||||||||||||||||||
Valuation Techniques Used to Determine Fair Value | ||||||||||||||||||||
Cash equivalents. Investments with maturities of three months or less when purchased, including certain short−term fixed income securities and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1. | ||||||||||||||||||||
Equity securities. With respect to individually held equity securities, including investments in U.S. and international securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually are primarily traded on exchanges that contain only actively traded securities, due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs. | ||||||||||||||||||||
Equity commingled funds and mutual funds are maintained by investment companies that hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. | ||||||||||||||||||||
Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross−provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market−based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly−liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The fair values of fixed income securities, excluding U.S. Treasury securities and privately placed fixed income securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. | ||||||||||||||||||||
Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2. | ||||||||||||||||||||
Fixed income commingled funds and mutual funds, including short−term investment funds, are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. | ||||||||||||||||||||
Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3. | ||||||||||||||||||||
Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or ownership interest of the investments. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock−up period or a gate. For Exelon's investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedge fund investments are categorized as Level 2. For investments that have restrictions that may limit Exelon's ability to redeem the investments at the measurement date or within a reasonable period of time, the hedge fund investments are categorized as Level 3. | ||||||||||||||||||||
Real estate. Real estate investment trusts valued daily based on quoted prices in active markets are categorized as Level 1. Real estate commingled funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon's overall investment strategy. Since these funds are not publicly quoted, the fund administrators value the funds using the net asset value per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Other real estate funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, these real estate funds have been categorized as Level 3. | ||||||||||||||||||||
Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2013, 2012 and 2011: | ||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | PECO | BGE (a) | BSC (b) | ||||||||||||||
2013 | $ | 85 | $ | 40 | $ | 22 | $ | 8 | $ | 8 | $ | 7 | ||||||||
2012 | 67 | 30 | 19 | 7 | 7 | 5 | ||||||||||||||
2011 | 78 | 40 | 22 | 9 | 7 | 7 | ||||||||||||||
_______________________ | ||||||||||||||||||||
BGE's matching contributions for the years ended December 31, 2012 and 2011 include $1 million and $7 million of costs, respectively, incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These costs are not included in Exelon's matching contributions for the years ended December 31, 2012 and 2011. | ||||||||||||||||||||
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, or BGE amounts above. | ||||||||||||||||||||
Severance_And_Plants_Retiremen
Severance And Plants Retirements (exelon and Generation) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Restructuring Charges [Abstract] | ' | ||||||||||||||||
Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO) | ' | ||||||||||||||||
17. Severance (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||
The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period. | |||||||||||||||||
Merger-Related Severance | |||||||||||||||||
Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. In addition, certain employees identified during the staffing and selection process also receive pension and other postretirement benefits that are deemed contractual termination benefits, which the Registrants recorded during the second quarter of 2012. | |||||||||||||||||
The amount of severance expense associated with the post-merger integration recognized for the year ended December 31, 2013 for Exelon and Generation was $6 million and $6 million, respectively. For Generation, $5 million represents amounts billed by BSC through intercompany allocations. There was no severance expense associated with post-merger integration recognized for the year ended December 31, 2013 for ComEd, PECO and BGE. Estimated costs to be incurred after December 31, 2013 are not material. | |||||||||||||||||
For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with the identified job reductions within operating and maintenance expense in their Consolidated Statements of Operations, except for those costs that were capitalized as regulatory assets related to ComEd and BGE: | |||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Severance Benefits (a) | Exelon (b) | Generation | ComEd (b) | PECO | BGE (b) | ||||||||||||
Severance charges | $ | 124 | $ | 80 | $ | 14 | $ | 7 | $ | 17 | |||||||
Stock compensation | 7 | 4 | 1 | 0 | 1 | ||||||||||||
Other charges | 7 | 4 | 1 | 0 | 1 | ||||||||||||
Total severance benefits | $ | 138 | $ | 88 | $ | 16 | $ | 7 | $ | 19 | |||||||
_________________ | |||||||||||||||||
The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012. | |||||||||||||||||
Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||
Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations: | |||||||||||||||||
Severance liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Balance at December 31, 2011 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||
Severance charges (a) | 124 | 38 | 2 | 0 | 11 | ||||||||||||
Stock compensation | 7 | 2 | 0 | 0 | 0 | ||||||||||||
Other charges (b) | 7 | 2 | 0 | 0 | 1 | ||||||||||||
Payments | -27 | -9 | -1 | 0 | -1 | ||||||||||||
Balance at December 31, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | 0 | $ | 11 | |||||||
Severance charges | 5 | 1 | 0 | 0 | 0 | ||||||||||||
Stock compensation | 1 | 0 | 0 | 0 | 0 | ||||||||||||
Payments | -64 | -24 | -1 | 0 | -5 | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | 0 | $ | 0 | $ | 6 | |||||||
_____________________ | |||||||||||||||||
(a) Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon's ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2012 and December 31, 2013. | |||||||||||||||||
(b) Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services. | |||||||||||||||||
Cash payments under the plan began in the second quarter of 2012. Substantially all cash payments under the plan are expected to be made by the end of 2016. | |||||||||||||||||
Ongoing Severance Plans | |||||||||||||||||
The Registrants provide severance and health and welfare benefits under Exelon's ongoing severance benefit plans to terminated employees in the normal course of business, which were not directly related to the merger with Constellation. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated. | |||||||||||||||||
For the years ended December 31, 2013, 2012, and 2011, the Registrants recorded the following severance costs associated with these ongoing severance benefits within operating and maintenance expense in their Consolidated Statements of Operations: | |||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Severance charges - 2013 | $ | 18 | $ | 16 | $ | 2 | $ | 0 | $ | 0 | |||||||
Severance charges - 2012 | 19 | 14 | 2 | 1 | 3 | ||||||||||||
Severance charges - 2011 | 5 | 5 | 0 | 0 | 4 | ||||||||||||
_______________ | |||||||||||||||||
The amounts above for Generation include $2 million, $0 million, and $1 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2013, 2012, and 2011, respectively. Amounts billed by BSC to ComEd, PECO, and BGE were not material. | |||||||||||||||||
The severance liability balances associated with these ongoing severance benefits as of December 31, 2013 and 2012 are not material. |
StockBased_Compensation_Plans_
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Stock-Based Compensation Plans [Line Items] | ' | ||||||||||
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
ComEd had 73,709 and 74,182 warrants outstanding to purchase ComEd common stock at December 31, 2013 and 2012, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2013 and 2012, 24,570 and 24,727 shares of common stock, respectively, were reserved for the conversion of warrants. | |||||||||||
Share Repurchases | |||||||||||
Share Repurchase Programs. In April 2004, Exelon's Board of Directors approved a discretionary share repurchase program that allowed Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program was intended to mitigate, in part, the dilutive effect of shares issued under Exelon's employee stock option plan and Exelon's ESPP. The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon's ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The 2004 share repurchase program had no specified limit on the number of shares that could be repurchased and no specified termination date. In 2008, Exelon management decided to defer indefinitely any share repurchases. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon's management. Under the share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2013. During 2013, 2012 and 2011, Exelon had no common stock repurchases. | |||||||||||
Stock-Based Compensation Plans | |||||||||||
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2013, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2013, 2012 and 2011, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares. | |||||||||||
The Compensation Committee of Exelon's Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminating stock options in favor of the use of full value shares, consisting of performance shares and restricted stock. The performance share awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 and earlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting from the transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of performance share transition awards in 2013, which will vest one-third after one year, with the remaining balance vesting over a two-year performance period. | |||||||||||
The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Components of Stock-Based Compensation Expense | 2013 | 2012 | 2011 | ||||||||
Performance share awards | $ | 48 | $ | 46 | $ | 26 | |||||
Restricted stock units | 61 | 50 | 31 | ||||||||
Stock options | 3 | 15 | 8 | ||||||||
Other stock-based awards | 6 | 4 | 4 | ||||||||
Total stock-based compensation expense included in | |||||||||||
operating and maintenance expense | 118 | 115 | 69 | ||||||||
Income tax benefit | -44 | -44 | -27 | ||||||||
Total after-tax stock-based compensation expense | $ | 74 | $ | 71 | $ | 42 | |||||
The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Subsidiaries | 2013 | 2012 | 2011 (d) | ||||||||
Generation | $ | 48 | $ | 42 | $ | 31 | |||||
ComEd | 9 | 11 | 5 | ||||||||
PECO | 5 | 5 | 5 | ||||||||
BGE (a) | 6 | 5 | 6 | ||||||||
BSC (b) | 50 | 52 | 28 | ||||||||
Total (c) | $ | 118 | $ | 115 | $ | 69 | |||||
(a) BGE's stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the year ended December 31, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | |||||||||||
(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. | |||||||||||
(c) The stock-based compensation expense (pre-tax) for December 31, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd does not reflect the impact of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | |||||||||||
(d) The total stock-based compensation expense (pre-tax) for December 31, 2011 of $69 million does not include the $6 million expense for BGE as those costs were incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. | |||||||||||
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2013, 2012 and 2011. | |||||||||||
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon's Consolidated Statements of Cash Flows. The following table presents information regarding Exelon's tax benefits for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Realized tax benefit when exercised/distributed: | |||||||||||
Stock options | $ | 0 | $ | 3 | $ | 2 | |||||
Restricted stock units | 11 | 11 | 8 | ||||||||
Performance share awards | 11 | 7 | 7 | ||||||||
Stock deferral plan | 1 | 0 | 1 | ||||||||
Excess tax benefits included in other financing activities of Exelon’s | |||||||||||
Consolidated Statements of Cash Flows: | |||||||||||
Stock options | $ | 0 | $ | 2 | $ | 1 | |||||
Stock Options | |||||||||||
Non-qualified stock options to purchase shares of Exelon's common stock are granted under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant. | |||||||||||
There were no stock options granted in 2013. The Compensation Committee eliminated stock option grants by changing the mix of long-term incentives for senior vice presidents (SVPs) and higher officers from 75% performance shares and 25% stock options to 67% performance shares and 33% restricted stock units. | |||||||||||
The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. | |||||||||||
Historically, Exelon has granted most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2012 and 2011 were not significant. | |||||||||||
The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the years ended 2012 and 2011: | |||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | ||||||||||
Dividend yield | 5.28 | % | 4.84 | % | |||||||
Expected volatility | 23.2 | % | 24.4 | % | |||||||
Risk-free interest rate | 1.3 | % | 2.65 | % | |||||||
Expected life (years) | 6.25 | 6.25 | |||||||||
Weighted average grant date fair value (per share) | $ | 4.18 | $ | 6.22 | |||||||
The assumptions above relate to Exelon stock options granted during the periods presented and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended 2012. | |||||||||||
The dividend yield is based on several factors, including Exelon's most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon's common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary. | |||||||||||
The following table presents information with respect to stock option activity for the year ended December 31, 2013: | |||||||||||
Weighted | Weighted | ||||||||||
Average | Average | ||||||||||
Exercise | Remaining | ||||||||||
Price | Contractual | Aggregate | |||||||||
(per | Life | Intrinsic | |||||||||
Shares | share) | (years) | Value | ||||||||
Balance of shares outstanding at December 31, 2012 | 21,903,781 | $ | 45.91 | ||||||||
Options reinstated | 751,122 | 38.6 | |||||||||
Options exercised | -670,957 | 28.02 | |||||||||
Options forfeited | -54,743 | 39.36 | |||||||||
Options expired | -893,758 | 49.08 | |||||||||
Balance of shares outstanding at December 31, 2013 | 21,035,445 | $ | 46.07 | 4.72 | $ | 10 | |||||
Exercisable at December 31, 2013 (a) | 20,188,327 | $ | 46.31 | 4.58 | $ | 10 | |||||
(a) Includes stock options issued to retirement eligible employees. | |||||||||||
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Intrinsic value (a) | $ | 4 | $ | 19 | $ | 5 | |||||
Cash received for exercise price | 19 | 47 | 13 | ||||||||
(a) The difference between the market value on the date of exercise and the option exercise price. | |||||||||||
The following table summarizes Exelon's nonvested stock option activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Exercise Price | |||||||||||
Shares | (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,960,665 | $ | 40.56 | ||||||||
Vested | -1,058,804 | 40.89 | |||||||||
Forfeited | -54,743 | 39.36 | |||||||||
Nonvested at December 31, 2013 (a) | 847,118 | $ | 40.22 | ||||||||
(a) Excludes 1,348,913 and 2,647,536 of stock options issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
At December 31, 2013, $2 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.6 years. | |||||||||||
Restricted Stock Units | |||||||||||
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. | |||||||||||
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary. | |||||||||||
The following table summarizes Exelon's nonvested restricted stock unit activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 2,029,161 | $ | 42.12 | ||||||||
Granted | 2,828,187 | 31.06 | |||||||||
Vested | -842,439 | 42.9 | |||||||||
Forfeited | -108,199 | 36.37 | |||||||||
Undistributed vested awards (b) | -520,013 | 32.62 | |||||||||
Nonvested at December 31, 2013 (a) | 3,386,697 | $ | 34.1 | ||||||||
(a) Excludes 931,628 and 686,121 of restricted stock units issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2013, 2012 and 2011 was $31.06, $39.94 and $43.33, respectively. At December 31, 2013 and 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of $77 million and $58 million, respectively, which are included in common stock in Exelon's Consolidated Balance Sheets. For the years ended December 31, 2013, 2012 and 2011, Exelon settled restricted stock units with fair value totaling $28 million, $25 million and $19 million, respectively. At December 31, 2013, $64 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.5 years. | |||||||||||
Performance Share Awards | |||||||||||
Performance share awards are granted under the LTIP. The 2013 and 2012 performance share awards are being settled 50% in common stock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period. | |||||||||||
The one-time 2013 performance share transition awards, which provide an opportunity to earn an award contingent on company performance, will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. One-third of the award vests and is payable after a one-year performance period while the remaining two-thirds vests and is payable after a two-year performance period. | |||||||||||
The payout of the 2013 performance share awards and one-time performance share transition awards are based on the Company's performance against specific operational and financial goals set annually during the respective performance periods. As a result, the 2013 performance share awards have been divided into equal tranches for the purpose of expense recognition as though the respective award were multiple awards; with each tranche representing a corresponding fiscal year. The one-time performance share transition awards have also been divided into multiple tranches for the purpose of expense recognition. One tranche reflects the one-third of the awards that vests and are payable after a one-year period. The two-thirds of the one-time performance share transition awards that are subject to a two-year performance period have also been divided into equal tranches; with each tranche representing a corresponding fiscal year. The grant date for each tranche of the 2013 performance share and one-time performance share transition awards is the date in which the performance goals for that fiscal year are approved and communicated, which typically occurs at the corresponding January Compensation Committee meeting. | |||||||||||
The 2013 performance share awards and one-time performance share transition awards are recorded at fair value at the grant dates for each tranche, with the estimated grant date fair value based on the expected payout of the award, which may range from 50% to 150% of the payout target. The 2013 performance share awards also include a total shareholder return modifier (TSR) that may increase or decrease the award up to 25% and an individual performance modifier (IPM) that can decrease the award by up to 50% or increase the award by up to 10% for SVPs and higher officers or up to 20% for vice presidents. The one-time performance share transition award is not affected by either TSR or the IPM. | |||||||||||
The common stock portion of the performance share and one-time performance share transition awards is considered an equity award being valued based on Exelon's stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon's current stock price. As the value of the common stock and cash portions of the awards are based on Exelon's stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established. | |||||||||||
The 2012 performance share awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock portion is considered an equity award with the 75% payout floor being valued based on Exelon's stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon's current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon's current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established. | |||||||||||
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant. | |||||||||||
The following table summarizes Exelon's nonvested performance share awards activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,312,734 | $ | 40.08 | ||||||||
Granted | 2,629,171 | 31.55 | |||||||||
Vested | -612,624 | 40.13 | |||||||||
Forfeited | -24,451 | 32.17 | |||||||||
Undistributed vested awards (b) | -1,290,640 | 34.28 | |||||||||
Nonvested at December 31, 2013 (a) | 2,014,190 | $ | 32.74 | ||||||||
(a) Excludes 1,411,824 and 204,643 of performance share awards issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2013, 2012 and 2011 was $31.55, $39.71, and $43.52, respectively. During the years ended December 31, 2013, 2012 and 2011, Exelon settled performance shares with a fair value totaling $26 million, $23 million and $22 million, respectively, of which $12 million, $3 million and $10 million was paid in cash, respectively. As of December 31, 2013, $34 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years. | |||||||||||
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled: | |||||||||||
December 31, | |||||||||||
2013 | 2012 | ||||||||||
Current liabilities (a) | $ | 13 | $ | 7 | |||||||
Deferred credits and other liabilities (b) | 24 | 11 | |||||||||
Common stock | 32 | 35 | |||||||||
Total | $ | 69 | $ | 53 | |||||||
(a) Represents the current liability related to performance share awards expected to be settled in cash. | |||||||||||
(b) Represents the long-term liability related to performance share awards expected to be settled in cash. | |||||||||||
Changes_in_Accumulated_Other_C
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | |||||||||||||
Accumulated Other Comprehensive Income Loss [Text Block] | ' | |||||||||||||
21. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO) | ||||||||||||||
The following table presents changes in accumulated other comprehensive income (loss) (AOCI) by component for the year ended December 31, 2013: | ||||||||||||||
Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | |||||||||
Exelon (a) | ||||||||||||||
Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | ||
OCI before reclassifications | 29 | 2 | 669 | -10 | 101 | 791 | ||||||||
Amounts reclassified from AOCI (b) | -277 | 0 | 208 | 0 | 5 | -64 | ||||||||
Net current-period OCI | -248 | 2 | 877 | -10 | 106 | 727 | ||||||||
Ending balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | ||
Generation (a) | ||||||||||||||
Beginning balance | $ | 512 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | $ | 513 | ||
OCI before reclassifications | 15 | 2 | 0 | -10 | 102 | 109 | ||||||||
Amounts reclassified from AOCI (b) | -413 | 0 | 0 | 0 | 5 | -408 | ||||||||
Net current-period OCI | -398 | 2 | 0 | -10 | 107 | -299 | ||||||||
Ending balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | ||
ComEd (a) | ||||||||||||||
PECO (a) | ||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ||
BGE (a) | ||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||
(b) See next table for details about these reclassifications. | ||||||||||||||
ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net Income during the year ended December 31, 2013. The following table presents amounts reclassified out of AOCI to Net Income for Exelon and Generation during the year ended December 31, 2013: | ||||||||||||||
(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||
(b) See next table for details about these reclassifications. | ||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the statement where Net Income is presented | ||||||||||||
Exelon | Generation | |||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||
Energy related hedges | $ | 464 | $ | 683 | Operating revenues | |||||||||
Other cash flow hedges | -3 | 0 | Interest expense | |||||||||||
461 | 683 | Total before tax | ||||||||||||
-184 | -270 | Tax expense | ||||||||||||
$ | 277 | $ | 413 | Net of tax | ||||||||||
Gains and (losses) on available for sale securities | ||||||||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||
Prior service costs | $ | -2 | $ | 0 | (b) | |||||||||
Actuarial losses | -339 | 0 | (b) | |||||||||||
Deferred compensation unit plan | -1 | 0 | (c) | |||||||||||
-342 | 0 | Total before tax | ||||||||||||
134 | 0 | Tax benefit | ||||||||||||
$ | -208 | $ | 0 | Net of tax | ||||||||||
Equity investments | ||||||||||||||
Capital activity | $ | -8 | $ | -8 | Equity in losses of unconsolidated affiliates | |||||||||
-8 | -8 | Total before tax | ||||||||||||
3 | 3 | Tax benefit | ||||||||||||
$ | -5 | $ | -5 | Net of tax | ||||||||||
Total Reclassifications | $ | 64 | $ | 408 | Net of Tax | |||||||||
(a) Amounts in parenthesis represent a decrease in net income. | ||||||||||||||
(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see note 16 for additional details). | ||||||||||||||
(c) Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. | ||||||||||||||
(a) Amounts in parenthesis represent a decrease in net income. | ||||||||||||||
(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see note 16 for additional details). | ||||||||||||||
(c) Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. | ||||||||||||||
Preferred_Securities_Exelon_Co
Preferred Securities (Exelon, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
Preferred Securities [Line Items] | ' | |||||||||||||
Preferred Securities (Exelon, ComEd, PECO and BGE) | ' | |||||||||||||
18. Preferred and Preference Securities (Exelon, ComEd, PECO and BGE) | ||||||||||||||
At December 31, 2013 and 2012, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding. | ||||||||||||||
Preferred and Preference Securities of Subsidiaries | ||||||||||||||
At December 31, 2013 and 2012, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding. | ||||||||||||||
At December 31, 2012, PECO cumulative preferred securities, no par value, consisted of 15,000,000 shares authorized and the outstanding amounts set forth below. Shares of preferred securities have full voting rights, including the right to cumulate votes in the election of directors. On May 1, 2013, PECO redeemed all of its outstanding preferred securities. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series was issued. The redemption premium is treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share for Exelon. | ||||||||||||||
December 31, | ||||||||||||||
Redemption Price (a) | 2012 | 2012 | ||||||||||||
Shares Outstanding | Dollar Amount | |||||||||||||
Series (without mandatory redemption) | ||||||||||||||
$4.68 (Series D) | $ | 104 | 150,000 | $ | 15 | |||||||||
$4.40 (Series C) | 112.5 | 274,720 | 27 | |||||||||||
$4.30 (Series B) | 102 | 150,000 | 15 | |||||||||||
$3.80 (Series A) | 106 | 300,000 | 30 | |||||||||||
Total preferred securities | 874,720 | $ | 87 | |||||||||||
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. | ||||||||||||||
At December 31, 2013 and 2012, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding amounts set forth below. Shares of BGE preference stock have no voting power except for the following: | ||||||||||||||
The preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE's charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and | ||||||||||||||
Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends. | ||||||||||||||
December 31, | ||||||||||||||
Redemption Price (a) | 2013 | 2012 | 2013 | 2012 | ||||||||||
Shares Outstanding | Dollar Amount | |||||||||||||
Series (without mandatory redemption) | ||||||||||||||
7.125%, 1993 Series | $ | 100 | 400,000 | 400,000 | $ | 40 | $ | 40 | ||||||
6.97%, 1993 Series | 100 | 500,000 | 500,000 | 50 | 50 | |||||||||
6.70%, 1993 Series | 100.34 | 400,000 | 400,000 | 40 | 40 | |||||||||
6.99%, 1995 Series | 100.7 | 600,000 | 600,000 | 60 | 60 | |||||||||
Total preference stock | 1,900,000 | 1,900,000 | $ | 190 | $ | 190 | ||||||||
(a) Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends. | ||||||||||||||
Common_Stock_Exelon_Generation
Common Stock (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Common Stock [Line Items] | ' | ||||||||||
Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
ComEd had 73,709 and 74,182 warrants outstanding to purchase ComEd common stock at December 31, 2013 and 2012, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2013 and 2012, 24,570 and 24,727 shares of common stock, respectively, were reserved for the conversion of warrants. | |||||||||||
Share Repurchases | |||||||||||
Share Repurchase Programs. In April 2004, Exelon's Board of Directors approved a discretionary share repurchase program that allowed Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program was intended to mitigate, in part, the dilutive effect of shares issued under Exelon's employee stock option plan and Exelon's ESPP. The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon's ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The 2004 share repurchase program had no specified limit on the number of shares that could be repurchased and no specified termination date. In 2008, Exelon management decided to defer indefinitely any share repurchases. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon's management. Under the share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2013. During 2013, 2012 and 2011, Exelon had no common stock repurchases. | |||||||||||
Stock-Based Compensation Plans | |||||||||||
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2013, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2013, 2012 and 2011, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares. | |||||||||||
The Compensation Committee of Exelon's Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminating stock options in favor of the use of full value shares, consisting of performance shares and restricted stock. The performance share awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 and earlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting from the transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of performance share transition awards in 2013, which will vest one-third after one year, with the remaining balance vesting over a two-year performance period. | |||||||||||
The following table presents the stock-based compensation expense included in Exelon's Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Components of Stock-Based Compensation Expense | 2013 | 2012 | 2011 | ||||||||
Performance share awards | $ | 48 | $ | 46 | $ | 26 | |||||
Restricted stock units | 61 | 50 | 31 | ||||||||
Stock options | 3 | 15 | 8 | ||||||||
Other stock-based awards | 6 | 4 | 4 | ||||||||
Total stock-based compensation expense included in | |||||||||||
operating and maintenance expense | 118 | 115 | 69 | ||||||||
Income tax benefit | -44 | -44 | -27 | ||||||||
Total after-tax stock-based compensation expense | $ | 74 | $ | 71 | $ | 42 | |||||
The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Subsidiaries | 2013 | 2012 | 2011 (d) | ||||||||
Generation | $ | 48 | $ | 42 | $ | 31 | |||||
ComEd | 9 | 11 | 5 | ||||||||
PECO | 5 | 5 | 5 | ||||||||
BGE (a) | 6 | 5 | 6 | ||||||||
BSC (b) | 50 | 52 | 28 | ||||||||
Total (c) | $ | 118 | $ | 115 | $ | 69 | |||||
(a) BGE's stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the year ended December 31, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | |||||||||||
(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. | |||||||||||
(c) The stock-based compensation expense (pre-tax) for December 31, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd does not reflect the impact of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | |||||||||||
(d) The total stock-based compensation expense (pre-tax) for December 31, 2011 of $69 million does not include the $6 million expense for BGE as those costs were incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. | |||||||||||
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2013, 2012 and 2011. | |||||||||||
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon's Consolidated Statements of Cash Flows. The following table presents information regarding Exelon's tax benefits for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Realized tax benefit when exercised/distributed: | |||||||||||
Stock options | $ | 0 | $ | 3 | $ | 2 | |||||
Restricted stock units | 11 | 11 | 8 | ||||||||
Performance share awards | 11 | 7 | 7 | ||||||||
Stock deferral plan | 1 | 0 | 1 | ||||||||
Excess tax benefits included in other financing activities of Exelon’s | |||||||||||
Consolidated Statements of Cash Flows: | |||||||||||
Stock options | $ | 0 | $ | 2 | $ | 1 | |||||
Stock Options | |||||||||||
Non-qualified stock options to purchase shares of Exelon's common stock are granted under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant. | |||||||||||
There were no stock options granted in 2013. The Compensation Committee eliminated stock option grants by changing the mix of long-term incentives for senior vice presidents (SVPs) and higher officers from 75% performance shares and 25% stock options to 67% performance shares and 33% restricted stock units. | |||||||||||
The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. | |||||||||||
Historically, Exelon has granted most of its stock options in the first quarter of each year. Stock options granted during the remaining quarters of 2012 and 2011 were not significant. | |||||||||||
The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the years ended 2012 and 2011: | |||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | ||||||||||
Dividend yield | 5.28 | % | 4.84 | % | |||||||
Expected volatility | 23.2 | % | 24.4 | % | |||||||
Risk-free interest rate | 1.3 | % | 2.65 | % | |||||||
Expected life (years) | 6.25 | 6.25 | |||||||||
Weighted average grant date fair value (per share) | $ | 4.18 | $ | 6.22 | |||||||
The assumptions above relate to Exelon stock options granted during the periods presented and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended 2012. | |||||||||||
The dividend yield is based on several factors, including Exelon's most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon's common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary. | |||||||||||
The following table presents information with respect to stock option activity for the year ended December 31, 2013: | |||||||||||
Weighted | Weighted | ||||||||||
Average | Average | ||||||||||
Exercise | Remaining | ||||||||||
Price | Contractual | Aggregate | |||||||||
(per | Life | Intrinsic | |||||||||
Shares | share) | (years) | Value | ||||||||
Balance of shares outstanding at December 31, 2012 | 21,903,781 | $ | 45.91 | ||||||||
Options reinstated | 751,122 | 38.6 | |||||||||
Options exercised | -670,957 | 28.02 | |||||||||
Options forfeited | -54,743 | 39.36 | |||||||||
Options expired | -893,758 | 49.08 | |||||||||
Balance of shares outstanding at December 31, 2013 | 21,035,445 | $ | 46.07 | 4.72 | $ | 10 | |||||
Exercisable at December 31, 2013 (a) | 20,188,327 | $ | 46.31 | 4.58 | $ | 10 | |||||
(a) Includes stock options issued to retirement eligible employees. | |||||||||||
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2013, 2012 and 2011: | |||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Intrinsic value (a) | $ | 4 | $ | 19 | $ | 5 | |||||
Cash received for exercise price | 19 | 47 | 13 | ||||||||
(a) The difference between the market value on the date of exercise and the option exercise price. | |||||||||||
The following table summarizes Exelon's nonvested stock option activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Exercise Price | |||||||||||
Shares | (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,960,665 | $ | 40.56 | ||||||||
Vested | -1,058,804 | 40.89 | |||||||||
Forfeited | -54,743 | 39.36 | |||||||||
Nonvested at December 31, 2013 (a) | 847,118 | $ | 40.22 | ||||||||
(a) Excludes 1,348,913 and 2,647,536 of stock options issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
At December 31, 2013, $2 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.6 years. | |||||||||||
Restricted Stock Units | |||||||||||
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued. | |||||||||||
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary. | |||||||||||
The following table summarizes Exelon's nonvested restricted stock unit activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 2,029,161 | $ | 42.12 | ||||||||
Granted | 2,828,187 | 31.06 | |||||||||
Vested | -842,439 | 42.9 | |||||||||
Forfeited | -108,199 | 36.37 | |||||||||
Undistributed vested awards (b) | -520,013 | 32.62 | |||||||||
Nonvested at December 31, 2013 (a) | 3,386,697 | $ | 34.1 | ||||||||
(a) Excludes 931,628 and 686,121 of restricted stock units issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2013, 2012 and 2011 was $31.06, $39.94 and $43.33, respectively. At December 31, 2013 and 2012, Exelon had obligations related to outstanding restricted stock units not yet settled of $77 million and $58 million, respectively, which are included in common stock in Exelon's Consolidated Balance Sheets. For the years ended December 31, 2013, 2012 and 2011, Exelon settled restricted stock units with fair value totaling $28 million, $25 million and $19 million, respectively. At December 31, 2013, $64 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.5 years. | |||||||||||
Performance Share Awards | |||||||||||
Performance share awards are granted under the LTIP. The 2013 and 2012 performance share awards are being settled 50% in common stock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period. | |||||||||||
The one-time 2013 performance share transition awards, which provide an opportunity to earn an award contingent on company performance, will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. One-third of the award vests and is payable after a one-year performance period while the remaining two-thirds vests and is payable after a two-year performance period. | |||||||||||
The payout of the 2013 performance share awards and one-time performance share transition awards are based on the Company's performance against specific operational and financial goals set annually during the respective performance periods. As a result, the 2013 performance share awards have been divided into equal tranches for the purpose of expense recognition as though the respective award were multiple awards; with each tranche representing a corresponding fiscal year. The one-time performance share transition awards have also been divided into multiple tranches for the purpose of expense recognition. One tranche reflects the one-third of the awards that vests and are payable after a one-year period. The two-thirds of the one-time performance share transition awards that are subject to a two-year performance period have also been divided into equal tranches; with each tranche representing a corresponding fiscal year. The grant date for each tranche of the 2013 performance share and one-time performance share transition awards is the date in which the performance goals for that fiscal year are approved and communicated, which typically occurs at the corresponding January Compensation Committee meeting. | |||||||||||
The 2013 performance share awards and one-time performance share transition awards are recorded at fair value at the grant dates for each tranche, with the estimated grant date fair value based on the expected payout of the award, which may range from 50% to 150% of the payout target. The 2013 performance share awards also include a total shareholder return modifier (TSR) that may increase or decrease the award up to 25% and an individual performance modifier (IPM) that can decrease the award by up to 50% or increase the award by up to 10% for SVPs and higher officers or up to 20% for vice presidents. The one-time performance share transition award is not affected by either TSR or the IPM. | |||||||||||
The common stock portion of the performance share and one-time performance share transition awards is considered an equity award being valued based on Exelon's stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon's current stock price. As the value of the common stock and cash portions of the awards are based on Exelon's stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established. | |||||||||||
The 2012 performance share awards are recorded at fair value at the date of grant with the estimated grant date fair value based on the expected payout of the award, which may range from 75% to 125% of the payout target. The common stock portion is considered an equity award with the 75% payout floor being valued based on Exelon's stock price on the grant date. The cash portion of the award is considered a liability award with the 75% payout floor being remeasured each reporting period based on Exelon's current stock price. The expected payout in excess of the 75% floor for the equity and liability portions are remeasured each reporting period based on Exelon's current stock price and changes in the expected payout of the award; therefore these portions of the award are subject to volatility until the payout is established. | |||||||||||
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant. | |||||||||||
The following table summarizes Exelon's nonvested performance share awards activity for the year ended December 31, 2013: | |||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,312,734 | $ | 40.08 | ||||||||
Granted | 2,629,171 | 31.55 | |||||||||
Vested | -612,624 | 40.13 | |||||||||
Forfeited | -24,451 | 32.17 | |||||||||
Undistributed vested awards (b) | -1,290,640 | 34.28 | |||||||||
Nonvested at December 31, 2013 (a) | 2,014,190 | $ | 32.74 | ||||||||
(a) Excludes 1,411,824 and 204,643 of performance share awards issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2013, 2012 and 2011 was $31.55, $39.71, and $43.52, respectively. During the years ended December 31, 2013, 2012 and 2011, Exelon settled performance shares with a fair value totaling $26 million, $23 million and $22 million, respectively, of which $12 million, $3 million and $10 million was paid in cash, respectively. As of December 31, 2013, $34 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years. | |||||||||||
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled: | |||||||||||
December 31, | |||||||||||
2013 | 2012 | ||||||||||
Current liabilities (a) | $ | 13 | $ | 7 | |||||||
Deferred credits and other liabilities (b) | 24 | 11 | |||||||||
Common stock | 32 | 35 | |||||||||
Total | $ | 69 | $ | 53 | |||||||
(a) Represents the current liability related to performance share awards expected to be settled in cash. | |||||||||||
(b) Represents the long-term liability related to performance share awards expected to be settled in cash. | |||||||||||
Earnings_Per_Share_and_Equity_
Earnings Per Share and Equity (Exelon) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Earnings Per Share and Equity [Abstract] | ' | |||||||||
Earnings Per Share and Equity (Exelon) | ' | |||||||||
20. Earnings Per Share and Equity (Exelon) | ||||||||||
Earnings per Share | ||||||||||
Diluted earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon's LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share: | ||||||||||
Year Ended December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Net income attributable to common shareholders | $ | 1,719 | $ | 1,160 | $ | 2,495 | ||||
Weighted average common shares outstanding — basic | 856 | 816 | 663 | |||||||
Assumed exercise and/or distributions of stock-based awards | 4 | 3 | 2 | |||||||
Weighted average common shares outstanding — diluted | 860 | 819 | 665 | |||||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 20 million in 2013, 14 million in 2012 and 9 million in 2011. | ||||||||||
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2013. In 2008, Exelon management decided to defer indefinitely any share repurchases. | ||||||||||
Preferred Securities Redemption (Exelon and PECO) | ||||||||||
On May 1, 2013, PECO redeemed all of its outstanding preferred securities. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series of securities were issued. The redemption premium of $6 million is treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of earnings per share for Exelon for the year ending December 31, 2013. As a result of the redemption, PECO is now indirectly, wholly-owned by Exelon. | ||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||||||||||||||||
22. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||
Nuclear Insurance | ||||||||||||||||||||||||
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. | ||||||||||||||||||||||||
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2013, the current liability limit per incident was $13.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of January 1, 2013, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $13.2 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon's maximum liability per incident is approximately $2.4 billion. | ||||||||||||||||||||||||
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident. | ||||||||||||||||||||||||
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member. | ||||||||||||||||||||||||
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. NEIL declared a distribution for 2013, of which Generation's portion was $18.5 million. The distribution was recorded as a reduction to Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. No distributions were declared in 2011 or 2012. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of future assessments, or if they will be imposed at all, as of December 31, 2013, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $287 million. | ||||||||||||||||||||||||
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. As of December 31, 2013, Generation's current limit for this coverage is $2.1 billion. For property limits in excess of the first $1.25 billion of that limit, Generation participates in an $850 million single limit blanket policy shared by all the Generation operating nuclear sites and the Salem and Hope Creek nuclear sites. This blanket limit is not subject to automatic reinstatement in the event of a loss. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. Under the terms of the various insurance agreements, Generation could be assessed up to $229 million per year for losses incurred at any plant insured by the insurance company (the retrospective premium obligation). In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses. The $3.2 billion maximum recovery limit is not applicable, however, in the event of a “certified act of terrorism” as defined in the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007. The Terrorism Risk Insurance Act expires on December 31, 2014. | ||||||||||||||||||||||||
Additionally, NEIL provides replacement power cost insurance in the event of a major accidental outage at an insured nuclear station. The premium for this coverage is subject to assessment for adverse loss experience. Generation's maximum share of any assessment is $58 million per year (the retrospective premium obligation). Recovery under this insurance for terrorist acts is subject to the $3.2 billion aggregate limit and secondary to the property insurance described above. This limit would not apply in cases of certified acts of terrorism under the Terrorism Risk Insurance Act of 2002, as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2007, as described above. | ||||||||||||||||||||||||
NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance. | ||||||||||||||||||||||||
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon's and Generation's financial condition, results of operations and liquidity. | ||||||||||||||||||||||||
Spent Nuclear Fuel Obligation | ||||||||||||||||||||||||
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation's nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation pays the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance will be delayed significantly. On November 19, 2013, the United States Court of Appeals for the District of Columbia Circuit ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On January 3, 2014, the DOE filed a petition for rehearing. On the same date, as ordered by the court, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero, subject to any further judicial decision. The DOE's submitted proposal becomes effective after the 90-days of continuous session of the Congress unless there is Congressional action contrary to the DOE proposal. However, if the court grants the petition for rehearing, the proposal to eliminate the fee (and the review period) will be held in suspense until after the court rules. Until such time as a new fee structure is in effect, Generation must continue to pay the current SNF disposal fees. | ||||||||||||||||||||||||
The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama administration devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) on America's Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation's spent nuclear fuel and high-level radioactive waste. | ||||||||||||||||||||||||
In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in 2025. | ||||||||||||||||||||||||
Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations. The extended delay in SNF acceptance by the DOE has led to Generation's adoption of dry cask storage at its Dresden, Clinton, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle and Quad Cities stations. | ||||||||||||||||||||||||
In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government's breach, for costs associated with storage of SNF at Generation's nuclear stations pending the DOE's fulfillment of its obligations. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF. | ||||||||||||||||||||||||
Under the settlement agreement, Generation has received cash reimbursements for costs incurred through April 30, 2013, totaling approximately $712 million ($601 million after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek). As of December 31, 2013, the amount of SNF storage costs for which reimbursement will be requested from the DOE under the settlement agreement is $71 million, which is recorded within Accounts receivable, other. Of this amount, $18 million represents amounts owed to the co-owners of the Peach Bottom and Quad Cities generating facilities. | ||||||||||||||||||||||||
CENG entered into settlement agreements with the DOE during 2011 and 2012 to recover damages caused by the DOE's failure to comply with legal and contractual obligations to dispose of spent nuclear fuel related to the Ginna, Calvert Cliffs and Nine Mile Point nuclear power plants. At December 31, 2012, Generation had approximately $22 million recorded as a receivable from CENG with respect to costs incurred by Constellation prior to the formation of the CENG joint venture for the Nine Mile Point and Calvert Cliffs nuclear power plants. CENG received the funds for the Nine Mile Point and Calvert Cliffs settlement from the DOE in January 2013 and February 2013, respectively, and remitted the $22 million to Generation. | ||||||||||||||||||||||||
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2013, the unfunded SNF liability for the one-time fee with interest was $1,021 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2013, was 0.051%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon's 2001 corporate restructuring. The outstanding one-time fee obligations for the Oyster Creek and TMI units remain with the former owners. Clinton has no outstanding obligation. See Note 11 – Fair Value of Assets and Liabilities for additional information. | ||||||||||||||||||||||||
Energy Commitments | ||||||||||||||||||||||||
Generation's customer facing activities include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Several of Generation's long-term PPAs, which have been determined to be operating leases, have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants, such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. In addition to physical contracts, Generation uses financial contracts for economic hedging purposes and, to a lesser extent, as part of proprietary trading activities. | ||||||||||||||||||||||||
Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. Generation provides for delivery of its energy to these customers through firm transmission. | ||||||||||||||||||||||||
As part of reaching a comprehensive agreement with EDF in October 2010, the existing power purchase agreements with CENG were modified to be unit−contingent through the end of their original term in 2014. Under these agreements, CENG has the ability to fix the energy price on a forward basis by entering into monthly energy hedge transactions for a portion of the future sale, while any unhedged portions will be provided at market prices by default. Additionally, beginning in 2015 and continuing to the end of the life of the respective plants, Generation agreed to purchase 50.01% of the nuclear plant output owned by CENG at market prices. Generation discloses in the table below commitments to purchase from CENG at fixed prices. All commitments to purchase at market prices, which include all purchases subsequent to December 31, 2014, are excluded from the table. Generation continues to own a 50.01% membership interest in CENG that is accounted for as an equity method investment. See Note 5 – Investment in Constellation Energy Nuclear Group, LLC and Note 25 — Related Party Transactions for more details on this arrangement. | ||||||||||||||||||||||||
At December 31, 2013, Generation's short- and long-term commitments, relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following tables: | ||||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||
2014 | $ | 412 | $ | 117 | $ | 25 | $ | 824 | $ | 1,378 | ||||||||||||||
2015 | 367 | 110 | 13 | — | 490 | |||||||||||||||||||
2016 | 284 | 76 | 2 | — | 362 | |||||||||||||||||||
2017 | 223 | 25 | 2 | — | 250 | |||||||||||||||||||
2018 | 112 | 3 | 2 | — | 117 | |||||||||||||||||||
Thereafter | 414 | 3 | 32 | — | 449 | |||||||||||||||||||
Total | $ | 1,812 | $ | 334 | $ | 76 | $ | 824 | $ | 3,046 | ||||||||||||||
(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at December 31, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | ||||||||||||||||||||||||
(b) The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||
ComEd purchases its expected energy requirements through an ICC approved competitive bidding process administered by the IPA and spot market purchases. See Note 3—Regulatory Matters for further information. | ||||||||||||||||||||||||
Since 2009, PECO has entered into contracts through a competitive procurement process in order to meet a portion of its default service customers' electric supply requirements for 2011 through 2016. See Note 3—Regulatory Matters for further information regarding the DSP Programs. | ||||||||||||||||||||||||
ComEd is subject to requirements established by the Illinois Settlement Legislation and the Energy Infrastructure Modernization Act related to the use of alternative energy resources. PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. BGE is subject to requirements established by the Public Utilities Article in Maryland related to the use of alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOS procurement auctions have the obligation, by contract with BGE, to meet the RPS requirement. BGE has entered into contracts with curtailment services providers in accordance with the March 2009 MDPSC order. See Note 3—Regulatory Matters for additional information relating to electric generation procurement, alternative energy resources and energy efficiency programs. | ||||||||||||||||||||||||
ComEd's, PECO's and BGE's electric supply procurement, curtailment services, REC and AEC purchase commitments as of December 31, 2013 are as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
ComEd | ||||||||||||||||||||||||
Electric supply procurement(a) | $ | 736 | $ | 323 | $ | 136 | $ | 137 | $ | 140 | $ | 0 | $ | 0 | ||||||||||
Renewable energy and RECs(b) | 1,589 | 72 | 74 | 76 | 77 | 83 | 1,207 | |||||||||||||||||
PECO | ||||||||||||||||||||||||
Electric supply procurement(c) | 681 | 590 | 91 | 0 | 0 | 0 | 0 | |||||||||||||||||
AECs(d) | 14 | 2 | 2 | 2 | 2 | 2 | 4 | |||||||||||||||||
BGE | ||||||||||||||||||||||||
Electric supply procurement(e) | 1,256 | 783 | 400 | 73 | 0 | 0 | 0 | |||||||||||||||||
Curtailment services(f) | 132 | 45 | 40 | 34 | 13 | 0 | 0 | |||||||||||||||||
_________________ | ||||||||||||||||||||||||
ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. The ICC's December 18, 2013 order approved the reduction of ComEd's commitments under the long-term contracts for the June 2014 through May 2015 procurement period, however the amount of the reduction will not be finalized and approved by the ICC until March 2014. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
BGE entered into various contracts for the procurement of electricity beginning 2013 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
Fuel Purchase Obligations | ||||||||||||||||||||||||
In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation. PECO and BGE have commitments to purchase natural gas, related transportation, storage capacity and services to serve customers in their gas distribution service territory. As of December 31, 2013, these net commitments were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Generation | $ | 8,490 | $ | 1,212 | $ | 1,256 | $ | 1,040 | $ | 1,044 | $ | 763 | $ | 3,175 | ||||||||||
PECO | 507 | 179 | 112 | 98 | 37 | 15 | 66 | |||||||||||||||||
BGE | 609 | 129 | 59 | 57 | 57 | 51 | 256 | |||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Exelon | $ | 262 | $ | 61 | $ | 34 | $ | 32 | $ | 31 | $ | 26 | $ | 78 | ||||||||||
Generation | 504 | 170 | 131 | 45 | 42 | 30 | 86 | |||||||||||||||||
ComEd (a) | 122 | 88 | 5 | 5 | 5 | 5 | 14 | |||||||||||||||||
PECO (a) | 40 | 30 | 1 | 1 | 1 | 1 | 6 | |||||||||||||||||
BGE (a) | 53 | 44 | 2 | 5 | 2 | — | — | |||||||||||||||||
_________________ | ||||||||||||||||||||||||
(a) Purchase obligations include commitments related to smart meter installation. See Note 3 - Regulatory Matters for additional information. | ||||||||||||||||||||||||
Commercial Commitments | ||||||||||||||||||||||||
Exelon's commercial commitments as of December 31, 2013, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,520 | $ | 1,217 | $ | 298 | $ | — | $ | 5 | $ | — | $ | — | ||||||||||
Surety bonds (b) | 339 | 301 | 2 | 6 | 4 | 1 | 25 | |||||||||||||||||
Performance guarantees (c) | 1,107 | 350 | — | — | — | — | 757 | |||||||||||||||||
Energy marketing contract | ||||||||||||||||||||||||
guarantees (d) | 3,161 | 3,161 | — | — | — | — | — | |||||||||||||||||
Lease guarantees (e) | 44 | — | — | — | — | — | 44 | |||||||||||||||||
Nuclear insurance premiums (f) | 3,529 | — | — | — | — | — | 3,529 | |||||||||||||||||
Total commercial commitments | $ | 9,700 | $ | 5,029 | $ | 300 | $ | 6 | $ | 9 | $ | 1 | $ | 4,355 | ||||||||||
(a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Guarantees issued to ensure performance under specific contracts, including $211 million issued on behalf of CENG nuclear generating facilities for credit support, $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II. | ||||||||||||||||||||||||
(d) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $463 million at December 31, 2013, which represents the total amount Exelon could be required to fund based on December 31, 2013 market prices. | ||||||||||||||||||||||||
(e) Lease guarantees - Guarantees issued to ensure payments on building leases. | ||||||||||||||||||||||||
(f) Nuclear insurance premiums - Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||
Generation's commercial commitments as of December 31, 2013, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,477 | $ | 1,174 | $ | 298 | $ | — | $ | 5 | $ | — | $ | — | ||||||||||
Performance guarantees (b) | 357 | 343 | — | — | — | — | 14 | |||||||||||||||||
Energy marketing contract guarantees (c) | 832 | 832 | — | — | — | — | — | |||||||||||||||||
Nuclear insurance premiums (d) | 3,529 | — | — | — | — | — | 3,529 | |||||||||||||||||
Total commercial commitments | $ | 6,195 | $ | 2,349 | $ | 298 | $ | — | $ | 5 | $ | — | $ | 3,543 | ||||||||||
(a) Letters of credit (non-debt) - Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Performance guarantees - Guarantees issued to ensure performance under specific contracts including $211 million issued on behalf of CENG nuclear generating facilities for credit support. | ||||||||||||||||||||||||
(c) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $749 million of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.2 billion at December 31, 2013, which represents the total amount Generation could be required to fund based on December 31, 2013 market prices. | ||||||||||||||||||||||||
(d) Nuclear insurance premiums - Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Nuclear Insurance section within this note for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||
ComEd's commercial commitments as of December 31, 2013, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 19 | $ | 19 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 9 | 9 | — | — | — | — | — | |||||||||||||||||
Performance guarantees (c) | 200 | — | — | — | — | — | 200 | |||||||||||||||||
Total commercial commitments | $ | 228 | $ | 28 | $ | — | $ | — | $ | — | $ | — | $ | 200 | ||||||||||
(a) Letters of credit (non-debt) - ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd. | ||||||||||||||||||||||||
PECO's commercial commitments as of December 31, 2013, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 22 | $ | 22 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 3 | 3 | — | — | — | — | — | |||||||||||||||||
Performance guarantees(c) | 178 | — | — | — | — | — | 178 | |||||||||||||||||
Total commercial commitments | $ | 203 | $ | 25 | $ | — | $ | — | $ | — | $ | — | $ | 178 | ||||||||||
(a) Letters of credit (non-debt) - PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO. | ||||||||||||||||||||||||
BGE's commercial commitments as of December 31, 2013, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 9 | 9 | — | — | — | — | — | |||||||||||||||||
Performance guarantees (c) | 250 | — | — | — | — | — | 250 | |||||||||||||||||
Total commercial commitments | $ | 260 | $ | 10 | $ | — | $ | — | $ | — | $ | — | $ | 250 | ||||||||||
Letters of credit (non-debt) - BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
Surety bond – Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
Performance guarantee - Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE. | ||||||||||||||||||||||||
Construction Commitments | ||||||||||||||||||||||||
Generation has committed to the construction of the Antelope Valley solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013 and an expectation of full commercial operation in the first half of 2014. Generation's estimated remaining commitment for the project is $110 million. | ||||||||||||||||||||||||
On July 3, 2013, Generation executed a Turbine Supply Agreement to expand its Beebe wind project in Michigan. The estimated remaining commitment under the contract is $50 million and achievement of commercial operations is expected in 2014. | ||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120 MW of new natural gas-fired generation to satisfy certain merger commitments. The estimated remaining commitment under the contract is $80 million and achievement of commercial operation is expected in 2015. See 4 – Merger and Acquisitions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||
On December 27, 2013, Generated executed a Turbine Supply Agreement for construction of the 32.5MW Fourmile Wind project in western Maryland. The estimated remaining commitment under the contract is $26 million and achievement of commercial operations is expected in 2014. See 4 – Merger and Acquisitions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||
Refer to Note 3 – Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan, and BGE's comprehensive smart grid initiative. | ||||||||||||||||||||||||
Letters of credit (non-debt) - BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
Surety bond – Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
Performance guarantee - Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE. | ||||||||||||||||||||||||
Construction Commitments | ||||||||||||||||||||||||
Generation has committed to the construction of the Antelope Valley solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013 and an expectation of full commercial operation in the first half of 2014. Generation's estimated remaining commitment for the project is $110 million. | ||||||||||||||||||||||||
On July 3, 2013, Generation executed a Turbine Supply Agreement to expand its Beebe wind project in Michigan. The estimated remaining commitment under the contract is $50 million and achievement of commercial operations is expected in 2014. | ||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120 MW of new natural gas-fired generation to satisfy certain merger commitments. The estimated remaining commitment under the contract is $80 million and achievement of commercial operation is expected in 2015. See 4 – Merger and Acquisitions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||
On December 27, 2013, Generated executed a Turbine Supply Agreement for construction of the 32.5MW Fourmile Wind project in western Maryland. The estimated remaining commitment under the contract is $26 million and achievement of commercial operations is expected in 2014. See 4 – Merger and Acquisitions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the merger. | ||||||||||||||||||||||||
Refer to Note 3 – Regulatory Matters for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan, and BGE's comprehensive smart grid initiative. | ||||||||||||||||||||||||
Constellation Merger Commitments | ||||||||||||||||||||||||
Exelon's commercial and construction commitments shown above do not include the merger commitments made to the State of Maryland in conjunction with the Constellation merger. See Note 4 – Merger and Acquisitions for additional information on the mergers commitments. | ||||||||||||||||||||||||
Leases | ||||||||||||||||||||||||
Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2013 were: | ||||||||||||||||||||||||
Exelon | Generation | ComEd (b) | PECO (b) | BGE (b)(c) | ||||||||||||||||||||
2014 | $ | 103 | $ | 49 | $ | 13 | $ | 13 | $ | 12 | ||||||||||||||
2015 | 91 | 50 | 11 | 3 | 11 | |||||||||||||||||||
2016 | 89 | 49 | 11 | 3 | 9 | |||||||||||||||||||
2017 | 82 | 48 | 7 | 3 | 8 | |||||||||||||||||||
2018 | 63 | 40 | 2 | 3 | 7 | |||||||||||||||||||
Remaining years | 398 | 336 | 3 | — | 14 | |||||||||||||||||||
Total minimum future lease payments | $ | 826 | (a) | $ | 572 | (a) | $ | 47 | $ | 25 | $ | 61 | ||||||||||||
(a) Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments. | ||||||||||||||||||||||||
(b) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd's, PECO's and BGE's annual obligation for these arrangements, included in each of the years 2014 - 2018, was $1 million, $3 million and $1 million respectively. | ||||||||||||||||||||||||
(c) Includes all future lease payments on a 99 year real estate lease that expires in 2105. | ||||||||||||||||||||||||
The following table presents the Registrants' rental expense under operating leases for the years ended December 31, 2013, 2012 and 2011: | ||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation (a) | ComEd | PECO | BGE | |||||||||||||||||||
2013 | $ | 806 | $ | 744 | $ | 15 | $ | 21 | $ | 11 | ||||||||||||||
2012 | 930 | 872 | 18 | 27 | 12 | |||||||||||||||||||
2011 | 711 | 659 | 18 | 28 | 15 | |||||||||||||||||||
(a) Includes Generation's PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation's PPAs and other capacity contracts totaled $694 million, $801 million and $630 million during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||
For information regarding capital lease obligations, see Note 13 – Debt and Credit Agreements. | ||||||||||||||||||||||||
Indemnifications Related to Sale of Sithe (Exelon and Generation) | ||||||||||||||||||||||||
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation's sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group's 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy Inc. (Dynegy). | ||||||||||||||||||||||||
The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2013. Generation believes that it is remote that it will be required to make any additional payments under the guarantee, and currently has no recorded liabilities associated with this guarantee. Generation expects that the exposure covered by this guarantee will expire in 2014. The guarantee is included above in the Commercial Commitments table under performance guarantees. | ||||||||||||||||||||||||
Indemnifications Related to Sale of TEG and TEP (Exelon and Generation) | ||||||||||||||||||||||||
On February 9, 2007, Tamuin International Inc. (TII), a wholly owned subsidiary of Generation, sold its 49.5% ownership interests in TEG and TEP to a subsidiary of AES Corporation for $95 million in cash plus certain purchase price adjustments. In connection with the transaction, Generation entered into a guarantee agreement under which Generation guarantees the timely payment of TII's obligations to the subsidiary of AES Corporation pursuant to the terms of the purchase and sale agreement relating to the sale of TII's ownership interests. Generation was required to perform in the event that TII did not pay any obligation covered by the guarantee that was not otherwise subject to a dispute resolution process. Portions of the exposures covered by this guarantee expired in 2008, and the remaining guarantee expired in the third quarter of 2013. Generation was not required to make payments under the guarantee, and therefore, has no further obligation related to this guarantee as of December 31, 2013. | ||||||||||||||||||||||||
Environmental Matters | ||||||||||||||||||||||||
General. The Registrants' operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property currently or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. | ||||||||||||||||||||||||
ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For many of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location. | ||||||||||||||||||||||||
ComEd has identified 42 sites, 16 of which have been approved for cleanup by the Illinois EPA or the U.S. EPA and 26 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2016. | ||||||||||||||||||||||||
PECO has identified 26 sites, 16 of which have been approved for cleanup by the PA DEP and 10 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2020. | ||||||||||||||||||||||||
BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor's acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One gas purification site is in the initial stages of investigation at the direction of the MDE. | ||||||||||||||||||||||||
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. BGE is authorized to and is currently recovering environmental costs for the remediation of former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recorded regulatory assets for the recovery of these costs. During the third quarter of 2013, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites; accordingly, ComEd and PECO increased their reserves and regulatory assets by less than $1 million and $6 million, respectively. BGE assessed its currently and formerly owned gas manufacturing and purification sites quarterly in 2013 and determined that a loss was not probable at ten of its sites as of December 31, 2013. As discussed above, the remediation costs at two of BGE's MGP sites are not considered material. Furthermore, an estimate of a range of possible loss, if any, related to BGE's gas purification site under investigation cannot be determined as of December 31, 2013 given that the site is in the early stages of investigation and the extent of contamination is currently unknown. See Note 3 — Regulatory Matters for additional information regarding the associated regulatory assets. | ||||||||||||||||||||||||
The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial action. Management determines its best estimate of remediation costs based on probabilistic modeling and deterministic estimates using all available information at the time of each study and the remediation standards currently required by the U.S. EPA. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency. | ||||||||||||||||||||||||
As of December 31, 2013 and 2012, the Registrants have accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets: | ||||||||||||||||||||||||
Total environmental investigation | Portion of total related to MGP | |||||||||||||||||||||||
31-Dec-13 | and remediation reserve | investigation and remediation | ||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||
Total environmental investigation | Portion of total related to MGP | |||||||||||||||||||||||
31-Dec-12 | and remediation reserve | investigation and remediation | ||||||||||||||||||||||
Exelon | $ | 351 | $ | 298 | ||||||||||||||||||||
Generation | 42 | 0 | ||||||||||||||||||||||
ComEd | 261 | 254 | ||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. | ||||||||||||||||||||||||
Water Quality | ||||||||||||||||||||||||
Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation's and CENG's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. | ||||||||||||||||||||||||
On March 28, 2011, the U.S. EPA issued the proposed regulation under Section 316(b). The proposal does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The proposal provides the state permitting agency with discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The proposed rule also imposes limits on impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or another technology at the intake. Exelon filed comments on the proposed regulation on August 18, 2011, stating its support for a number of its provisions (e.g., cooling towers not required as best technology available, and the use of site-specific and cost benefit analysis) while also noting a number of technical provisions that require revision to take into account existing unit operations and practices within the industry. | ||||||||||||||||||||||||
In June 2012, the U.S. EPA published two Notices of Data Availability (NODA) seeking public comment on alternate compliance technologies for impingement and the use of a public opinion survey to calculate the so-called “non-use” benefits of the rule. Exelon filed comments for each NODA, supporting the additional flexibility afforded by the impingement NODA, and opposing the NODA relating to calculation of non-use benefits due to its inaccurate and unreliable methodologies that would artificially inflate the benefits of proposed technologies that would otherwise not be cost-effective. On June 27, 2013, the U.S. EPA agreed to amend the court approved Settlement Agreement to extend the deadline to issue a final rule until November 4, 2013 and on October 30, 2013 the U.S. EPA invoked the force majeure provision of the Settlement Agreement to extend the final rule deadline until January 14, 2014 due to the early October 2013 federal government shutdown. The U.S. EPA and the plaintiffs have again agreed to extend the date for issuance of the final rule until April 17, 2014. Until the rule is finalized, the state permitting agencies will continue to apply their best professional judgment to address impingement and entrainment. | ||||||||||||||||||||||||
Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon's and Generation's share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment. | ||||||||||||||||||||||||
It is unknown at this time whether the NJDEP permit programs will require closed-cycle cooling at Salem. In addition, the economic viability of Generation's other power generation facilities, as well as CENG's, without closed-cycle cooling water systems will be called into question by any requirement to construct cooling towers. Should the final rule not require the installation of cooling towers, and retain the flexibility afforded the state permitting agencies in applying a cost benefit test and to consider site-specific factors, the impact of the rule would be minimized even though the costs of compliance could be material to Generation and CENG. | ||||||||||||||||||||||||
Given the uncertainties associated with the requirements that will be contained in the final rule, Generation cannot predict the eventual outcome or estimate the effect that compliance with any resulting Section 316(b) or interim state requirements will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position. | ||||||||||||||||||||||||
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Prior to the Merger, Constellation recorded in its Consolidated Balance Sheets total liabilities of approximately $30 million to comply with the consent decree with an additional $3 million recognized through purchase accounting. During third quarter of 2013, Generation increased its reserve by $2 million based on an update of future estimated remediation costs. The remaining liability as of December 31, 2013, is approximately $14 million. In addition, a private party asserted claims relating to groundwater contamination. Generation has reached an agreement in principle to resolve these claims. The amount of the settlement is not material to the financial condition of Generation. | ||||||||||||||||||||||||
Alleged Conemaugh Clean Streams Act Violation. The PA DEP has alleged that GenOn Northeast Management Company (GenOn), the operator of Conemaugh Generating Station, violated the Pennsylvania Clean Streams Law. GenOn reached agreement with PA DEP on a proposed Consent Decree that was approved by the Commonwealth Court of Pennsylvania on December 4, 2012. Under the Consent Decree, GenOn is obligated to pay a civil penalty of $0.5 million, of which Generation's responsibility was approximately $0.2 million. Generation made the final payment in January 2014 and is complying with the Consent Decree. | ||||||||||||||||||||||||
Air Quality | ||||||||||||||||||||||||
Cross-State Air Pollution Rule (CSAPR). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court's July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. | ||||||||||||||||||||||||
Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court's consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. The Court's order was appealed to the U.S. Supreme Court, where oral argument was held on December 10, 2013. A decision is expected sometime during 2014. | ||||||||||||||||||||||||
Under the CSAPR, generation units were to receive allowances based on historic heat input and intrastate, and limited interstate, trading of allowances was permitted. The CSAPR restricted entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use under ARP. As of December 31, 2013, Generation had $56 million of emission allowances carried at the lower of weighted average cost or market. | ||||||||||||||||||||||||
EPA Mercury and Air Toxics Standards (MATS). The MATS rule became final on April 16, 2012. The MATS rule reduces emissions of toxic air pollutants, and finalized the new source performance standards for fossil fuel-fired electric utility steam generating units (EGUs). The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities have challenged MATS in the D.C. Circuit Court, and Exelon was granted permission by the Court to intervene in support of the rule. A decision by the Court is expected sometime during 2014. The outcome of the appeal, and its impact on power plant operators' investment and retirement decisions, is uncertain. | ||||||||||||||||||||||||
Exelon, along with the other co-owners of Conemaugh Generating Station are moving forward with plans to improve the existing scrubbers and install Selective Catalytic Reduction (SCR) controls to meet the mercury removal requirements of MATS. | ||||||||||||||||||||||||
In addition, as of December 31, 2013, Exelon had a $698 million net investment in coal-fired plants in Georgia and Texas subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, after the impairment recorded in the second quarter of 2013, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material. | ||||||||||||||||||||||||
National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of all NAAQS by 2014. Oral argument in the litigation (State of Miss. v. EPA) of the final 2008 ozone standard occurred in the D.C. Circuit Court in November 2012 and a final Court decision was issued on July 23, 2013 with the 2008 primary ozone standard upheld, but the secondary standard remanded to EPA for reconsideration. Concurrent with litigation of the 2008 ozone standard, the U.S. EPA continues its regular, periodic review of the ozone NAAQS and is expected to propose revisions in the fall of 2014, with preliminary indications that the U.S. EPA will likely propose a tightened standard. It is unclear at this point in time whether the U.S. EPA will be able to respond to the Court remand of the secondary 2008 ozone standard on a timeframe that would be any quicker than that of the U.S. EPA's current, periodic review schedule. In December 2012, the U.S. EPA issued its final revisions to the Agency's particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATS regulation. It is unclear if the vacatur of the CSAPR, one of the regulations that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA's view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020. In March 2013, a number of industry coalitions filed a joint lawsuit challenging the new PM2.5 standard. Also during early 2013, the D.C. Circuit remanded several rules for implementation of earlier PM2.5 NAAQS to the U.S. EPA for revision of certain aspects of the rules, with a requirement that the U.S. EPA re-promulgate regulations in conformance with the correct subparts of the Clean Air Act. | ||||||||||||||||||||||||
In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. U.S. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by April 2015. With regard to Texas and Maryland, no nonattainment areas were identified in U.S. EPA's final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. The U.S. EPA will follow the approach outlined in a February 2013 U.S. EPA strategy document that establishes a process and timeline for the Agency to address additional designations in states' counties under a future rulemaking. Nonattainment county compliance with the one-hour SO2 standard is required by October 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states' SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard. | ||||||||||||||||||||||||
Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third-party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon's 2001 corporate restructuring, Generation assumed ComEd's rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME. | ||||||||||||||||||||||||
On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. | ||||||||||||||||||||||||
In 2012, the Bankruptcy Court approved the rejection of a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations. The rejection left Generation as the party responsible to make remaining payments under the lease. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012. | ||||||||||||||||||||||||
During the second quarter of 2013, Exelon filed proofs of claim of $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation for the coal rail car lease, ComEd utility payments and certain legal costs. Further, Exelon filed an environmental claim with an unspecified amount that listed the indemnifications that were in place pre-Petition Date and other factors associated with the remediation. As of December 31, 2013, Exelon has not recorded a receivable for the filed proofs of claim because recovery of any amount cannot be assured at this point in the bankruptcy. Exelon will not record claim recoveries unless and until they are realized. | ||||||||||||||||||||||||
Certain environmental laws and regulations subject current and prior owners of properties or generators of hazardous substances at such properties to liability for remediation costs of environmental contamination. As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon's 2001 corporate restructuring to assume ComEd's rights and obligations associated with its former generation business) could face liability (along with any other potentially responsible parties) for environmental conditions at the stations requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors, including the impact of Midwest Generation's bankruptcy. On January 17, 2014, Midwest Generation filed a plan supplement to its bankruptcy filing that included a request to reject the sale agreement, including the environmental indemnity. ComEd and Generation have reviewed available public information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosed in its quarter ending September 30, 2013 Form 10-Q that (i) it has accrued a probable amount of approximately $8 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at four Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted. For these reasons, ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of December 31, 2013. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows. | ||||||||||||||||||||||||
Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. In addition to the sale agreement, Midwest Generation also requested to reject this supplemental agreement in the January 17, 2014 plan supplement to its bankruptcy filing. Exelon and Generation had previously expected Midwest Generation or its successor would remain responsible for asbestos personal injury claims filed post-Petition Date, and as a result had not recorded a liability for such amounts. Exelon and Generation now believe that the rejection of the 1999 sale and supplemental agreements is probable, and as a result, Generation has increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million. The increase in the reserve was estimated using actuarial assumptions and analyses available to Generation. Generation's exposure could differ to the extent new information is received or made available. Midwest Generation publicly disclosed in its quarter ending September 30, 2013 Form 10-Q that they had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. If the agreements are rejected, Exelon and Generation may be entitled to damages associated with the agreement terminations. These amounts are considered to be contingent gains and would not be recognized until realized. | ||||||||||||||||||||||||
On October 18, 2013, NRG Energy entered into an agreement to buy EME's portfolio of generation subject to regulatory approvals. Exelon continues to monitor all aspects of the bankruptcy; the proposed purchase by NRG has not impacted any accounting conclusions as of December 31, 2013. | ||||||||||||||||||||||||
In May 2010, the United States and State of Illinois initiated a lawsuit against Midwest Generation, ComEd and EME alleging Clean Air Act violations relating to the modification and/or operation of six (coal) electric generation plants in Northern Illinois, which ComEd sold to Midwest Generation/EME in 1999. The government parties sought injunctive relief and civil penalties against all defendants, although not all of the claims specifically pertained to ComEd. On March 16, 2011, the District Court granted ComEd's motion to dismiss the May 2010 complaint in its entirety as it relates to ComEd. On January 3, 2012, upon leave of the District Court, the government parties appealed the dismissal of ComEd to the U.S. Circuit Court of Appeals for the Seventh Circuit. On July 8, 2013, the Circuit Court affirmed the District Court's dismissal of the complaint against ComEd. On September 19, 2013, the Circuit Court denied the petition for a rehearing filed by the governmental parties. The government parties did not seek United States Supreme Court review of the Seventh Circuit's decision. The deadline for seeking such review was in December 2013. In light of the Circuit Court decision resolving this matter in favor of ComEd, no reserve has been established. | ||||||||||||||||||||||||
Solid and Hazardous Waste | ||||||||||||||||||||||||
Cotter Corporation. The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon's 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the supplemental feasibility study that could take up to one year to complete, and subsequently requested additional analysis sampling and modeling to be conducted into 2014. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote. | ||||||||||||||||||||||||
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government's clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd's indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government's Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2014 so that settlement discussions could proceed. Based on Exelon's preliminary review, it appears probable that Exelon has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability. | ||||||||||||||||||||||||
On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the “Exelon defendants”) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the defendants' negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price−Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. Since May 30, 2012, several related lawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations in these related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price–Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price–Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon cannot estimate a range of loss, if any. | ||||||||||||||||||||||||
68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. Based on Exelon's preliminary review, it appears probable that Exelon has liability and has established an appropriate accrual for its share of the estimated clean-up costs. BGE is indemnified by a wholly owned subsidiary of Generation for most of the costs related to this settlement and clean-up of the site. | ||||||||||||||||||||||||
Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC(CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $6 million, which has been fully reserved as of December 31, 2013. | ||||||||||||||||||||||||
Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP's signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP's to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE's reasonably possible loss, if any, cannot be determined. | ||||||||||||||||||||||||
Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA's position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA's “Tailpipe Rule” for cars and light duty trucks, the endangerment finding for GHG's from stationary sources, and the Tailoring Rule. On October 15, 2013 the U.S. Supreme Court granted industry petitions to review one aspect of the PSD permitting regulations. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants. | ||||||||||||||||||||||||
On June 25, 2013, President Obama announced “The President's Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration's plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act. | ||||||||||||||||||||||||
The first rulemaking, under Section 111(b) of the Clean Air Act is to focus on establishing carbon regulations for new fossil-fuel power plants. This rulemaking was proposed on September 20, 2013 and is to be finalized “in a timely fashion.” In the proposed rule U.S.EPA sets separate standards for fossil-fuel fired utility boilers and natural gas fired stationary combustion turbines. | ||||||||||||||||||||||||
The second rulemaking, under Section 111(d) of the Clean Air Act is to focus on modified, reconstructed and existing fossil power plants. The rulemaking is to be proposed no later than June 1, 2014, be finalized no later than June 1, 2015, and require that states submit to U.S. EPA their implementation plans no later than June 30, 2016. In developing this rulemaking, U.S. EPA is directed to consider a number of factors, including options to reduce costs, options to ensure the continued use of a range of energy sources and technologies, options that are consistent with reliable and affordable power, and options that allow for the use of market-based instruments, performance standards and other regulatory flexibilities. | ||||||||||||||||||||||||
To the extent that the final Section 111(d) rule results in emission reductions from fossil fuel fired plants, and thereby imposes some form of direct or indirect price of carbon in competitive electricity markets, Exelon's overall low-carbon generation portfolio results could benefit. | ||||||||||||||||||||||||
Litigation and Regulatory Matters | ||||||||||||||||||||||||
Asbestos Personal Injury Claims (Exelon, Generation, PECO and BGE). | ||||||||||||||||||||||||
Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material. | ||||||||||||||||||||||||
At December 31, 2013 and 2012, Generation had reserved approximately $90 million and $63 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2013, approximately $19 million of this amount related to 224 open claims presented to Generation, while the remaining $71 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. | ||||||||||||||||||||||||
On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee's disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee's last employment-based exposure, and that therefore the exclusivity provision of the Act does not apply to preclude such employee from suing his or her employer in court. The Supreme Court's ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee's last employment-based exposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as of December 31, 2013. Increased claims activity resulting from this ruling could have a material adverse impact on Exelon, Generation's and PECO's future results of operations and cash flows. | ||||||||||||||||||||||||
BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases. | ||||||||||||||||||||||||
Approximately 486 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation's financial results. | ||||||||||||||||||||||||
Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include: | ||||||||||||||||||||||||
the identity of the facilities at which the plaintiffs allegedly worked as contractors; | ||||||||||||||||||||||||
the names of the plaintiffs' employers; | ||||||||||||||||||||||||
the dates on which and the places where the exposure allegedly occurred; and | ||||||||||||||||||||||||
the facts and circumstances relating to the alleged exposure. | ||||||||||||||||||||||||
Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions. | ||||||||||||||||||||||||
Federal Energy Regulatory Commission Investigation (Exelon and Generation). | ||||||||||||||||||||||||
On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation's power trading activities in and around the ISO-NY from September 2007 through December 2008. Prior to the merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay, and has paid, a $135 million civil penalty and $110 million in disgorgement. | ||||||||||||||||||||||||
During the year ended December 31, 2012, Generation recorded expense of $195 million in operating and maintenance expense with the remaining $50 million recorded as a Constellation pre-acquisition contingency. See Note 4 — Merger and Acquisitions for additional information on the merger. | ||||||||||||||||||||||||
Continuous Power Interruption (ComEd) | ||||||||||||||||||||||||
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd's case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. | ||||||||||||||||||||||||
On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd's service territory, as well as for five other storm systems that affected ComEd's customers during June and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket). | ||||||||||||||||||||||||
On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. However, the ICC held that for the July 11, 2011 storm, 34,599 interruptions were preventable and therefore no waiver should apply. As required by the ICC's Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General's request for the ICC to open an investigation into ComEd's infrastructure and storm hardening investments. | ||||||||||||||||||||||||
Following the ICC's June 26, 2013 denial of ComEd's request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC's interpretation of Section 16-125 of the Illinois Public Utilities Act. ComEd cannot predict the outcome of appeals. | ||||||||||||||||||||||||
As a result of the ICC's June 5, 2013 ruling, ComEd established a liability, which was not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC's June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd's ultimate liability will be based on actual claims eligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd's results of operations or cash flows. | ||||||||||||||||||||||||
ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows. | ||||||||||||||||||||||||
Telephone Consumer Protection Act Lawsuit (ComEd) | ||||||||||||||||||||||||
On November 19, 2013, a class action complaint was filed in Cook County on behalf of a single individual and a presumptive class that would include all customers in ComEd's service territory who were enrolled by the Company in ComEd's Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (“TCPA”) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys' fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $500 to $1,500 per text. However, ComEd is preparing a motion to dismiss this class action complaint and will vigorously contest the allegations of this suit. The ultimate outcome of this proceeding is uncertain, and an amount, if any, which might be asserted, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows. As a result, ComEd has not established a reserve for this complaint as of December 31, 2013. | ||||||||||||||||||||||||
Securities Class Action (Exelon) | ||||||||||||||||||||||||
Three federal securities class action lawsuits were filed in the United States District Courts for the Southern District of New York and the District of Maryland between September 2008 and November 2008 against Constellation. The cases were filed on behalf of a proposed class of persons who acquired publicly traded securities, including the Series A Junior Subordinated Debentures (Debentures), of Constellation between January 30, 2008 and September 16, 2008, and who acquired Debentures in an offering completed in June 2008. The securities class actions generally allege that Constellation, a number of its former officers or directors, and the underwriters violated the securities laws by issuing a false and misleading registration statement and prospectus in connection with Constellation's June 27, 2008 offering of the Debentures. The securities class actions also allege that Constellation issued false or misleading statements or was aware of material undisclosed information which contradicted public statements, including in connection with its announcements of financial results for 2007, the fourth quarter of 2007, the first quarter of 2008 and the second quarter of 2008 and the filing of its first quarter 2008 Form 10-Q. The securities class actions sought, among other things, certification of the cases as class actions, compensatory damages, reasonable costs and expenses, including counsel fees, and rescission damages. | ||||||||||||||||||||||||
The Southern District of New York granted the defendants' motion to transfer the two securities class actions filed in Maryland to the District of Maryland, and the actions have since been transferred for coordination with the securities class action filed there. On May 9, 2013, the federal court in Maryland preliminarily approved the settlement of Constellation's 2008 Securities Class Action for a payment of $4 million, which will be paid by Constellation's insurer. Notice of the settlement was provided to class members in June 2013 and the court approved the final settlement on November 4, 2013. This settlement will resolve all of Constellation's litigation arising from the 2008 Securities Class Action lawsuit. | ||||||||||||||||||||||||
Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||||||
Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon's intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool. | ||||||||||||||||||||||||
The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon's actual cash needs. | ||||||||||||||||||||||||
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. | ||||||||||||||||||||||||
PECO's Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. | ||||||||||||||||||||||||
BGE pays dividends on its common stock after its board of directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE's preference stock have not been paid. | ||||||||||||||||||||||||
Baltimore City Franchise Taxes (BGE) | ||||||||||||||||||||||||
The City of Baltimore claims that BGE has maintained electric facilities in the City's public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE is currently reviewing the merits of this claim. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE's results of operations and cash flows. | ||||||||||||||||||||||||
General (Exelon, Generation, ComEd, PECO and BGE). | ||||||||||||||||||||||||
The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. | ||||||||||||||||||||||||
Income Taxes | ||||||||||||||||||||||||
See Note 14—Income Taxes for information regarding the Registrants' income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets. | ||||||||||||||||||||||||
Supplemental_Financial_Informa
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | ||||||||||||||||||
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
23. Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||
Supplemental Statement of Operations Information | |||||||||||||||||||
The following tables provide additional information about the Registrants' Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011. | |||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 449 | $ | 79 | $ | 241 | $ | 129 | $ | 82 | |||||||||
Property | 302 | 205 | 24 | 14 | 112 | ||||||||||||||
Payroll | 159 | 89 | 27 | 13 | 15 | ||||||||||||||
Other | 185 | 16 | 7 | 2 | 4 | ||||||||||||||
Total taxes other than income | $ | 1,095 | $ | 389 | $ | 299 | $ | 158 | $ | 213 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 463 | $ | 82 | $ | 239 | $ | 141 | $ | 75 | |||||||||
Property | 227 | 189 | 22 | 13 | 111 | ||||||||||||||
Payroll | 131 | 78 | 26 | 12 | 18 | ||||||||||||||
Other | 198 | 20 | 8 | -4 | 4 | ||||||||||||||
Total taxes other than income | $ | 1,019 | $ | 369 | $ | 295 | $ | 162 | $ | 208 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 443 | $ | 27 | $ | 243 | $ | 173 | $ | 79 | |||||||||
Property | 177 | 146 | 22 | 9 | 107 | ||||||||||||||
Payroll | 123 | 71 | 25 | 13 | 17 | ||||||||||||||
Other | 42 | 20 | 6 | 10 | 4 | ||||||||||||||
Total taxes other than income | $ | 785 | $ | 264 | $ | 296 | $ | 205 | $ | 207 | |||||||||
(a) Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 256 | $ | 256 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 77 | 77 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | 406 | 406 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 146 | 146 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets — | |||||||||||||||||||
Zion Station decommissioning | 7 | 7 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -546 | -546 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 346 | 346 | 0 | 0 | 0 | ||||||||||||||
Investment income | 8 | -1 | 0 | -1 | 9 | (c) | |||||||||||||
Long-term lease income | 28 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 24 | 4 | 0 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 22 | 0 | 11 | 4 | 7 | ||||||||||||||
Other | 45 | 19 | 15 | 3 | 1 | ||||||||||||||
Other, net | $ | 473 | $ | 368 | $ | 26 | $ | 6 | $ | 17 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 189 | $ | 189 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement Units | 102 | 102 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | 386 | 386 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 105 | 105 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets — | |||||||||||||||||||
Zion Station decommissioning | 73 | 73 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -530 | -530 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 325 | 325 | 0 | 0 | 0 | ||||||||||||||
Investment income | 20 | 3 | 1 | 2 | 11 | (c) | |||||||||||||
Long-term lease income | 29 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 15 | 2 | 20 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 17 | 0 | 6 | 4 | 10 | ||||||||||||||
Credit facility termination fees | -85 | -85 | 0 | 0 | 0 | ||||||||||||||
Other | 25 | -6 | 12 | 2 | 2 | ||||||||||||||
Other, net | $ | 346 | $ | 239 | $ | 39 | $ | 8 | $ | 23 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 177 | $ | 177 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 45 | 45 | 0 | 0 | 0 | ||||||||||||||
Net unrealized losses on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | -74 | -74 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | -4 | -4 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets - | |||||||||||||||||||
Zion Station decommissioning | 48 | 48 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -130 | -130 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 62 | 62 | 0 | 0 | 0 | ||||||||||||||
Investment income | 10 | 1 | 1 | 3 | 13 | (c) | |||||||||||||
Long-term lease income | 28 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 53 | 31 | 14 | 1 | 0 | ||||||||||||||
AFUDC - Equity | 17 | 0 | 8 | 9 | 15 | ||||||||||||||
Bargain purchase gain related to Wolf Hollow acquisition | 36 | 36 | 0 | 0 | 0 | ||||||||||||||
Other | -3 | -8 | 6 | 1 | -2 | ||||||||||||||
Other, net | $ | 203 | $ | 122 | $ | 29 | $ | 14 | $ | 26 | |||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||||||||||||||||
(b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 3 – Regulatory Matters for additional information regarding the rate stabilization deferral. | |||||||||||||||||||
Supplemental Cash Flow Information | |||||||||||||||||||
The following tables provide additional information regarding the Registrants' Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011. | |||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,893 | $ | 813 | $ | 545 | $ | 219 | $ | 264 | |||||||||
Regulatory assets | 212 | 0 | 119 | 9 | 84 | ||||||||||||||
Amortization of intangible assets, net | 48 | 43 | 5 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities(a) | 430 | 507 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel(a) | 921 | 921 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 275 | 275 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 3,779 | $ | 2,559 | $ | 669 | $ | 228 | $ | 348 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,712 | $ | 733 | $ | 525 | $ | 207 | $ | 245 | |||||||||
Regulatory assets | 129 | 0 | 80 | 10 | 53 | ||||||||||||||
Amortization of intangible assets, net | 40 | 35 | 5 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities(a) | 1,110 | 1,110 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel(a) | 848 | 848 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 240 | 240 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 4,079 | $ | 2,966 | $ | 610 | $ | 217 | $ | 298 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization and accretion | |||||||||||||||||||
Property, plant and equipment | $ | 1,284 | $ | 570 | $ | 502 | $ | 191 | $ | 224 | |||||||||
Regulatory assets | 63 | 0 | 52 | 11 | 50 | ||||||||||||||
Nuclear fuel(a) | 755 | 755 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 214 | 214 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization and accretion | $ | 2,316 | $ | 1,539 | $ | 554 | $ | 202 | $ | 274 | |||||||||
(a) Included in revenues or fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 866 | $ | 291 | $ | 283 | $ | 95 | $ | 130 | |||||||||
Income taxes (net of refunds) | 112 | -18 | 33 | 70 | 42 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 825 | $ | 345 | $ | 308 | $ | 43 | $ | 56 | |||||||||
Earnings from equity method investments | -10 | -10 | 0 | 0 | 0 | ||||||||||||||
Provision for uncollectible accounts | 101 | 10 | -15 | 61 | 44 | ||||||||||||||
Provision for excess and obsolete inventory | 9 | 9 | 0 | 0 | 0 | ||||||||||||||
Stock-based compensation costs | 120 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -169 | -169 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 104 | 104 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 12 | 0 | 9 | 3 | 0 | ||||||||||||||
Amortization of rate stabilization deferral | 66 | 0 | 0 | 0 | 66 | ||||||||||||||
Amortization of debt fair value adjustment | -34 | -34 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | -271 | 0 | -271 | 0 | 0 | ||||||||||||||
Amortization of debt costs | 18 | 10 | 1 | 2 | 2 | ||||||||||||||
Impairment of investments in direct financing leases (e) | 14 | 0 | 0 | 0 | 0 | ||||||||||||||
Impairment charges (f) | 149 | 149 | 0 | 0 | 0 | ||||||||||||||
Other | -58 | 0 | -4 | -1 | -15 | ||||||||||||||
Total other non-cash operating activities | $ | 876 | $ | 414 | $ | 28 | $ | 108 | $ | 153 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 12 | $ | 0 | $ | -35 | $ | 9 | $ | 38 | |||||||||
Other regulatory assets and liabilities | -64 | 0 | -43 | -16 | -71 | ||||||||||||||
Other current assets | -165 | -151 | -2 | 13 | -8 | ||||||||||||||
Other noncurrent assets and liabilities | 319 | 15 | 268 | (g) | -12 | -23 | |||||||||||||
Total changes in other assets and liabilities | $ | 102 | $ | -136 | $ | 188 | $ | -6 | $ | -64 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | -128 | $ | -128 | $ | 0 | $ | 0 | $ | 4 | |||||||||
Change in capital expenditures not paid | -38 | -107 | (h) | -8 | 13 | -48 | |||||||||||||
Consolidated VIE dividend to non-controlling interest | 63 | 63 | 0 | 0 | 0 | ||||||||||||||
Indemnification of like-kind exchange position (i) | 0 | 0 | 176 | 0 | 0 | ||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(e) Relates to an other than temporary decline in the estimated residual value of one of Exelon's direct financing leases. See Note 8 – Impairment of Long-Lived Assets for more information. | |||||||||||||||||||
(f) Relates to the cancellation of uprate projects and write down of certain wind projects at Generation. See Note 8 – Impairment of Long-Lived Assets for more information. | |||||||||||||||||||
(g) Relates primarily to interest payable related to like-kind exchange tax position. See Note 14 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
(h) Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | |||||||||||||||||||
(i) See Note 14 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 761 | $ | 286 | $ | 288 | $ | 113 | $ | 136 | |||||||||
Income taxes (net of refunds) | -171 | 175 | -42 | -64 | -112 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 820 | $ | 341 | $ | 282 | $ | 50 | $ | 57 | |||||||||
Loss in equity method investments | 91 | 91 | 0 | 0 | 0 | ||||||||||||||
Provision for uncollectible accounts | 164 | 22 | 42 | 60 | 44 | ||||||||||||||
Provision for excess and obsolete inventory | 6 | 6 | 1 | 0 | 0 | ||||||||||||||
Stock-based compensation costs | 94 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -145 | -145 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 160 | 160 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 18 | 0 | 13 | 3 | 2 | ||||||||||||||
Amortization of rate stabilization deferral | 57 | 0 | 0 | 0 | 67 | ||||||||||||||
Amortization of debt fair value adjustment | -34 | -34 | 0 | 0 | 0 | ||||||||||||||
Merger-related commitments (d) | 141 | 32 | 0 | 0 | 27 | ||||||||||||||
Severance costs | 99 | 34 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | -96 | 0 | -96 | 0 | 0 | ||||||||||||||
Amortization of debt costs | 19 | 11 | 5 | 3 | 2 | ||||||||||||||
Other | -11 | 19 | 5 | 9 | -6 | ||||||||||||||
Total other non-cash operating activities | $ | 1,383 | $ | 537 | $ | 252 | $ | 125 | $ | 193 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 71 | $ | 0 | $ | 28 | $ | 20 | $ | 26 | |||||||||
Other regulatory assets and liabilities | -404 | 0 | -68 | 18 | -112 | ||||||||||||||
Other current assets | 213 | -30 | -7 | -12 | -7 | ||||||||||||||
Other noncurrent assets and liabilities | -248 | -98 | -95 | -10 | 8 | ||||||||||||||
Total changes in other assets and liabilities | $ | -368 | $ | -128 | $ | -142 | $ | 16 | $ | -85 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | 781 | $ | 781 | $ | 2 | $ | 0 | $ | 0 | |||||||||
Change in capital expenditures not paid | 160 | 103 | (e) | 15 | 26 | -4 | |||||||||||||
Merger with Constellation, common stock issued | 7,365 | 5,264 | 0 | 0 | 0 | ||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(d) Relates to the integration costs to achieve distribution synergies related to the merger transaction. See Note 4 – Mergers and Acquisitions for more information on merger-related commitments. | |||||||||||||||||||
(e) Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | |||||||||||||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 649 | $ | 158 | $ | 296 | $ | 128 | $ | 122 | |||||||||
Income taxes (net of refunds) | -457 | 347 | -676 | -65 | -54 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 542 | $ | 249 | $ | 213 | $ | 32 | $ | 51 | |||||||||
Provision for uncollectible accounts | 121 | 0 | 57 | 64 | 44 | ||||||||||||||
Stock-based compensation costs | 67 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | 16 | 16 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 137 | 137 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 21 | 0 | 18 | 3 | 2 | ||||||||||||||
Amortization of rate stabilization deferral | 0 | 0 | 0 | 0 | 57 | ||||||||||||||
Deferral of storm costs | 0 | 0 | 0 | 0 | -16 | ||||||||||||||
Uncollectible accounts recovery, net | 14 | 0 | 14 | 0 | 0 | ||||||||||||||
Discrete impacts from 2010 Rate Case Order (c) | -32 | 0 | -32 | 0 | 0 | ||||||||||||||
Bargain purchase gain related to Wolf Hollow Acquisition | -36 | -36 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (d) | -82 | 0 | -82 | 0 | 0 | ||||||||||||||
Other | 2 | 55 | -4 | 1 | -9 | ||||||||||||||
Total other non-cash operating activities | $ | 770 | $ | 421 | $ | 184 | $ | 100 | $ | 129 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -45 | $ | 0 | $ | -49 | $ | 4 | $ | -52 | |||||||||
Other regulatory assets and liabilities | 0 | 0 | 44 | 26 | 10 | ||||||||||||||
Other current assets | -101 | -23 | -14 | -12 | -88 | ||||||||||||||
Other noncurrent assets and liabilities | 122 | -34 | 64 | -4 | -31 | ||||||||||||||
Total changes in other assets and liabilities | $ | -24 | $ | -57 | $ | 45 | $ | 14 | $ | -161 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | 186 | $ | 186 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Change in capital expenditures not paid | 96 | 125 | (e) | 7 | -35 | -7 | |||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 3 - Regulatory Matters for more information. | |||||||||||||||||||
(d) Includes the establishment of a regulatory asset, pursuant to EIMA, for the 2011 annual reconciliation in ComEd's distribution formula rate tariff and the deferral of costs associated with significant 2011 storms, partially offset by an accrual to fund a new Science and Technology Innovation Trust. See Note 3 - Regulatory Matters for more information. | |||||||||||||||||||
(e) Includes $120 million of changes in capital expenditures not paid between December 31, 2011 and 2010 related to Antelope Valley. | |||||||||||||||||||
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, respectively, and reimbursements of $95 million, $37 million and $58 million, respectively, related to PECO's and BGE's DOE SGIG programs. For the year ended December 31, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $103 million, $56 million and $47 million, respectively, and reimbursements of $113 million, $66 million and $47 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 3 - Regulatory Matters for additional information regarding the DOE SGIG. | |||||||||||||||||||
Supplemental Balance Sheet Information | |||||||||||||||||||
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2013 and 2012. | |||||||||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Investments | |||||||||||||||||||
Equity method investments: | |||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | 0 | $ | 6 | $ | 8 | $ | 8 | |||||||||
Keystone Fuels, LLC | 32 | 32 | 0 | 0 | 0 | ||||||||||||||
Conemaugh Fuels, LLC | 21 | 21 | 0 | 0 | 0 | ||||||||||||||
CENG | 1,925 | 1,925 | 0 | 0 | 0 | ||||||||||||||
Safe Harbor | 285 | 285 | 0 | 0 | 0 | ||||||||||||||
Malacha | 8 | 8 | 0 | 0 | 0 | ||||||||||||||
Other investments | 31 | 31 | 0 | 0 | 0 | ||||||||||||||
Total equity method investments | 2,324 | 2,302 | 6 | 8 | 8 | ||||||||||||||
Other investments: | |||||||||||||||||||
Net investment in direct financing leases | 698 | 0 | 0 | 0 | 0 | ||||||||||||||
Employee benefit trusts and investments (b) | 90 | 23 | 5 | 23 | 5 | ||||||||||||||
Total investments | $ | 3,112 | $ | 2,325 | $ | 11 | $ | 31 | $ | 13 | |||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Investments | |||||||||||||||||||
Equity method investments: | |||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | 0 | $ | 6 | $ | 8 | $ | 8 | |||||||||
Keystone Fuels, LLC | 38 | 38 | 0 | 0 | 0 | ||||||||||||||
Conemaugh Fuels, LLC | 26 | 26 | 0 | 0 | 0 | ||||||||||||||
CENG | 1,849 | 1,849 | 0 | 0 | 0 | ||||||||||||||
Safe Harbor | 293 | 293 | 0 | 0 | 0 | ||||||||||||||
Malacha | 8 | 8 | 0 | 0 | 0 | ||||||||||||||
Other investments | 34 | 33 | 0 | 0 | 0 | ||||||||||||||
Total equity method investments | 2,270 | 2,247 | 6 | 8 | 8 | ||||||||||||||
Other investments: | |||||||||||||||||||
Net investment in direct financing leases | 685 | 0 | 0 | 0 | 0 | ||||||||||||||
Employee benefit trusts and investments (b) | 100 | 22 | 8 | 22 | 5 | ||||||||||||||
Total investments | $ | 3,055 | $ | 2,269 | $ | 14 | $ | 30 | $ | 13 | |||||||||
(a) Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the Consolidated Balance Sheets. See Note 1 - Significant Accounting Policies for additional information. | |||||||||||||||||||
(b) The Registrants' investments in these marketable securities are recorded at fair market value. | |||||||||||||||||||
The following tables provide additional information about liabilities of the Registrants at December 31, 2013 and 2012. | |||||||||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Accrued expenses | |||||||||||||||||||
Compensation-related accruals (a) | $ | 683 | $ | 337 | $ | 135 | $ | 47 | $ | 55 | |||||||||
Taxes accrued | 315 | 212 | 62 | 24 | 16 | ||||||||||||||
Interest accrued | 234 | 72 | 95 | 32 | 29 | ||||||||||||||
Severance accrued | 66 | 31 | 3 | 1 | 4 | ||||||||||||||
Other accrued expenses | 335 | (b) | 324 | (b) | 12 | 2 | 7 | ||||||||||||
Total accrued expenses | $ | 1,633 | $ | 976 | $ | 307 | $ | 106 | $ | 111 | |||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Accrued expenses | |||||||||||||||||||
Compensation-related accruals (a) | $ | 708 | $ | 371 | $ | 125 | $ | 45 | $ | 38 | |||||||||
Taxes accrued | 353 | 247 | 61 | 3 | 22 | ||||||||||||||
Interest accrued | 232 | 60 | 96 | 32 | 37 | ||||||||||||||
Severance accrued | 91 | 42 | 4 | 1 | 5 | ||||||||||||||
Other accrued expenses | 412 | (b) | 396 | (b) | 9 | 1 | 0 | ||||||||||||
Total accrued expenses | $ | 1,796 | $ | 1,116 | $ | 295 | $ | 82 | $ | 102 | |||||||||
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. | ||||||||||||||||||
(b) | Includes $228 million and $327 million for amounts accrued related to Antelope Valley as of December 31, 2013 and December 31, 2012, respectively. |
Segment_Information_Exelon_Gen
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||
Segment Information [Line Items] | ' | ||||||||||||||||||||||||||
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||||||||||
24. Segment Information (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants. | |||||||||||||||||||||||||||
Exelon has nine reportable segments, ComEd, PECO, BGE and Generation's six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. Generation's expanded number of reportable segments is the result of the acquisition of Constellation on March 12, 2012. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon evaluates the performance of ComEd, PECO and BGE based on net income. | |||||||||||||||||||||||||||
The CODMs for ComEd, PECO, and BGE evaluate performance and allocate resources for their respective companies based on net income and return on equity for ComEd, PECO, and BGE each as single integrated businesses. | |||||||||||||||||||||||||||
The foundation of Generation's six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation's six reportable segments are as follows: | |||||||||||||||||||||||||||
Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina. | |||||||||||||||||||||||||||
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO's Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky. | |||||||||||||||||||||||||||
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. | |||||||||||||||||||||||||||
New York represents operations within ISO-NY, which covers the state of New York in its entirety. | |||||||||||||||||||||||||||
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas. | |||||||||||||||||||||||||||
Other Regions not considered individually significant: | |||||||||||||||||||||||||||
South represents operations in the FRCC, MISO's Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation's South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas. | |||||||||||||||||||||||||||
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota. | |||||||||||||||||||||||||||
Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO. | |||||||||||||||||||||||||||
The CODMs for Exelon and Generation evaluate the performance of Generation's power marketing activities and allocate resources based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation's operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation's own generation and fuel costs associated with tolling agreements. Generation's other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency and demand response, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, and investments in energy-related proprietary technology are not allocated to regions. Further, Generation's compensation under the reliability-must-run rate schedule, results of operations from the Brandon Shores, Wagner, and C.P. Crane Maryland generating stations, and other miscellaneous revenues, mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger are also not allocated to a region. | |||||||||||||||||||||||||||
An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2013, 2012 and 2011 is as follows: | |||||||||||||||||||||||||||
Intersegment | |||||||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE(b) | Other(c) | Eliminations | Exelon | |||||||||||||||||||||
Operating revenues(d): | |||||||||||||||||||||||||||
2013 | $ | 15,630 | $ | 4,464 | $ | 3,100 | $ | 3,065 | $ | 1,241 | $ | -2,612 | $ | 24,888 | |||||||||||||
2012 | 14,437 | 5,443 | 3,186 | 2,091 | 1,396 | -3,064 | 23,489 | ||||||||||||||||||||
2011 | 10,447 | 6,056 | 3,720 | 0 | 830 | -1,990 | 19,063 | ||||||||||||||||||||
Intersegment revenues(e): | |||||||||||||||||||||||||||
2013 | $ | 1,367 | $ | 3 | $ | 1 | $ | 13 | $ | 1,237 | $ | -2,607 | $ | 14 | |||||||||||||
2012 | 1,660 | 2 | 3 | 9 | 1,381 | -3,049 | 6 | ||||||||||||||||||||
2011 | 1,161 | 2 | 5 | 0 | 831 | -1,990 | 9 | ||||||||||||||||||||
Depreciation and amortization | |||||||||||||||||||||||||||
2013 | $ | 856 | $ | 669 | $ | 228 | $ | 348 | $ | 52 | $ | 0 | $ | 2,153 | |||||||||||||
2012 | 768 | 610 | 217 | 238 | 48 | 0 | 1,881 | ||||||||||||||||||||
2011 | 570 | 554 | 202 | 0 | 21 | 0 | 1,347 | ||||||||||||||||||||
Operating expenses(d): | |||||||||||||||||||||||||||
2013 | $ | 13,976 | $ | 3,510 | $ | 2,434 | $ | 2,616 | $ | 1,324 | $ | -2,618 | $ | 21,242 | |||||||||||||
2012 | 13,226 | 4,557 | 2,563 | 2,053 | 1,662 | -3,043 | 21,018 | ||||||||||||||||||||
2011 | 7,571 | 5,074 | 3,065 | 0 | 863 | -1,990 | 14,583 | ||||||||||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | |||||||||||||||||||||||||||
2013 | $ | 10 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 10 | |||||||||||||
2012 | -91 | 0 | 0 | 0 | 0 | 0 | -91 | ||||||||||||||||||||
2011 | -1 | 0 | 0 | 0 | 0 | 0 | -1 | ||||||||||||||||||||
Interest expense, net: | |||||||||||||||||||||||||||
2013 | $ | 357 | $ | 579 | $ | 115 | $ | 122 | $ | 183 | $ | 0 | $ | 1,356 | |||||||||||||
2012 | 301 | 307 | 123 | 111 | 86 | 0 | 928 | ||||||||||||||||||||
2011 | 170 | 345 | 134 | 0 | 77 | 0 | 726 | ||||||||||||||||||||
Income (loss) before income taxes: | |||||||||||||||||||||||||||
2013 | $ | 1,675 | $ | 401 | $ | 557 | $ | 344 | $ | -191 | $ | -13 | $ | 2,773 | |||||||||||||
2012 | 1,058 | 618 | 508 | -54 | -325 | -7 | 1,798 | ||||||||||||||||||||
2011 | 2,827 | 666 | 535 | 0 | -59 | -13 | 3,956 | ||||||||||||||||||||
Income taxes: | |||||||||||||||||||||||||||
2013 | $ | 615 | $ | 152 | $ | 162 | $ | 134 | $ | -20 | $ | 1 | $ | 1,044 | |||||||||||||
2012 | 500 | 239 | 127 | -23 | -215 | -1 | 627 | ||||||||||||||||||||
2011 | 1,056 | 250 | 146 | 0 | 9 | -4 | 1,457 | ||||||||||||||||||||
Net income (loss): | |||||||||||||||||||||||||||
2013 | $ | 1,060 | $ | 249 | $ | 395 | $ | 210 | $ | -171 | $ | -14 | $ | 1,729 | |||||||||||||
2012 | 558 | 379 | 381 | -31 | -110 | -6 | 1,171 | ||||||||||||||||||||
2011 | 1,771 | 416 | 389 | 0 | -68 | -9 | 2,499 | ||||||||||||||||||||
Capital expenditures: | |||||||||||||||||||||||||||
2013 | $ | 2,752 | $ | 1,433 | $ | 537 | $ | 587 | $ | 86 | $ | 0 | $ | 5,395 | |||||||||||||
2012 | 3,554 | 1,246 | 422 | 500 | 67 | 0 | 5,789 | ||||||||||||||||||||
2011 | 2,491 | 1,028 | 481 | 0 | 42 | 0 | 4,042 | ||||||||||||||||||||
Total assets: | |||||||||||||||||||||||||||
2013 | $ | 41,232 | $ | 24,118 | $ | 9,617 | $ | 7,861 | $ | 8,317 | $ | -11,221 | $ | 79,924 | |||||||||||||
2012 | 40,681 | 22,905 | 9,353 | 7,506 | 10,432 | -12,316 | 78,561 | ||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the year ended December 31, 2013 include revenue from sales to PECO of $405 and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012 include revenue from sales to PECO of $543 and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended 2011 intersegment revenues for Generation include revenue from sales to PECO of $508 million in the Mid-Atlantic region, and sales to ComEd of $653 million in the Midwest region. | |||||||||||||||||||||||||||
(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2013. | |||||||||||||||||||||||||||
(c) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||||||
(d) For the years ended December 31, 2013, 2012 and 2011, utility taxes of $79 million, $82 million and $27 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2013, 2012 and 2011, utility taxes of $241 million, $239 million and $243 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2013, 2012 and 2011, utility taxes of $129 million, $141 million and $173 million, respectively, are included in revenues and expenses for PECO. For the year ended December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||||||||||||||||
(e) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. | |||||||||||||||||||||||||||
Generation total revenues: | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | |||||||||||||||||||
Mid-Atlantic | $ | 5,182 | $ | 22 | $ | 5,204 | $ | 5,082 | $ | -44 | $ | 5,038 | $ | 4,052 | $ | 0 | $ | 4,052 | |||||||||
Midwest | 4,280 | -10 | 4,270 | 4,824 | 24 | 4,848 | 5,445 | 0 | 5,445 | ||||||||||||||||||
New England | 1,245 | -8 | 1,237 | 1,048 | 45 | 1,093 | 11 | 0 | 11 | ||||||||||||||||||
New York | 735 | -21 | 714 | 582 | -25 | 557 | 0 | 0 | 0 | ||||||||||||||||||
ERCOT | 1,222 | -6 | 1,216 | 1,365 | 2 | 1,367 | 575 | 0 | 575 | ||||||||||||||||||
Other Regions (b) | 946 | 22 | 968 | 755 | 78 | 833 | 201 | 0 | 201 | ||||||||||||||||||
Total Revenues for Reportable Segments | $ | 13,610 | $ | -1 | $ | 13,609 | $ | 13,656 | $ | 80 | $ | 13,736 | $ | 10,284 | $ | 0 | $ | 10,284 | |||||||||
Other (c) | 2,020 | 1 | 2,021 | 781 | -80 | 701 | 163 | 0 | 163 | ||||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 15,630 | $ | 0 | $ | 15,630 | $ | 14,437 | $ | 0 | $ | 14,437 | $ | 10,447 | $ | 0 | $ | 10,447 | |||||||||
(a) Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $767 million and $1,505 million for the years ended December 31, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense: | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | |||||||||||||||||||
Mid-Atlantic | $ | 3,273 | $ | -3 | $ | 3,270 | $ | 3,477 | $ | -44 | $ | 3,433 | $ | 3,350 | $ | 0 | $ | 3,350 | |||||||||
Midwest | 2,585 | 1 | 2,586 | 2,974 | 24 | 2,998 | 3,547 | 0 | 3,547 | ||||||||||||||||||
New England | 217 | -32 | 185 | 151 | 45 | 196 | 9 | 0 | 9 | ||||||||||||||||||
New York | 14 | -18 | -4 | 101 | -25 | 76 | - | 0 | - | ||||||||||||||||||
ERCOT | 604 | -168 | 436 | 403 | 2 | 405 | 84 | 0 | 84 | ||||||||||||||||||
Other Regions (b) | 334 | -133 | 201 | 53 | 78 | 131 | -14 | 0 | -14 | ||||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | $ | 7,027 | $ | -353 | $ | 6,674 | $ | 7,159 | $ | 80 | $ | 7,239 | $ | 6,976 | $ | 0 | $ | 6,976 | |||||||||
Other (c) | 406 | 353 | 759 | 217 | -80 | 137 | -118 | 0 | -118 | ||||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 7,433 | $ | 0 | $ | 7,433 | $ | 7,376 | $ | 0 | $ | 7,376 | $ | 6,858 | $ | 0 | $ | 6,858 | |||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $488 million and $1,098 million, for the years ended December 31, 2013 and 2012, respectively, and the elimination of intersegment revenues. | |||||||||||||||||||||||||||
Related_Party_Transactions_Exe
Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Related-Party Transactions [Line Items] | ' | |||||||||
Related-Party Transactions (Exelon, Generation, ComEd, PECO and BGE) | ' | |||||||||
25. Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||
Exelon | ||||||||||
The financial statements of Exelon include related party transactions as presented in the tables below: | ||||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
PECO (a) | $ | 10 | $ | 6 | $ | 9 | ||||
CENG (b) | 56 | 42 | 0 | |||||||
BGE | 4 | 0 | 0 | |||||||
Total operating revenues from affiliates | $ | 70 | $ | 48 | $ | 9 | ||||
Purchase power and fuel from affiliates: | ||||||||||
CENG (c) | $ | 992 | $ | 793 | $ | 0 | ||||
Keystone Fuels, LLC | 144 | 119 | 68 | |||||||
Conemaugh Fuels, LLC | 98 | 101 | 69 | |||||||
Safe Harbor Water Power Corp | 22 | 23 | 0 | |||||||
Total purchase power and fuel from affiliates | $ | 1,256 | $ | 1,036 | $ | 137 | ||||
Interest expense to affiliates, net: | ||||||||||
ComEd Financing III | $ | 13 | $ | 13 | $ | 13 | ||||
PECO Trust III | 6 | 6 | 6 | |||||||
PECO Trust IV | 6 | 6 | 6 | |||||||
BGE Capital Trust II (f) | 16 | 12 | 0 | |||||||
Total interest expense to affiliates, net | $ | 41 | $ | 37 | $ | 25 | ||||
Earnings (losses) in equity method investments: | ||||||||||
CENG (e) | $ | 9 | $ | -99 | $ | 0 | ||||
Qualifying facilities and domestic power projects | 1 | 8 | -1 | |||||||
Total earnings (losses) in equity method investments | $ | 10 | $ | -91 | $ | -1 | ||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Investments in affiliates: | ||||||||||
ComEd Financing III | $ | 6 | $ | 6 | ||||||
PECO Energy Capital Corporation | 4 | 4 | ||||||||
PECO Trust IV | 4 | 4 | ||||||||
BGE Capital Trust II | 8 | 8 | ||||||||
Total investments in affiliates | $ | 22 | $ | 22 | ||||||
Receivables from affiliates (current): | ||||||||||
CENG (b) | $ | 3 | $ | 16 | ||||||
Payables to affiliates (current): | ||||||||||
CENG (c) | $ | 85 | $ | 83 | ||||||
ComEd Financing III | 4 | 4 | ||||||||
PECO Trust III | 1 | 1 | ||||||||
BGE Capital Trust II | 4 | 4 | ||||||||
Keystone Fuels, LLC | 12 | 11 | ||||||||
Conemaugh Fuels, LLC | 9 | 9 | ||||||||
Other | 1 | 0 | ||||||||
Total payables to affiliates (current) | $ | 116 | $ | 112 | ||||||
Long-term debt due to financing trusts: | ||||||||||
ComEd Financing III | $ | 206 | $ | 206 | ||||||
PECO Trust III | 81 | 81 | ||||||||
PECO Trust IV | 103 | 103 | ||||||||
BGE Capital Trust II | 258 | 258 | ||||||||
Total long-term debt due to financing trusts | $ | 648 | $ | 648 | ||||||
Transactions involving Generation, ComEd, PECO and BGE are further described in the tables below. | ||||||||||
Generation | ||||||||||
The financial statements of Generation include related party transactions as presented in the tables below: | ||||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
ComEd (a) | $ | 506 | $ | 795 | $ | 653 | ||||
PECO (b) | 405 | 543 | 508 | |||||||
BGE (c) | 455 | 322 | 0 | |||||||
CENG (d) | 56 | 42 | 0 | |||||||
BSC | 1 | 0 | 0 | |||||||
Total operating revenues from affiliates | $ | 1,423 | $ | 1,702 | $ | 1,161 | ||||
Purchase power and fuel from affiliates: | ||||||||||
PECO | $ | 0 | $ | 0 | $ | 1 | ||||
ComEd | 1 | 0 | 0 | |||||||
BGE | 13 | 8 | 0 | |||||||
CENG (e) | 992 | 793 | 0 | |||||||
Keystone Fuels, LLC | 144 | 119 | 68 | |||||||
Conemaugh Fuels, LLC | 98 | 101 | 69 | |||||||
Safe Harbor Water Power Corporation | 22 | 23 | 0 | |||||||
Total purchase power and fuel from affiliates | $ | 1,270 | $ | 1,044 | $ | 138 | ||||
Operating and maintenance from affiliates: | ||||||||||
ComEd (f) | $ | 2 | $ | 2 | $ | 2 | ||||
PECO (f) | 1 | 3 | 5 | |||||||
BSC (g) | 571 | 625 | 314 | |||||||
Total operating and maintenance from affiliates | $ | 574 | $ | 630 | $ | 321 | ||||
Interest expense to affiliates, net: | ||||||||||
Exelon Corporate | $ | 59 | $ | 75 | $ | 0 | ||||
Earnings (losses) in equity method investments | ||||||||||
CENG (h) | 9 | -99 | 0 | |||||||
Qualifying facilities and domestic power projects | 1 | 8 | -1 | |||||||
Total earnings (losses) in equity method investments | $ | 10 | $ | -91 | $ | -1 | ||||
Cash distribution paid to member | $ | 625 | $ | 1,626 | $ | 172 | ||||
Contribution from member | $ | 26 | $ | 48 | $ | 30 | ||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Mark-to-market derivative assets with affiliates (current): | ||||||||||
ComEd (i) | $ | 0 | $ | 226 | ||||||
Receivables from affiliates (current): | ||||||||||
CENG (d) | $ | 3 | $ | 0 | ||||||
ComEd (a)(j) | 38 | 54 | ||||||||
PECO (b) | 38 | 56 | ||||||||
BGE (c) | 27 | 31 | ||||||||
Other | 2 | 0 | ||||||||
Total receivables from affiliates (current) | $ | 108 | $ | 141 | ||||||
Receivable from affiliate (noncurrent) | ||||||||||
Exelon Corporate | $ | 0 | $ | 1 | ||||||
Payables to affiliates (current): | ||||||||||
CENG (e) | $ | 85 | $ | 83 | ||||||
Exelon Corporate (k) | 7 | 33 | ||||||||
BSC (g) | 66 | 77 | ||||||||
Keystone Fuels, LLC | 12 | 11 | ||||||||
Conemaugh Fuels, LLC | 9 | 9 | ||||||||
Other | 2 | 0 | ||||||||
Total payables to affiliates (current) | $ | 181 | $ | 213 | ||||||
Payables to affiliates (noncurrent): | ||||||||||
ComEd (l) | $ | 2,293 | $ | 2,037 | ||||||
PECO (l) | 447 | 360 | ||||||||
Total payables to affiliates (noncurrent) | $ | 2,740 | $ | 2,397 | ||||||
(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(b) Generation provides electric supply to PECO under contracts executed through PECO's competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(d) Exelon has a shared services agreement with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. In addition to the SSA, Generation has a power services agency agreement with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. At the closing, as described under the Master Agreement, the PSAA will be amended and extended until the complete and permanent cessation of operation of the CENG generation plants. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(e) CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Generation has a PPA under which it is purchasing 85% of the nuclear plant output owned by CENG that is not sold to third parties under pre-existing firm and unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG. This agreement will continue to be effective and is not affected by the Master Agreement, except that if the put option under the Master Agreement is exercised, then the EDF PPA would transfer to Generation upon completion of the Put Option Agreement transaction. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(f) Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. | ||||||||||
(g) Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(h) Generation's total gain (loss) in equity method investments includes equity income (loss) and amortization of basis difference. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(i) Represents the fair value of Generation's five-year financial swap contract with ComEd, which ended in 2013. | ||||||||||
(j) Generation had a $53 million receivable from ComEd at December 31, 2012 associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | ||||||||||
(k) As of December 31, 2013 and 2012, the balance consists of interest owed to Exelon Corporation related to the senior unsecured notes. In addition, the balance at December 31, 2012, includes expense related to certain invoices Exelon Corporation processed on behalf of Generation. | ||||||||||
(l) Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15 - Asset Retirement Obligations. | ||||||||||
ComEd | ||||||||||
The financial statements of ComEd include related party transactions as presented in the tables below: | ||||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates | ||||||||||
Generation | $ | 3 | $ | 2 | $ | 2 | ||||
Purchased power from affiliate | ||||||||||
Generation (a) | $ | 512 | $ | 789 | $ | 653 | ||||
Operating and maintenance from affiliate | ||||||||||
BSC (b) | $ | 157 | $ | 163 | $ | 158 | ||||
Interest expense to affiliates, net: | ||||||||||
Exelon Corporate | $ | 0 | $ | 0 | $ | 2 | ||||
ComEd Financing III | 13 | 13 | 13 | |||||||
Total interest expense to affiliates, net | $ | 13 | $ | 13 | $ | 15 | ||||
Capitalized costs | ||||||||||
BSC (b) | $ | 69 | $ | 92 | $ | 85 | ||||
Cash dividends paid to parent | $ | 220 | $ | 105 | $ | 300 | ||||
Contribution from parent | $ | 0 | $ | 11 | $ | 11 | ||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (c) | $ | 13 | $ | 10 | ||||||
Investment in affiliate | ||||||||||
ComEd Financing III | $ | 6 | $ | 6 | ||||||
Receivable from affiliates (current): | ||||||||||
Voluntary employee beneficiary association trust | $ | 3 | $ | 0 | ||||||
BGE | 0 | 3 | ||||||||
Total receivable from affiliates (current) | $ | 3 | $ | 3 | ||||||
Receivable from affiliates (noncurrent): | ||||||||||
Generation (d) | $ | 2,293 | $ | 2,037 | ||||||
Exelon Corporate (g) | 176 | 2 | ||||||||
Total receivable from affiliates (noncurrent) | $ | 2,469 | $ | 2,039 | ||||||
Payables to affiliates (current): | ||||||||||
Generation (a)(e) | $ | 38 | $ | 54 | ||||||
BSC (b) | 30 | 35 | ||||||||
ComEd Financing III | 4 | 4 | ||||||||
Exelon Corporate | 9 | 2 | ||||||||
Other | 2 | 2 | ||||||||
Total payables to affiliates (current) | $ | 83 | $ | 97 | ||||||
Mark-to-market derivative liability with affiliate (current) | ||||||||||
Generation (f) | $ | 0 | $ | 226 | ||||||
Mark-to-market derivative liability with affiliate (noncurrent) | ||||||||||
Long-term debt to ComEd financing trust | ||||||||||
ComEd Financing III | $ | 206 | $ | 206 | ||||||
____________________ | ||||||||||
(a) ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | ||||||||||
(b) ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(c) The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd's contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets. | ||||||||||
(d) ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd's customers. | ||||||||||
(e) ComEd had a $53 million payable to Generation at December 31, 2012, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Information for additional information. | ||||||||||
(f) To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation, which ended in 2013. | ||||||||||
(g) In 2013, represents indemnification from Exelon Corporate related to the like-kind exchange transaction. | ||||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
Generation (a) | $ | 1 | $ | 3 | $ | 5 | ||||
Purchased power from affiliate | ||||||||||
Generation (b) | $ | 392 | $ | 533 | $ | 495 | ||||
Operating and maintenance from affiliates: | ||||||||||
BSC (c) | $ | 98 | $ | 107 | $ | 92 | ||||
Generation | 3 | 4 | 4 | |||||||
Total operating and maintenance from affiliates | $ | 101 | $ | 111 | $ | 96 | ||||
Interest expense to affiliates, net: | ||||||||||
PECO Trust III | $ | 6 | $ | 6 | $ | 6 | ||||
PECO Trust IV | 6 | 6 | 6 | |||||||
Total interest expense to affiliates, net | $ | 12 | $ | 12 | $ | 12 | ||||
Loss in equity method investments | ||||||||||
Capitalized costs | ||||||||||
BSC (c) | $ | 46 | $ | 54 | $ | 60 | ||||
Cash dividends paid to parent | $ | 332 | $ | 343 | $ | 348 | ||||
Contribution from parent | $ | 27 | $ | 9 | $ | 18 | ||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 3 | $ | 2 | ||||||
Investments in affiliates: | ||||||||||
PECO Energy Capital Corporation | $ | 4 | $ | 4 | ||||||
PECO Trust IV | 4 | 4 | ||||||||
Total investments in affiliates | $ | 8 | $ | 8 | ||||||
Receivable from affiliate (noncurrent): | ||||||||||
BGE | $ | 3 | $ | 2 | ||||||
Receivable from affiliate (noncurrent): | ||||||||||
Generation (e) | $ | 447 | $ | 360 | ||||||
Mark-to-market derivative liability with affiliate (current): | ||||||||||
Payables to affiliates (current): | ||||||||||
Generation (b) | $ | 38 | $ | 56 | ||||||
BSC (c) | 17 | 18 | ||||||||
Exelon Corporate | 2 | 1 | ||||||||
PECO Trust III | 1 | 1 | ||||||||
Total payables to affiliates (current) | $ | 58 | $ | 76 | ||||||
Long-term debt to financing trusts: | ||||||||||
PECO Trust III | $ | 81 | $ | 81 | ||||||
PECO Trust IV | 103 | 103 | ||||||||
Total long-term debt to financing trusts | $ | 184 | $ | 184 | ||||||
________ | ||||||||||
(a) PECO provides energy to Generation for Generation's own use. | ||||||||||
(b) PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs. | ||||||||||
(c) PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(d) The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time. | ||||||||||
(e) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers. | ||||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
Generation (a) | $ | 13 | $ | 10 | $ | 8 | ||||
Purchased power from affiliate | ||||||||||
Generation (b) | $ | 452 | $ | 396 | $ | 348 | ||||
Operating and maintenance from affiliates: | ||||||||||
BSC (c) | $ | 83 | $ | 106 | $ | 150 | ||||
Interest expense to affiliates, net: | ||||||||||
BGE Capital Trust II | $ | 16 | $ | 16 | $ | 16 | ||||
Capitalized costs | ||||||||||
BSC (c) | $ | 15 | $ | 21 | $ | 29 | ||||
Cash dividends paid to parent | $ | 0 | $ | 0 | $ | -85 | ||||
Contribution from parent | $ | 0 | $ | 66 | $ | 0 | ||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 1 | $ | 0 | ||||||
Investments in affiliates: | ||||||||||
BGE Capital Trust II | $ | 8 | $ | 8 | ||||||
Payables to affiliates (current): | ||||||||||
Generation (b) | $ | 27 | $ | 31 | ||||||
BSC (c) | 20 | 12 | ||||||||
Exelon (d) | 1 | 17 | ||||||||
ComEd | 0 | 3 | ||||||||
PECO | 3 | 2 | ||||||||
BGE Capital Trust II | 4 | 4 | ||||||||
Total payables to affiliates (current) | $ | 55 | $ | 69 | ||||||
Long-term debt to BGE financing trust | ||||||||||
BGE Capital Trust II | $ | 258 | $ | 258 | ||||||
Quarterly_Data_Exelon_Generati
Quarterly Data (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Quarterly Financial Information [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Text Block (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||||||||||
26. Quarterly Data (Unaudited) (Exelon, Generation, ComEd and PECO) | |||||||||||||||||||
Exelon | |||||||||||||||||||
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts: | |||||||||||||||||||
Net (Loss) Income | |||||||||||||||||||
on Common | |||||||||||||||||||
Operating Revenues | Operating Income | Stock | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 6,082 | $ | 4,690 | $ | 508 | $ | 359 | $ | -4 | $ | 200 | |||||||
30-Jun | 6,141 | 5,966 | 1,005 | 714 | 490 | 286 | |||||||||||||
30-Sep | 6,502 | 6,579 | 1,254 | 603 | 738 | 296 | |||||||||||||
31-Dec | 6,163 | 6,254 | 889 | 704 | 495 | 378 | |||||||||||||
Average Basic Shares | |||||||||||||||||||
Outstanding | Net (Loss) Income | ||||||||||||||||||
(in millions) | per Basic Share | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | 855 | 705 | $ | -0.01 | $ | 0.28 | |||||||||||||
30-Jun | 856 | 853 | 0.57 | 0.34 | |||||||||||||||
30-Sep | 857 | 854 | 0.86 | 0.35 | |||||||||||||||
31-Dec | 856 | 854 | 0.6 | 0.44 | |||||||||||||||
Average Diluted Shares | |||||||||||||||||||
Outstanding | Net (Loss) Income | ||||||||||||||||||
(in millions) | per Diluted Share | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | 855 | 707 | $ | -0.01 | $ | 0.28 | |||||||||||||
30-Jun | 860 | 856 | 0.57 | 0.33 | |||||||||||||||
30-Sep | 860 | 857 | 0.86 | 0.35 | |||||||||||||||
31-Dec | 860 | 857 | 0.59 | 0.44 | |||||||||||||||
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis: | |||||||||||||||||||
2013 | 2012 | ||||||||||||||||||
Fourth | Third | Second | First | Fourth | Third | Second | First | ||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||
High price | $ | 30.59 | $ | 32.42 | $ | 37.8 | $ | 34.56 | $ | 37.5 | $ | 39.82 | $ | 39.37 | $ | 43.7 | |||
Low price | 26.64 | 29.42 | 29.84 | 29.1 | 28.4 | 34.54 | 36.27 | 38.31 | |||||||||||
Close | 27.39 | 29.64 | 30.88 | 34.48 | 29.74 | 35.58 | 37.62 | 39.21 | |||||||||||
Dividends | 0.31 | 0.31 | 0.31 | 0.525 | 0.525 | 0.525 | 0.525 | 0.525 | |||||||||||
Generation | |||||||||||||||||||
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts: | |||||||||||||||||||
Net (Loss) Income | |||||||||||||||||||
on Membership | |||||||||||||||||||
Operating Revenues | Operating (Loss) Income | Interest | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 3,533 | $ | 2,743 | $ | -64 | $ | 272 | $ | -18 | $ | 168 | |||||||
30-Jun | 4,070 | 3,765 | 603 | 384 | 330 | 166 | |||||||||||||
30-Sep | 4,255 | 4,031 | 721 | 174 | 490 | 91 | |||||||||||||
31-Dec | 3,772 | 3,898 | 405 | 290 | 269 | 137 | |||||||||||||
ComEd | |||||||||||||||||||
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts: | |||||||||||||||||||
Operating Revenues | Operating Income | Net (Loss) Income | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 1,160 | $ | 1,388 | $ | 209 | $ | 226 | $ | -81 | $ | 87 | |||||||
30-Jun | 1,080 | 1,281 | 232 | 142 | 96 | 42 | |||||||||||||
30-Sep | 1,156 | 1,484 | 278 | 218 | 126 | 90 | |||||||||||||
31-Dec | 1,068 | 1,290 | 236 | 300 | 109 | 160 | |||||||||||||
PECO | |||||||||||||||||||
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts: | |||||||||||||||||||
Net Income | |||||||||||||||||||
on Common | |||||||||||||||||||
Operating Revenues | Operating Income | Stock | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 895 | $ | 875 | $ | 203 | $ | 177 | $ | 121 | $ | 96 | |||||||
30-Jun | 672 | 715 | 138 | 151 | 72 | 79 | |||||||||||||
30-Sep | 728 | 806 | 155 | 178 | 92 | 122 | |||||||||||||
31-Dec | 805 | 790 | 168 | 117 | 102 | 79 | |||||||||||||
BGE | |||||||||||||||||||
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts: | |||||||||||||||||||
Net Income (Loss) | |||||||||||||||||||
Operating | attributable to | ||||||||||||||||||
Operating Revenues | Income (Loss) | Common Shareholders | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 880 | $ | 697 | $ | 163 | $ | -11 | $ | 77 | $ | -33 | |||||||
30-Jun | 653 | 616 | 69 | 52 | 22 | 13 | |||||||||||||
30-Sep | 737 | 720 | 114 | 30 | 50 | -4 | |||||||||||||
31-Dec | 794 | 703 | 101 | 61 | 47 | 15 |
Subsequent_Events_Exelon_PECO_
Subsequent Events (Exelon, PECO and BGE) | 12 Months Ended |
Dec. 31, 2013 | |
Subsequent Events Disclosure [Line Items] | ' |
Schedule Of Subsequent Events Text Block (Exelon, PECO and BGE) | ' |
27. Subsequent Events (Exelon and PECO) | |
On February 5, 2014, a winter storm which brought a mix of snow, ice and freezing rain to the region interrupted electric service delivery to nearly 715,000 customers in PECO's service territory. Restoration efforts are continuing and will include significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies. PECO estimates that restoration efforts will have a material impact to Exelon's and PECO's results of operations and cash flows for the first quarter of 2014. | |
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
Significant Accounting Policies [Line Items] | ' |
Consolidation, Policy [Text Block] | ' |
Use of Estimates (Exelon, Generation, ComEd, PECO and BGE) | |
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. | |
Reclassifications (Exelon, ComEd, and BGE) | |
Certain prior year amounts in Exelon's and BGE's Consolidated Statements of Operations and Cash Flows, and Exelon's, ComEd's, and BGE's Consolidated Balance Sheets have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. | |
In 2013, Exelon and BGE identified a presentation errors of $12 million and $16 million on their Statements of Operations and Comprehensive Income, respectively related to its financing trusts within interest expense that is now presented within Interest expense to affiliates, net. Additionally, Exelon identified similar presentation errors of $92 million between Accounts payable, Accrued expenses and Payables to affiliates on its Balance Sheet. Generation identified a related presentation error of $83 million between Accounts payable and Payables to affiliates on its Balance Sheet. BGE identified a related presentation error of $4 million between Accrued expenses and Payables to affiliates on its Balance Sheet. Similar adjustments are also reflected on the related party transactions footnote. | |
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) | |
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities' costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd's, PECO's or BGE's business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information. | |
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order. | |
. | |
Use Of Estimates | ' |
Use of Estimates (Exelon, Generation, ComEd, PECO and BGE) | |
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. | |
Reclassifications | ' |
Reclassifications (Exelon, ComEd, and BGE) | |
Certain prior year amounts in Exelon's and BGE's Consolidated Statements of Operations and Cash Flows, and Exelon's, ComEd's, and BGE's Consolidated Balance Sheets have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. | |
In 2013, Exelon and BGE identified a presentation errors of $12 million and $16 million on their Statements of Operations and Comprehensive Income, respectively related to its financing trusts within interest expense that is now presented within Interest expense to affiliates, net. Additionally, Exelon identified similar presentation errors of $92 million between Accounts payable, Accrued expenses and Payables to affiliates on its Balance Sheet. Generation identified a related presentation error of $83 million between Accounts payable and Payables to affiliates on its Balance Sheet. BGE identified a related presentation error of $4 million between Accrued expenses and Payables to affiliates on its Balance Sheet. Similar adjustments are also reflected on the related party transactions footnote. | |
Consolidation Variable Interest Entity Policy [Text Block] | ' |
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | |
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $458 million and $614 million as of December 31, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $414 million and $564 million as of December 31, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 15 – Asset Retirement Obligations for further discussion. | |
For each unconsolidated VIE, Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities. | |
Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEs which, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs. | |
ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon or Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions' creditors do not have any recourse to Exelon's or Generation's general credit. | |
Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 22 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. | |
For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. | |
Investment in Energy Development Projects. Generation has several equity investments in energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities of the VIEs that most significantly impact the VIEs economic performance. | |
Residential Solar Provider. Generation has an equity investment in a residential solar provider. Generation has evaluated the significant agreements, ownership structure and risks of the entity, and determined that the entity is a VIE because it does not have sufficient equity at risk to fund its operations. Generation has determined that its equity investment in the entity is a variable interest. However, Generation has concluded that we are not the primary beneficiary because Generation does not have the power to direct the activities of the VIE that most significantly impact the entity's economic performance. Exelon or Generation do not have any contractual or other obligations to provide additional financial support and the residential solar provider's creditors do not have any recourse to Exelon's or Generation's general credit. | |
ComEd, PECO and BGE | |
ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 22 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. | |
For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs as a result of commercial arrangements represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2013, the total amount of accounts payable owed by the utilities under agreements with these VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in these VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. | |
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon's, ComEd's, PECO's or BGE's financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 – Debt and Credit Agreements for additional information. | |
Public Utilities Policy [Text Block] | ' |
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) | |
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities' costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd's, PECO's or BGE's business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information. | |
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order. | |
. | |
Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for gas reserves are based on internal calculations. | |
Amortization of regulatory assets is recorded over the recovery period specified in the related legislation or regulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost would have originally been recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income. For income tax related regulatory assets, amortization is generally recorded to Income tax expense in the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |
See Note 3—Regulatory Matters and Note 23—Supplemental Financial Information for additional information regarding Generation's nuclear fuel, Generation's ARC and the amortization of ComEd's, PECO's and BGE's regulatory assets. | |
Property Plant And Equipment Policy [Text Block] | ' |
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | |
Property, plant and equipment is recorded at original cost. Original cost includes labor, materials and construction overhead. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred. For constructed assets, Exelon capitalizes construction-related direct labor and material costs. ComEd, PECO and BGE also capitalized indirect construction costs including labor and related costs of departments associated with supporting construction activities. | |
Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE are accounted for as CIAC. | |
For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to operating and maintenance expense as incurred. | |
For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd's and BGE's depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. ComEd's and BGE's actual incurred removal costs are applied against a related regulatory liability. PECO's removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method. | |
Generation's oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred. | |
See Note 7—Property, Plant and Equipment, Note 9—Jointly Owned Electric Utility Plant and Note 23—Supplemental Financial Information for additional information regarding property, plant and equipment. | |
__________ | |
(a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012 and 2011. | |
Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE) | |
Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd's and BGE's depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation's operating nuclear generating stations except for Oyster Creek. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations. | |
See Note 7—Property, Plant and Equipment for further information regarding depreciation. | |
Asset Retirement Obligations And Environmental Cost Policy [Text Block] | ' |
Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE) | |
The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years. The liabilities associated with Exelon's non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations or, in the case of the majority of ComEd's, PECO's, and BGE's accretion, through an increase to regulatory assets. See Note 15—Asset Retirement Obligations for additional information. | |
Impairment Or Disposal Of Long Lived Assets Policy [Text Block] | ' |
Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. Cash flows from Generation plant assets are generally evaluated at a regional portfolio level along with cash flows generated from Generation's supply and risk management activities, including cash flows from contracts that are recorded as intangible contract assets and liabilities on the balance sheet. In certain cases generation assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). | |
Impairment may occur when the carrying value of the asset or asset group exceeds the future undiscounted cash flows. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. | |
Conditions that could have an adverse impact on the expected future cash flows and the fair value of the long-lived assets and asset groups include, among other factors, a deteriorating business climate, including energy prices and market conditions, revisions to regulatory laws, or plans to dispose of a long-lived asset significantly before the end of its useful life. See Note 8 – Impairment of Long-Lived Assets for additional information. | |
Goodwill And Intangible Assets Policy [Text Block] | ' |
Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10—Intangible Assets for additional information regarding Exelon's and ComEd's goodwill. | |
Derivatives Policy [Text Block] | ' |
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | |
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that are not designated or do not qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon's Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. | |
For commodity derivative contracts, effective with the date of the merger with Constellation, Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and will be reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivatives executed to hedge economic risk for commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company. | |
As part of Generation's energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12—Derivative Financial Instruments for additional information. | |
Compensation Related Costs Policy [Text Block] | ' |
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | |
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective March 12, 2012, Exelon became the sponsor of all of Constellation's defined benefit pension and other postretirement benefit plans and defined contribution savings plans. | |
The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16—Retirement Benefits for additional discussion of Exelon's accounting for retirement benefits. | |
Marketable Securities Policy [Text Block] | ' |
Marketable Securities (Exelon, Generation, ComEd, PECO and BGE) | |
All marketable securities are reported at fair value. Marketable securities held in the NDT funds, certain Generation Rabbi trust investments and BGE's Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former ComEd and former PECO nuclear generating units (Regulatory Agreement Units) are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the former AmerGen nuclear generating units, the Zion generating station and portions of the Peach Bottom nuclear generating units not subject to a regulatory agreement (Non-Regulatory Agreement Units) are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on certain Generation Rabbi trust investments and BGE's Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gains and losses, net of tax, for Generation's, ComEd's and PECO's available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd's and PECO's available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 15— Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 23—Supplemental Financial Information for additional information regarding ComEd's and PECO's regulatory assets and liabilities. | |
Allowance For Funds Used During Construction Policy [Text Block] | ' |
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities. | |
Research Development And Computer Software Disclosure [Text Block] | ' |
Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE) | |
Costs incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year: | |
Property Plant And Equipment Interest Capitalization [Text Block] | ' |
During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. | |
Guarantees Indemnifications And Warranties Policies [Text Block] | ' |
Guarantees (Exelon, Generation, ComEd, PECO and BGE) | |
The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. | |
The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22—Commitments and Contingencies for additional information. | |
Nuclear Fuel Policy [Text Block] | ' |
Nuclear Fuel (Exelon and Generation) | |
The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. The estimated disposal cost of SNF is established per the Standard Waste Contract with the DOE and is expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22—Commitments and Contingencies for additional information regarding the SNF disposal fee. | |
Nuclear Outage Costs Policy [Text Block] | ' |
Nuclear Outage Costs (Exelon and Generation) | |
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to operating and maintenance expense or capitalized to property, plant and equipment (based on the nature of the activities) in the period incurred. | |
New site development costs nuclear outage costs policy [Text Block] | ' |
New Site Development Costs (Exelon and Generation) | |
New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management's determination that the project is economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. At December 31, 2013 and 2012, there were no material capitalized development costs for projects not yet under construction included in Property, plant and equipment, net on Exelon's and Generation's Consolidated Balance Sheets. Approximately $10 million, $4 million and $2 million of costs were expensed by Exelon and Generation for the years ended December 31, 2013, 2012, and 2011, respectively. These costs primarily related to the possible development of new renewable energy projects. | |
Business Description And Basis Of Presentation [TextBlock] | ' |
Description of Business (Exelon, Generation, ComEd, PECO and BGE) | |
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon's principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation's regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. | |
The energy generation business includes: | |
Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions. | |
The energy delivery businesses include: | |
ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago. | |
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia. | |
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. | |
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE) | |
This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures. | |
Exelon did not apply push-down accounting to BGE and BGE continued to be subject to reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2013, 2012 and 2011 and the financial position as of December 31, 2013 and December 31, 2012. However, for Exelon's consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2013. | |
Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. | |
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon's corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed. | |
Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE's preference stock. Exelon owned none of PECO's preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity, PECO's preferred securities as preferred securities of subsidiary through their redemption in 2013, and BGE's preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters. | |
Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in non-controlling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the non-controlling members for certain of these projects. | |
ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity. | |
Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions. | |
For the year ended December 31, 2013, BGE recorded a $2 million correcting adjustment to decrease amortization expense related to regulatory assets that were originally recorded during 2012, an adjustment to decrease income tax expense by $4 million related to the recognition and measurement of regulatory assets that should have been recorded in periods prior to 2013, and a $4 million correcting adjustment to decrease operating and maintenance expense for an overstatement of BGE's life insurance obligation related to post-employment benefits in prior years. For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. In addition, ComEd identified a disclosure adjustment within the renewable energy credits and alternative energy credits section of the 2012 Form 10-K Note 8 – Intangible Assets which has been revised in Note 10 of this year's report. Exelon, ComEd and BGE have concluded these correcting adjustments are not material to its results of operations, cash flows, or financial positions for the years ended December 31, 2013, and December 31, 2012, or any prior period. | |
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. | |
Basis_of_Presentation_Policies
Basis of Presentation (Policies) | 12 Months Ended |
Dec. 31, 2013 | |
Basis of Presentation [Line Items] | ' |
Consolidation, Policy [Text Block] | ' |
Use of Estimates (Exelon, Generation, ComEd, PECO and BGE) | |
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates. | |
Reclassifications (Exelon, ComEd, and BGE) | |
Certain prior year amounts in Exelon's and BGE's Consolidated Statements of Operations and Cash Flows, and Exelon's, ComEd's, and BGE's Consolidated Balance Sheets have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. | |
In 2013, Exelon and BGE identified a presentation errors of $12 million and $16 million on their Statements of Operations and Comprehensive Income, respectively related to its financing trusts within interest expense that is now presented within Interest expense to affiliates, net. Additionally, Exelon identified similar presentation errors of $92 million between Accounts payable, Accrued expenses and Payables to affiliates on its Balance Sheet. Generation identified a related presentation error of $83 million between Accounts payable and Payables to affiliates on its Balance Sheet. BGE identified a related presentation error of $4 million between Accrued expenses and Payables to affiliates on its Balance Sheet. Similar adjustments are also reflected on the related party transactions footnote. | |
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) | |
Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities' costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd's, PECO's or BGE's business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3—Regulatory Matters for additional information. | |
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order. | |
. | |
Consolidation Variable Interest Entity Policy [Text Block] | ' |
These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | |
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $458 million and $614 million as of December 31, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $414 million and $564 million as of December 31, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 15 – Asset Retirement Obligations for further discussion. | |
For each unconsolidated VIE, Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities. | |
Energy Purchase and Sale Agreements. In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEs which, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs. | |
ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 – Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon or Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions' creditors do not have any recourse to Exelon's or Generation's general credit. | |
Fuel Purchase Commitments. Generation's customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation's membership in NEIL are discussed in further detail in Note 22 – Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required. | |
For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities' activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 —Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required. | |
Investment in Energy Development Projects. Generation has several equity investments in energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities of the VIEs that most significantly impact the VIEs economic performance. | |
Residential Solar Provider. Generation has an equity investment in a residential solar provider. Generation has evaluated the significant agreements, ownership structure and risks of the entity, and determined that the entity is a VIE because it does not have sufficient equity at risk to fund its operations. Generation has determined that its equity investment in the entity is a variable interest. However, Generation has concluded that we are not the primary beneficiary because Generation does not have the power to direct the activities of the VIE that most significantly impact the entity's economic performance. Exelon or Generation do not have any contractual or other obligations to provide additional financial support and the residential solar provider's creditors do not have any recourse to Exelon's or Generation's general credit. | |
ComEd, PECO and BGE | |
ComEd's, PECO's, and BGE's retail operations frequently include the purchase of electricity and RECs through procurement contracts of varying durations. See Note 3 – Regulatory Matters and Note 22 – Commitments and Contingencies for additional information on these contracts. ComEd, PECO and BGE have evaluated these types of contracts and have historically determined that either there is no significant variable interest in the entity, or where either ComEd, PECO or BGE does have a significant variable interest in a VIE, ComEd, PECO or BGE would not be the primary beneficiary and, therefore, consolidation would not be required. | |
For contracts where ComEd, PECO or BGE is considered to have a significant variable interest, consideration is given to which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of their production or procurement processes related to electricity, RECs, AECs or natural gas. ComEd, PECO and BGE do not have control over the operation and maintenance of the entities and they do not bear operational risk related to the associated activities. Generally, the carrying amounts of assets and liabilities in ComEd's, PECO's, and BGE's Consolidated Balance Sheets that relate to their involvement with VIEs as a result of commercial arrangements represent the amounts owed by the utilities for the purchases associated with the current billing cycles under the contracts. As of December 31, 2013, the total amount of accounts payable owed by the utilities under agreements with these VIEs was not material. In addition, variability from these contracts is mitigated by the fact that the utilities are able to recover costs incurred under purchase agreements through customer rates. Furthermore, ComEd, PECO and BGE do not have any debt or equity investments in these VIEs and do not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 – Commitments and Contingencies. Accordingly, none of ComEd, PECO or BGE considers itself to be the primary beneficiary of any VIEs as a result of commercial arrangements. | |
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon's, ComEd's, PECO's or BGE's financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 – Debt and Credit Agreements for additional information. | |
Business Description And Basis Of Presentation [TextBlock] | ' |
Description of Business (Exelon, Generation, ComEd, PECO and BGE) | |
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon's principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation's regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 - Merger and Acquisitions for further information regarding the merger transaction. | |
The energy generation business includes: | |
Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions. | |
The energy delivery businesses include: | |
ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago. | |
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia. | |
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore. | |
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE) | |
This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures. | |
Exelon did not apply push-down accounting to BGE and BGE continued to be subject to reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2013, 2012 and 2011 and the financial position as of December 31, 2013 and December 31, 2012. However, for Exelon's consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2013. | |
Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. | |
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon's corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed. | |
Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE's preference stock. Exelon owned none of PECO's preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity, PECO's preferred securities as preferred securities of subsidiary through their redemption in 2013, and BGE's preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters. | |
Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain Exelon Wind projects, of which Generation holds a majority interest ranging from 94% to 99% for certain periods of time, and the remaining interests are included in non-controlling interest on Exelon's and Generation's Consolidated Balance Sheets. See Note 2 for further discussion of Exelon's and Generation's VIEs and the reversionary interests of the non-controlling members for certain of these projects. | |
ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2013 and December 31, 2012, as equity. | |
Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including the 50.01% interest in CENG, and certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon's percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions. | |
For the year ended December 31, 2013, BGE recorded a $2 million correcting adjustment to decrease amortization expense related to regulatory assets that were originally recorded during 2012, an adjustment to decrease income tax expense by $4 million related to the recognition and measurement of regulatory assets that should have been recorded in periods prior to 2013, and a $4 million correcting adjustment to decrease operating and maintenance expense for an overstatement of BGE's life insurance obligation related to post-employment benefits in prior years. For the year ended December 31, 2012, BGE recorded a $2 million correcting adjustment to reduce electric distribution revenue related to decoupling of 2011 electric distribution revenue, a $3 million correcting adjustment to increase electric operations and maintenance expense related to capitalization of electric transmission costs, and a $5 million correcting adjustment to interest expense to reflect the impacts of amendments of tax positions previously taken on prior-year consolidated income tax returns. In addition, ComEd identified a disclosure adjustment within the renewable energy credits and alternative energy credits section of the 2012 Form 10-K Note 8 – Intangible Assets which has been revised in Note 10 of this year's report. Exelon, ComEd and BGE have concluded these correcting adjustments are not material to its results of operations, cash flows, or financial positions for the years ended December 31, 2013, and December 31, 2012, or any prior period. | |
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. | |
Significant_Accounting_Policie2
Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2013 | ||||||||||||||||
Significant Accounting Policies [Line Items] | ' | |||||||||||||||
Schedule Of Capitalized Software [Text Block] | ' | |||||||||||||||
Net unamortized software costs | Exelon | Generation | ComEd | PECO | BGE | |||||||||||
31-Dec-13 | $ | 479 | $ | 129 | $ | 101 | $ | 71 | $ | 155 | ||||||
31-Dec-12 | 499 | 143 | 105 | 63 | 157 | |||||||||||
Amortization of capitalized software costs | Exelon (a) | Generation (a) | ComEd | PECO | BGE (a) | |||||||||||
2013 | $ | 198 | $ | 67 | $ | 52 | $ | 33 | $ | 36 | ||||||
2012 | 208 | 81 | 56 | 30 | 32 | |||||||||||
2011 | 122 | 41 | 50 | 25 | 25 | |||||||||||
Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012 and 2011 | ||||||||||||||||
Schedule Of Capitalized Interest And AFUDC [Text Block] | ' | |||||||||||||||
Exelon (a) | Generation (a) | ComEd | PECO | BGE (a) | ||||||||||||
2013 | Total incurred interest (b) | $ | 1,423 | $ | 411 | $ | 584 | $ | 117 | $ | 129 | |||||
Capitalized interest | 54 | 54 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 35 | — | 16 | 6 | 13 | |||||||||||
2012 | Total incurred interest (b) | $ | 1,003 | $ | 368 | $ | 310 | $ | 125 | $ | 149 | |||||
Capitalized interest | 67 | 67 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 25 | — | 9 | 6 | 15 | |||||||||||
2011 | Total incurred interest (b) | $ | 783 | $ | 219 | $ | 349 | $ | 138 | $ | 136 | |||||
Capitalized interest | 49 | 49 | — | — | — | |||||||||||
Credits to AFUDC debt and equity | 25 | — | 12 | 13 | 22 | |||||||||||
__________ | ||||||||||||||||
(a) Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 – December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 – December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010. | ||||||||||||||||
(b) Includes interest expense to affiliates. | ||||||||||||||||
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Variable Interest Entity [Line Items] | ' | ||||||||||||||||||
Schedule of Variable Interest Entities [Table Text Block] | ' | ||||||||||||||||||
31-Dec-13 | 31-Dec-12 | ||||||||||||||||||
Exelon (a) | Generation | BGE | Exelon (a)(b) | Generation (b) | BGE | ||||||||||||||
Current assets | $ | 484 | $ | 446 | $ | 28 | $ | 550 | $ | 519 | $ | 30 | |||||||
Noncurrent assets | 1,905 | 1,884 | 3 | 1,719 | 1,680 | - | |||||||||||||
Total assets | $ | 2,389 | $ | 2,330 | $ | 31 | $ | 2,269 | $ | 2,199 | $ | 30 | |||||||
Current liabilities | $ | 566 | $ | 481 | $ | 74 | $ | 684 | $ | 612 | $ | 71 | |||||||
Noncurrent liabilities | 774 | 562 | 195 | 775 | 470 | 265 | |||||||||||||
Total liabilities | $ | 1,340 | $ | 1,043 | $ | 269 | $ | 1,459 | $ | 1,082 | $ | 336 | |||||||
Schedule Of Unconsolidated Variable Interest Entities [Text Block] | ' | ||||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-13 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 128 | $ | 332 | $ | 460 | |||||||||||||
Total liabilities (a) | 17 | 123 | 140 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 86 | 86 | ||||||||||||||||
Other ownership interests (a) | 111 | 123 | 234 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Carrying amount of equity investments | 7 | 67 | 74 | ||||||||||||||||
Contract intangible asset | 9 | 0 | 9 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 44 | 0 | 44 | ||||||||||||||||
Commercial | Equity | ||||||||||||||||||
Agreement | Investment | ||||||||||||||||||
31-Dec-12 | VIEs | VIEs | Total | ||||||||||||||||
Total assets (a) | $ | 386 | $ | 354 | $ | 740 | |||||||||||||
Total liabilities (a) | 219 | 114 | 333 | ||||||||||||||||
Registrants' ownership interest (a) | 0 | 97 | 97 | ||||||||||||||||
Other ownership interests (a) | 167 | 143 | 310 | ||||||||||||||||
Registrants' maximum exposure to loss: | |||||||||||||||||||
Letters of credit | 5 | 0 | 5 | ||||||||||||||||
Carrying amount of equity investments | 0 | 77 | 77 | ||||||||||||||||
Contract intangible asset | 8 | 0 | 8 | ||||||||||||||||
Debt and payment guarantees | 0 | 5 | 5 | ||||||||||||||||
Net assets pledged for Zion Station decommissioning (b) | 50 | 0 | 50 |
Merger_and_Acquisitions_Tables
Merger and Acquisitions (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | ' | ||||||||||||||||||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block] | ' | ||||||||||||||||||||||||||||
Preliminary Purchase Price Allocation, excluding amortization | Exelon | Generation | |||||||||||||||||||||||||||
Current assets | $ | 4,936 | $ | 3,638 | |||||||||||||||||||||||||
Property, plant and equipment | 9,342 | 4,054 | |||||||||||||||||||||||||||
Unamortized energy contracts | 3,218 | 3,218 | |||||||||||||||||||||||||||
Other intangibles, trade name and retail relationships | 457 | 457 | |||||||||||||||||||||||||||
Investment in affiliates | 1,942 | 1,942 | |||||||||||||||||||||||||||
Pension and OPEB regulatory asset | 740 | 0 | |||||||||||||||||||||||||||
Other assets | 2,265 | 1,266 | |||||||||||||||||||||||||||
Total assets | 22,900 | 14,575 | |||||||||||||||||||||||||||
Current liabilities | 3,408 | 2,804 | |||||||||||||||||||||||||||
Unamortized energy contracts | 1,722 | 1,512 | |||||||||||||||||||||||||||
Long-term debt, including current maturities | 5,632 | 2,972 | |||||||||||||||||||||||||||
Non-controlling interest | 90 | 90 | |||||||||||||||||||||||||||
Deferred credits and other liabilities and preferred securities | 4,683 | 1,933 | |||||||||||||||||||||||||||
Total liabilities, preferred securities and non-controlling interest | 15,535 | 9,311 | |||||||||||||||||||||||||||
Total purchase price | $ | 7,365 | $ | 5,264 | |||||||||||||||||||||||||
Schedule of Finite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block] | ' | ||||||||||||||||||||||||||||
Estimated amortization expense | |||||||||||||||||||||||||||||
Description | Weighted Average Amortization (Years) (b) | Gross | Accumulated Amortization | Net | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 and Beyond | |||||||||||||||||||
Unamortized energy contracts, net (a) | 1.5 | $ | 1,499 | $ | -1,378 | $ | 121 | $ | 75 | $ | 18 | $ | -31 | $ | -21 | $ | 11 | $ | 69 | ||||||||||
Trade name | 10 | 243 | -46 | 197 | 24 | 24 | 24 | 24 | 24 | 77 | |||||||||||||||||||
Retail relationships | 12.4 | 214 | -36 | 178 | 19 | 18 | 18 | 18 | 18 | 87 | |||||||||||||||||||
Total, net | $ | 1,956 | $ | -1,460 | $ | 496 | $ | 118 | $ | 60 | $ | 11 | $ | 21 | $ | 53 | $ | 233 | |||||||||||
Includes the fair value of BGE's power and gas supply contracts of $12 million for which an offsetting Exelon Corporate regulatory asset was also recorded. | |||||||||||||||||||||||||||||
(b) Weighted average amortization period was calculated as of the date of acquisition. | |||||||||||||||||||||||||||||
Schedule of Restructuring and Related Costs [Text Block] | ' | ||||||||||||||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon (b) | Generation | ComEd (b) | PECO | BGE (b) | ||||||||||||||||||||||||
Severance charges | $ | 124 | $ | 80 | $ | 14 | $ | 7 | $ | 17 | |||||||||||||||||||
Stock compensation | 7 | 4 | 1 | 0 | 1 | ||||||||||||||||||||||||
Other charges | 7 | 4 | 1 | 0 | 1 | ||||||||||||||||||||||||
Total severance benefits | $ | 138 | $ | 88 | $ | 16 | $ | 7 | $ | 19 | |||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012. | |||||||||||||||||||||||||||||
Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||||||||||||||
Schedule Of Severance Costs [TableTextBlock] | ' | ||||||||||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||||||||
Severance charges - 2013 | $ | 18 | $ | 16 | $ | 2 | $ | 0 | $ | 0 | |||||||||||||||||||
Severance charges - 2012 | 19 | 14 | 2 | 1 | 3 | ||||||||||||||||||||||||
Severance charges - 2011 | 5 | 5 | 0 | 0 | 4 | ||||||||||||||||||||||||
Business Acquisition, Pro Forma Information [Table Text Block] | ' | ||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||
(unaudited) | 2012 | 2011 (a) | 2012 | 2011 (b) | |||||||||||||||||||||||||
Total Revenues | $ | 17,013 | $ | 19,494 | $ | 26,700 | $ | 30,712 | |||||||||||||||||||||
Net income attributable to Exelon | 1,205 | 324 | 2,092 | 974 | |||||||||||||||||||||||||
Basic Earnings Per Share | n.a. | n.a. | $ | 2.56 | $ | 1.15 | |||||||||||||||||||||||
Diluted Earnings Per Share | n.a. | n.a. | 2.55 | 1.14 | |||||||||||||||||||||||||
_________________ | |||||||||||||||||||||||||||||
The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||
Schedule Of Business Acquisitions By Acquisition [Text Block] | ' | ||||||||||||||||||||||||||||
Description | Payment Period | BGE | Generation | Exelon | Statement of Operations Location | ||||||||||||||||||||||||
BGE rate credit of $100 per residential | |||||||||||||||||||||||||||||
customer (a) | Q2 2012 | $ | 113 | $ | 0 | $ | 113 | Revenues | |||||||||||||||||||||
Customer investment fund to invest in | |||||||||||||||||||||||||||||
energy efficiency and low-income | |||||||||||||||||||||||||||||
energy assistance to BGE customers | 2012 to 2014 | 0 | 0 | 113.5 | O&M Expense | ||||||||||||||||||||||||
Contribution for renewable energy, | |||||||||||||||||||||||||||||
energy efficiency or related projects | |||||||||||||||||||||||||||||
in Baltimore | 2012 to 2014 | 0 | 0 | 2 | O&M Expense | ||||||||||||||||||||||||
Charitable contributions at $7 million per | |||||||||||||||||||||||||||||
year for 10 years | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | ||||||||||||||||||||||||
State funding for offshore wind | |||||||||||||||||||||||||||||
development projects | Q2 2012 | 0 | 0 | 32 | O&M Expense | ||||||||||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | -2 | 0 | -2 | Taxes Other Than Income | ||||||||||||||||||||||||
Total | $ | 139 | $ | 35 | $ | 328.5 | |||||||||||||||||||||||
Acquisitions | |||||||||||||||||||||||||||||
2011 | |||||||||||||||||||||||||||||
Wolf Hollow | Antelope Valley | ||||||||||||||||||||||||||||
Fair value of consideration transferred | |||||||||||||||||||||||||||||
Cash | $ | 305 | $ | 75 | |||||||||||||||||||||||||
Plus: Gain on PPA settlement | 6 | - | |||||||||||||||||||||||||||
Total fair value of consideration transferred | $ | 311 | $ | 75 | |||||||||||||||||||||||||
Recognized amounts of identifiable assets acquired and liabilities assumed | |||||||||||||||||||||||||||||
Property, plant and equipment | $ | 347 | $ | 15 | |||||||||||||||||||||||||
Inventory | 5 | - | |||||||||||||||||||||||||||
Intangible assets (a) | - | 190 | |||||||||||||||||||||||||||
Payable to First Solar, Inc. (b) | - | -135 | |||||||||||||||||||||||||||
Working capital, net | -5 | - | |||||||||||||||||||||||||||
Other Assets | - | 5 | |||||||||||||||||||||||||||
Total net identifiable assets | $ | 347 | $ | 75 | |||||||||||||||||||||||||
Bargain purchase gain | $ | 36 | $ | - | |||||||||||||||||||||||||
________________________ | |||||||||||||||||||||||||||||
(a) See Note 10 - Intangible Assets for additional information. | |||||||||||||||||||||||||||||
(b) Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a "seller financing" arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation's implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc. During 2013, a subsidiary of Generation paid off the remaining balance of the payable to First Solar, Inc. | |||||||||||||||||||||||||||||
Regulatory_Matters_Tables
Regulatory Matters (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets and liabilities | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | 31-Dec-12 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Regulatory assets | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||||||||||||
Pension and other postretirement | Pension and other postretirement | |||||||||||||||||||||||||||||||||||||||||||||||||||
benefits | $ | 221 | $ | 2,794 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | benefits | $ | 304 | $ | 3,673 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | 0 | 1,317 | 8 | 77 | Deferred income taxes | 14 | 1,382 | 5 | 62 | 0 | 1,255 | 9 | 65 | |||||||||||||||||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | 0 | 58 | 0 | 66 | AMI programs | 3 | 70 | 3 | 10 | 0 | 29 | 0 | 31 | |||||||||||||||||||||||||||||||||||
AMI meter events | 0 | 5 | 0 | 0 | 0 | 5 | 0 | 0 | AMI meter events | 0 | 17 | 0 | 0 | 0 | 17 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Under-recovered distribution service | Under-recovered distribution service | |||||||||||||||||||||||||||||||||||||||||||||||||||
costs | 178 | 285 | 178 | 285 | 0 | 0 | 0 | 0 | costs | 18 | 191 | 18 | 191 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | Debt costs | 14 | 68 | 11 | 62 | 3 | 6 | 1 | 9 | |||||||||||||||||||||||||||||||||||
Fair value of BGE long-term debt | 0 | 219 | 0 | 0 | 0 | 0 | 0 | 0 | Fair value of BGE long-term debt | 0 | 256 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Fair value of BGE supply contract | 12 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | Fair value of BGE supply contracts | 77 | 12 | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Severance | 16 | 12 | 12 | 0 | 0 | 0 | 4 | 12 | Severance | 29 | 28 | 25 | 12 | 0 | 0 | 4 | 16 | |||||||||||||||||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | 0 | 25 | 0 | 10 | Asset retirement obligations | 0 | 90 | 0 | 65 | 0 | 25 | 0 | 0 | |||||||||||||||||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | MGP remediation costs | 58 | 232 | 51 | 197 | 6 | 33 | 1 | 2 | |||||||||||||||||||||||||||||||||||
RTO start-up costs | 2 | 0 | 2 | 0 | 0 | 0 | 0 | 0 | RTO start-up costs | 3 | 2 | 3 | 2 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Under-recovered uncollectible | Under-recovered electric universal | |||||||||||||||||||||||||||||||||||||||||||||||||||
accounts | 0 | 48 | 0 | 48 | 0 | 0 | 0 | 0 | service fund costs | 11 | 0 | 0 | 0 | 11 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | 0 | 0 | 0 | 0 | Financial swap with Generation | 0 | 0 | 226 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Energy and transmission programs | 53 | 0 | 52 | 0 | 0 | 0 | 1 | 0 | Renewable energy | 18 | 49 | 18 | 49 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Deferred storm costs | 3 | 3 | 0 | 0 | 0 | 0 | 3 | 3 | Energy and transmission programs | 43 | 0 | 14 | 0 | 1 | 0 | 28 | 0 | |||||||||||||||||||||||||||||||||||
Electric generation-related | DSP Program costs | 1 | 3 | 0 | 0 | 1 | 3 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
regulatory asset | 13 | 30 | 0 | 0 | 0 | 0 | 13 | 30 | DSP II Program costs | 1 | 2 | 0 | 0 | 1 | 2 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | 0 | 0 | 0 | 0 | 71 | 154 | Deferred storm costs | 3 | 6 | 0 | 0 | 0 | 0 | 3 | 6 | |||||||||||||||||||||||||||||||||||
Energy efficiency and demand | Electric generation-related | |||||||||||||||||||||||||||||||||||||||||||||||||||
response programs | 73 | 148 | 0 | 0 | 0 | 0 | 73 | 148 | regulatory asset | 16 | 40 | 0 | 0 | 0 | 0 | 16 | 40 | |||||||||||||||||||||||||||||||||||
Merger integration costs | 2 | 9 | 0 | 0 | 2 | 9 | Rate stabilization deferral | 67 | 225 | 0 | 0 | 0 | 0 | 67 | 225 | |||||||||||||||||||||||||||||||||||||
Other | 31 | 39 | 18 | 26 | 8 | 7 | 4 | 6 | Energy efficiency and demand | |||||||||||||||||||||||||||||||||||||||||||
response programs | 56 | 126 | 0 | 0 | 0 | 0 | 56 | 126 | ||||||||||||||||||||||||||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | Under-recovered electric revenue | |||||||||||||||||||||||||||||||||||
31-Dec-13 | Exelon | ComEd | PECO | BGE | decoupling | 5 | 0 | 0 | 0 | 0 | 0 | 5 | 0 | |||||||||||||||||||||||||||||||||||||||
Other | 23 | 25 | 14 | 16 | 9 | 8 | 0 | 2 | ||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | ||||||||||||||||||||||||||||||||||||||||||||
Total regulatory assets | $ | 764 | $ | 6,497 | $ | 388 | $ | 666 | $ | 32 | $ | 1,378 | $ | 190 | $ | 522 | ||||||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | 31-Dec-12 | Exelon | ComEd | PECO | BGE | |||||||||||||||||||||||||||||||
Nuclear decommissioning | 0 | 2,740 | 0 | 2,293 | 0 | 447 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | 0 | 0 | 21 | 204 | Regulatory liabilities | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||||||||||||
Energy efficiency and demand | Nuclear decommissioning | $ | 0 | $ | 2,397 | $ | 0 | $ | 2,037 | $ | 0 | $ | 360 | $ | 0 | $ | 0 | |||||||||||||||||||||||||||||||||||
response programs | 53 | 0 | 45 | 0 | 8 | 0 | 0 | 0 | Removal costs | 97 | 1,406 | 75 | 1,192 | 0 | 0 | 22 | 214 | |||||||||||||||||||||||||||||||||||
DLC program costs | 1 | 10 | 0 | 0 | 1 | 10 | 0 | 0 | Energy efficiency and demand | |||||||||||||||||||||||||||||||||||||||||||
Energy efficiency phase II | 0 | 21 | 0 | 0 | 0 | 21 | 0 | 0 | response programs | 131 | 0 | 43 | 0 | 88 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | 0 | 0 | 20 | 114 | 0 | 0 | Electric distribution tax repairs | 20 | 132 | 0 | 0 | 20 | 132 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | 0 | 0 | 8 | 37 | 0 | 0 | Gas distribution tax repairs | 8 | 46 | 0 | 0 | 8 | 46 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Energy and transmission programs | 78 | 0 | 9 | 0 | 58 | 0 | 11 | 0 | Over-recovered uncollectible | |||||||||||||||||||||||||||||||||||||||||||
Over-recovered gas and electric | accounts | 6 | 0 | 6 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
universal service fund costs | 8 | 0 | 0 | 0 | 8 | 0 | 0 | 0 | Energy and transmission programs | 54 | 0 | 6 | 0 | 48 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Revenue subject to refund | 38 | 0 | 38 | 0 | 0 | 0 | 0 | 0 | Over-recovered gas universal | |||||||||||||||||||||||||||||||||||||||||||
Over-recovered electric and gas | service fund costs | 3 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||
revenue decoupling | 16 | 0 | 0 | 0 | 0 | 0 | 16 | 0 | Over-recovered AEPS costs | 2 | 0 | 0 | 0 | 2 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Other | 4 | 0 | 0 | 0 | 3 | 0 | 0 | 0 | Revenue subject to refund | 40 | 0 | 40 | 0 | 0 | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||
Over-recovered gas revenue | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | decoupling | 7 | 0 | 0 | 0 | 0 | 0 | 7 | 0 | |||||||||||||||||||||||||||
Total regulatory liabilities | $ | 368 | $ | 3,981 | $ | 170 | $ | 3,229 | $ | 169 | $ | 538 | $ | 29 | $ | 214 | ||||||||||||||||||||||||||||||||||||
Regulatory Construction Commitment | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||||||||||||||||||||||||||||||||
ComEd | $ | 486 | $ | 134 | $ | 173 | $ | 177 | $ | 2 | $ | 0 | ||||||||||||||||||||||||||||||||||||||||
PECO | 133 | 32 | 29 | 40 | 24 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||
BGE | 400 | 42 | 83 | 95 | 87 | 93 | ||||||||||||||||||||||||||||||||||||||||||||||
Purchase Of Receivables [Table Text Block] | ' | ' | ||||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 263 | $ | 105 | $ | 72 | $ | 86 | ||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -30 | -16 | -7 | -7 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables, net | $ | 233 | $ | 89 | $ | 65 | $ | 79 | ||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2012 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 191 | $ | 55 | $ | 65 | $ | 71 | ||||||||||||||||||||||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | -21 | -9 | -6 | -6 | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchased receivables, net | $ | 170 | $ | 46 | $ | 59 | $ | 65 |
Investment_in_Constellation_En1
Investment in Constellation Energy Nuclear Group, LLC (Tables) | 12 Months Ended | ||||||
Dec. 31, 2013 | |||||||
Schedule of Equity Method Investments [Line Items] | ' | ||||||
Schedule of total equity in earnings of investment in CENG | ' | ||||||
Year Ended | Period March 12, | ||||||
Ended December 31, | through December 31, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 123 | $ | 73 | |||
Amortization of basis difference in CENG | -114 | -172 | |||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 | |||
Exelon Generation Co L L C [Member] | ' | ||||||
Schedule of Equity Method Investments [Line Items] | ' | ||||||
Schedule of total equity in earnings of investment in CENG | ' | ||||||
Year Ended | Period March 12, | ||||||
Ended December 31, | through December 31, | ||||||
2013 | 2012 | ||||||
Equity investment income | $ | 123 | $ | 73 | |||
Amortization of basis difference in CENG | -114 | -172 | |||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 |
Recovered_Sheet1
Impairment of Long-Lived assets (Tables) | 12 Months Ended | |||||
Dec. 31, 2013 | ||||||
Impaired Long-Lived Assets Held and Used [Line Items] | ' | |||||
Schedule of Capital Leased Assets [Table Text Block] | ' | |||||
31-Dec-13 | 31-Dec-12 | |||||
Estimated residual value of leased assets | $ | 1,465 | $ | 1,492 | ||
Less: unearned income | 767 | 807 | ||||
Net investment in long-term leases | $ | 698 | $ | 685 |
Accounts_Receivable_Tables
Accounts Receivable (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2013 | |||||||||||||
Accounts Receivable [Line Items] | ' | ||||||||||||
Schedule Of Accounts Notes Loans And Financing Receivable [Text Block] | ' | ||||||||||||
2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||
Unbilled customer revenues | $ | 1,151 | $ | 584 | (a) | $ | 201 | $ | 161 | $ | 205 | ||
Allowance for uncollectible accounts(b) | -272 | -57 | -62 | -107 | (c) | -46 | |||||||
2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||
Unbilled customer revenues | $ | 1,094 | $ | 535 | (a) | $ | 213 | $ | 164 | $ | 182 | ||
Allowance for uncollectible accounts(b) | -293 | -84 | -70 | -99 | (c) | -40 | |||||||
________________ | |||||||||||||
(a) Represents unbilled portion of retail receivables estimated under Exelon's unbilled critical accounting policy. | |||||||||||||
(b) Includes the allowance for uncollectible accounts on customer and other accounts receivable. | |||||||||||||
(c) Includes an allowance for uncollectible accounts of $8 million and $7 million at December 31, 2013 and 2012, respectively, related to PECO's current installment plan receivables described below. | |||||||||||||
Property_Plant_and_Equipment_T
Property, Plant, and Equipment (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Property Plant And Equipment [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
7. Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||
Exelon | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 28,123 | $ | 26,576 | ||||
Electric—generation | 1 | - | 52 | 20,420 | 19,004 | ||||||
Gas—transportation and distribution | 5 | - | 90 | 3,296 | 3,108 | ||||||
Common—electric and gas | 5 | - | 50 | 1,101 | 1,029 | ||||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,890 | 1,926 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 1,017 | 912 | ||||||
Total property, plant and equipment | 61,043 | 57,370 | |||||||||
Less: accumulated depreciation (c) | 13,713 | 12,184 | |||||||||
Property, plant and equipment, net | $ | 47,330 | $ | 45,186 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes Generation's buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. Also includes ComEd's buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. Includes land held for future use and non utility property at PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category. | |||||||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes Generation's buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. Also includes ComEd's buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. Includes land held for future use and non utility property at PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.76 | % | 2.59 | % | |||||
Electric—generation | 3.35 | % | 3.15 | % | 3.12 | % | |||||
Gas | 2.06 | % | 2.03 | % | 1.73 | % | |||||
Common—electric and gas | 7.53 | % | 7.61 | % | 8.05 | % | |||||
Generation | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—generation | 1 | - | 52 | $ | 20,420 | $ | 19,004 | ||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,129 | 1,352 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 400 | 374 | ||||||
Total property, plant and equipment | 27,145 | 25,545 | |||||||||
Less: accumulated depreciation (c) | 7,034 | 6,014 | |||||||||
Property, plant and equipment, net | $ | 20,111 | $ | 19,531 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.35%, 3.15% and 3.12% for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||
License Renewals. Generation's depreciation provisions are based on the estimated useful lives of its generating stations, which assume the renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information regarding license renewals. | |||||||||||
Plant Retirements | |||||||||||
Schuylkill Station and Riverside Station. On October 31, 2012, Generation notified PJM of its intention to permanently retire Schuylkill Generating Station Unit 1 by February 1, 2013, and Riverside Generating Station Unit 6 by June 1, 2014. Schuylkill Unit 1 is a 166 MW peaking oil unit located in Philadelphia, Pennsylvania, which was placed in service in 1958. Riverside Unit 6 is a 115 MW peaking gas/kerosene unit that was placed in service in 1970, located in Baltimore, Maryland. On December 1, 2013, Generation notified PJM of its intention to permanently retire Riverside Generating Station Unit 4 by June 1, 2016. Riverside Unit 4 is a 74 MW intermediate gas unit that was placed in service in 1951 also located in Baltimore, Maryland. The units are being retired because they are no longer economic to operate due to their age, relatively high capital and operating costs and declining revenue expectations. On November 30, 2012, PJM notified Generation that it did not identify any transmission system reliability issues associated with the proposed Schuylkill Unit 1 retirement date, and as a result, Schuylkill Unit 1 was retired on January 1, 2013. On January 7, 2013 and December 23, 2013, PJM notified Generation that it did not identify any transmission system reliability issues associated with the retirements of Riverside Units 6 and 4, respectively. The early retirements will not have a material impact on Generation or Exelon's results of operations, cash flows or financial position. | |||||||||||
Eddystone Station and Cromby Station. In December 2009, Exelon announced its intention to permanently retire three coal-fired generating units and one oil/gas-fired generating unit, effective May 31, 2011, in response to the economic outlook related to the continued operation of these four units. However, PJM determined that transmission reliability upgrades would be necessary to alleviate reliability impacts and that those upgrades would be completed in a manner that will permit Generation's retirement of two of the units on that date and two of the units subsequent to May 31, 2011. On May 31, 2011, Cromby Generating Station (Cromby) Unit 1 and Eddystone Generating Station (Eddystone) Unit 1 were retired. On May 27, 2011, the FERC approved a settlement providing for a reliability-must-run rate schedule, which defined compensation to be paid to Generation for continuing to operate Cromby Unit 2 and Eddystone Unit 2. The monthly fixed-cost recovery during the reliability-must-run period for Eddystone Unit 2 was approximately $6 million, and covered operating costs, plus a return on net assets, of the two units during the reliability-must-run period. In addition, Generation was reimbursed for variable costs, including fuel, emissions costs, chemicals, auxiliary power and for project investment costs during the reliability-must-run period. Eddystone Unit 2 and Cromby Unit 2 operated under the reliability-must-run agreement from June 1, 2011 until their respective retirement dates, Cromby Unit 2 on December 31, 2011 and Eddystone Unit 2 on May 31, 2012. | |||||||||||
During the years ended December 31, 2013, 2012, and 2011, Generation incurred $1 million, $11 million, and $2 million of shut down costs reflected within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Expense for the write down of inventory was not material for the years ended December 31, 2013, 2012 and 2011. | |||||||||||
ComEd | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 75 | $ | 17,334 | $ | 16,480 | ||||
Construction work in progress | N/A | 456 | 294 | ||||||||
Other property, plant and equipment (a) | 50 | 60 | 50 | ||||||||
Total property, plant and equipment | 17,850 | 16,824 | |||||||||
Less: accumulated depreciation | 3,184 | 2,998 | |||||||||
Property, plant and equipment, net | $ | 14,666 | $ | 13,826 | |||||||
(a) Includes buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. | |||||||||||
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.97%, 2.79% and 2.67% for the years ended December 31, 2013, 2012 and 2011, respectively. | |||||||||||
PECO | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 65 | $ | 6,669 | $ | 6,355 | ||||
Gas—transportation and distribution | 5 | - | 70 | 1,932 | 1,859 | ||||||
Common—electric and gas | 5 | - | 50 | 600 | 568 | ||||||
Construction work in progress | N/A | 101 | 76 | ||||||||
Other property, plant and equipment (a) | 50 | 17 | 17 | ||||||||
Total property, plant and equipment | 9,319 | 8,875 | |||||||||
Less: accumulated depreciation | 2,935 | 2,797 | |||||||||
Property, plant and equipment, net | $ | 6,384 | $ | 6,078 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.73 | % | 2.51 | % | 2.33 | % | |||||
Gas | 1.79 | % | 1.77 | % | 1.73 | % | |||||
Common—electric and gas | 6.65 | % | 7.54 | % | 8.05 | % | |||||
BGE | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2013 and 2012: | |||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 6,100 | $ | 5,767 | ||||
Gas—distribution | 5 | - | 90 | 1,660 | 1,548 | ||||||
Common—electric and gas | 5 | - | 40 | 578 | 554 | ||||||
Construction work in progress | N/A | 196 | 193 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 31 | ||||||||
Total property, plant and equipment | 8,566 | 8,093 | |||||||||
Less: accumulated depreciation | 2,702 | 2,595 | |||||||||
Property, plant and equipment, net | $ | 5,864 | $ | 5,498 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.92 | % | 2.89 | % | |||||
Gas | 2.36 | % | 2.33 | % | 2.41 | % | |||||
Common—electric and gas | 8.45 | % | 7.68 | % | 8.4 | % | |||||
See Note 1—Significant Accounting Polices for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 13—Debt and Credit Agreements for further information regarding Exelon's, ComEd's, and PECO's property, plant and equipment subject to mortgage liens. | |||||||||||
Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block] | ' | ||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.76 | % | 2.59 | % | |||||
Electric—generation | 3.35 | % | 3.15 | % | 3.12 | % | |||||
Gas | 2.06 | % | 2.03 | % | 1.73 | % | |||||
Common—electric and gas | 7.53 | % | 7.61 | % | 8.05 | % | |||||
Exelon Generation Co L L C [Member] | ' | ||||||||||
Property Plant And Equipment [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—generation | 1 | - | 52 | $ | 20,420 | $ | 19,004 | ||||
Nuclear fuel (a) | 1 | - | 8 | 5,196 | 4,815 | ||||||
Construction work in progress | N/A | 1,129 | 1,352 | ||||||||
Other property, plant and equipment (b) | 1 | - | 51 | 400 | 374 | ||||||
Total property, plant and equipment | 27,145 | 25,545 | |||||||||
Less: accumulated depreciation (c) | 7,034 | 6,014 | |||||||||
Property, plant and equipment, net | $ | 20,111 | $ | 19,531 | |||||||
(a) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | |||||||||||
(b) Includes buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities. | |||||||||||
(c) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | |||||||||||
Commonwealth Edison Co [Member] | ' | ||||||||||
Property Plant And Equipment [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 75 | $ | 17,334 | $ | 16,480 | ||||
Construction work in progress | N/A | 456 | 294 | ||||||||
Other property, plant and equipment (a) | 50 | 60 | 50 | ||||||||
Total property, plant and equipment | 17,850 | 16,824 | |||||||||
Less: accumulated depreciation | 3,184 | 2,998 | |||||||||
Property, plant and equipment, net | $ | 14,666 | $ | 13,826 | |||||||
(a) Includes buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. | |||||||||||
PECO Energy Co [Member] | ' | ||||||||||
Property Plant And Equipment [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 65 | $ | 6,669 | $ | 6,355 | ||||
Gas—transportation and distribution | 5 | - | 70 | 1,932 | 1,859 | ||||||
Common—electric and gas | 5 | - | 50 | 600 | 568 | ||||||
Construction work in progress | N/A | 101 | 76 | ||||||||
Other property, plant and equipment (a) | 50 | 17 | 17 | ||||||||
Total property, plant and equipment | 9,319 | 8,875 | |||||||||
Less: accumulated depreciation | 2,935 | 2,797 | |||||||||
Property, plant and equipment, net | $ | 6,384 | $ | 6,078 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block] | ' | ||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.73 | % | 2.51 | % | 2.33 | % | |||||
Gas | 1.79 | % | 1.77 | % | 1.73 | % | |||||
Common—electric and gas | 6.65 | % | 7.54 | % | 8.05 | % | |||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||
Property Plant And Equipment [Line Items] | ' | ||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | ' | ||||||||||
Average Service Life | |||||||||||
(years) | 2013 | 2012 | |||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | 5 | - | 90 | $ | 6,100 | $ | 5,767 | ||||
Gas—distribution | 5 | - | 90 | 1,660 | 1,548 | ||||||
Common—electric and gas | 5 | - | 40 | 578 | 554 | ||||||
Construction work in progress | N/A | 196 | 193 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 31 | ||||||||
Total property, plant and equipment | 8,566 | 8,093 | |||||||||
Less: accumulated depreciation | 2,702 | 2,595 | |||||||||
Property, plant and equipment, net | $ | 5,864 | $ | 5,498 | |||||||
(a) Represents land held for future use and non utility property. | |||||||||||
Property Plant And Equipment Average Service Life Percentage By Asset Category Table [Text Block] | ' | ||||||||||
Average Service Life Percentage by Asset Category | 2013 | 2012 | 2011 | ||||||||
Electric—transmission and distribution | 2.91 | % | 2.92 | % | 2.89 | % | |||||
Gas | 2.36 | % | 2.33 | % | 2.41 | % | |||||
Common—electric and gas | 8.45 | % | 7.68 | % | 8.4 | % |
Jointly_Owned_Electric_Utility1
Jointly Owned Electric Utility Plant (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | ' | ||||||||||||||||||||||||||||||||||||
Schedule Of Jointly Owned Utility Plants [Text Block] | ' | ||||||||||||||||||||||||||||||||||||
Nuclear generation | Fossil fuel generation | Transmission | Other | ||||||||||||||||||||||||||||||||||
Peach | |||||||||||||||||||||||||||||||||||||
Quad Cities | Bottom | Salem (a) | Keystone (b) | Conemaugh (b) | Wyman | PA (c) | DE/NJ (d) | Other (e) | |||||||||||||||||||||||||||||
Operator | Generation | Generation | PSEG Nuclear | GenOn | GenOn | FP&L | First Energy | PSEG | |||||||||||||||||||||||||||||
Ownership interest | 75 | % | 50 | % | 42.59 | % | 41.98 | % | 31.28 | % | 5.89 | % | Various | 42.55 | % | 44.24 | % | ||||||||||||||||||||
Exelon’s share at | |||||||||||||||||||||||||||||||||||||
December 31, 2013: | |||||||||||||||||||||||||||||||||||||
Plant (f) | $ | 941 | $ | 883 | $ | 501 | $ | 725 | $ | 399 | $ | 3 | $ | 14 | $ | 64 | $ | 2 | |||||||||||||||||||
Accumulated | |||||||||||||||||||||||||||||||||||||
depreciation (f) | 226 | 326 | 134 | 268 | 220 | 3 | 7 | 34 | 1 | ||||||||||||||||||||||||||||
Construction | |||||||||||||||||||||||||||||||||||||
work in progress | 27 | 174 | 24 | 6 | 121 | — | — | — | — | ||||||||||||||||||||||||||||
Exelon’s share at | |||||||||||||||||||||||||||||||||||||
December 31, 2012: | |||||||||||||||||||||||||||||||||||||
Plant (f) | $ | 874 | $ | 796 | $ | 494 | $ | 624 | $ | 322 | $ | 3 | $ | 13 | $ | 65 | $ | 1 | |||||||||||||||||||
Accumulated | |||||||||||||||||||||||||||||||||||||
depreciation (f) | 187 | 302 | 119 | 153 | 158 | 3 | 7 | 33 | — | ||||||||||||||||||||||||||||
Construction | |||||||||||||||||||||||||||||||||||||
work in progress | 44 | 115 | 11 | 10 | 57 | — | 1 | — | — | ||||||||||||||||||||||||||||
(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2013 and 2012. | |||||||||||||||||||||||||||||||||||||
(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 – Merger and Acquisitions for additional information. | |||||||||||||||||||||||||||||||||||||
(c) PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(d) PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey. | |||||||||||||||||||||||||||||||||||||
(f) Excludes asset retirement costs. | |||||||||||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | ' | ||||||||||||||||||||||||||||||||||||
Schedule Of Jointly Owned Utility Plants [Text Block] | ' | ||||||||||||||||||||||||||||||||||||
(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2013 and 2012. | |||||||||||||||||||||||||||||||||||||
(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 – Merger and Acquisitions for additional information. | |||||||||||||||||||||||||||||||||||||
(c) PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(d) PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey. | |||||||||||||||||||||||||||||||||||||
(f) Excludes asset retirement costs. | |||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | ' | ||||||||||||||||||||||||||||||||||||
Jointly Owned Utility Plant Interests [Line Items] | ' | ||||||||||||||||||||||||||||||||||||
Schedule Of Jointly Owned Utility Plants [Text Block] | ' | ||||||||||||||||||||||||||||||||||||
(a) Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2013 and 2012. | |||||||||||||||||||||||||||||||||||||
(b) Generation's ownership interest in Keystone and Conemaugh has increased as a result of Exelon's merger with Constellation in 2012. See Note 4 – Merger and Acquisitions for additional information. | |||||||||||||||||||||||||||||||||||||
(c) PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(d) PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||
(e) Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey. | |||||||||||||||||||||||||||||||||||||
(f) Excludes asset retirement costs. | |||||||||||||||||||||||||||||||||||||
Goodwill_Tables
Goodwill (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||||||
Schedule Of Goodwill And Intangible Assets [Line Items] | ' | |||||||||||||||||||||||||||
Schedule Of Goodwill Text Block | ' | |||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||
Gross | Impairment | Carrying | ||||||||||||||||||||||||||
Amount(a) | Losses | Amount | ||||||||||||||||||||||||||
Balance, January 1, 2012 | $ | 4,608 | $ | 1,983 | $ | 2,625 | ||||||||||||||||||||||
Impairment losses | 0 | 0 | 0 | |||||||||||||||||||||||||
Balance, December 31, 2013 | $ | 4,608 | $ | 1,983 | $ | 2,625 | ||||||||||||||||||||||
__________ | ||||||||||||||||||||||||||||
(a) Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance. | ||||||||||||||||||||||||||||
Schedule of Finite-Lived Intangible Assets [Table Text Block] | ' | |||||||||||||||||||||||||||
Estimated amortization expense | ||||||||||||||||||||||||||||
Weighted Average Amortization Years (e) | Gross | Accumulated Amortization | Net | 2014 | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||||||
Generation (f) | ||||||||||||||||||||||||||||
Exelon Wind acquisition (a) | 18 | $ | 224 | $ | -41 | $ | 183 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | |||||||||||
Antelope Valley acquisition (b) | 25 | 190 | -4 | 186 | 8 | 8 | 8 | 8 | 8 | |||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||
Chicago settlement – 1999 agreement (c) | 21.8 | 100 | -76 | 24 | 3 | 3 | 3 | 4 | 4 | |||||||||||||||||||
Chicago settlement – 2003 agreement (d) | 17.9 | 62 | -38 | 24 | 4 | 4 | 4 | 3 | 3 | |||||||||||||||||||
Total intangible assets | $ | 576 | $ | -159 | $ | 417 | $ | 29 | $ | 29 | $ | 29 | $ | 29 | $ | 29 | ||||||||||||
__________ | ||||||||||||||||||||||||||||
(a) In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735 MWs of installed, operating wind capacity located in eight states. | ||||||||||||||||||||||||||||
(b) Refer to Note 4 – Merger and Acquisitions for additional information regarding Antelope Valley. | ||||||||||||||||||||||||||||
(c) In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd's franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020. | ||||||||||||||||||||||||||||
(d) In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago's behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation's obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement. | ||||||||||||||||||||||||||||
(e) Weighted-average amortization period was calculated at the date of acquisition for acquired assets or settlement agreement. | ||||||||||||||||||||||||||||
(f) Excludes $67 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. | ||||||||||||||||||||||||||||
Schedule Of Finite-Lived Intangible Assets Amortization Expense [Text Block] | ' | |||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | |||||||||||||||||||||||||
2013 | $ | 27 | $ | 20 | $ | 7 | ||||||||||||||||||||||
2012 | 20 | 13 | 7 | |||||||||||||||||||||||||
2011 | 19 | 12 | 7 | |||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ' | |||||||||||||||||||||||||||
Schedule Of Goodwill And Intangible Assets [Line Items] | ' | |||||||||||||||||||||||||||
Schedule Of Goodwill Text Block | ' | |||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||||
Gross | Impairment | Carrying | ||||||||||||||||||||||||||
Amount(a) | Losses | Amount | ||||||||||||||||||||||||||
Balance, January 1, 2012 | $ | 4,608 | $ | 1,983 | $ | 2,625 | ||||||||||||||||||||||
Impairment losses | 0 | 0 | 0 | |||||||||||||||||||||||||
Balance, December 31, 2013 | $ | 4,608 | $ | 1,983 | $ | 2,625 |
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | |||||||||||||||||||||||||||||||||
Fair Value Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ' | ||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||
Short-term liabilities | $ | 344 | $ | 3 | $ | 341 | $ | 0 | $ | 214 | $ | 214 | ||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||
due within one year) | 19,132 | 0 | 18,672 | 1,079 | 18,745 | 20,520 | ||||||||||||||||||||||||||||
Long-term debt to financing trusts | 648 | 0 | 0 | 631 | 648 | 664 | ||||||||||||||||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 1,020 | 763 | ||||||||||||||||||||||||||||
Preferred securities of subsidiary | 0 | 0 | 0 | 0 | 87 | 82 | ||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 1,230 | $ | 0 | $ | 0 | $ | 1,230 | ||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | ||||||||||||||||||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 882 | 0 | 0 | 882 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 294 | 0 | 294 | ||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | ||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | ||||||||||||||||||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | ||||||||||||||||||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | ||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 45 | 4 | 0 | 49 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 20 | 0 | 20 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning subtotal(c) | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | ||||||||||||||||||||||||||||||
Mutual funds(d)(e) | 54 | 0 | 0 | 54 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 56 | 0 | 0 | 56 | ||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -863 | -3,131 | -430 | -4,424 | ||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | -46 | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 30 | 39 | 0 | 69 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||
Other Investments | 0 | 0 | 15 | 15 | ||||||||||||||||||||||||||||||
Total assets | 4,533 | 5,575 | 1,054 | 11,162 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||
Economic hedges | -540 | -1,890 | -590 | -3,020 | ||||||||||||||||||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal(h) | 1 | -139 | -305 | -443 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | -31 | -17 | 0 | -48 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -16 | 0 | -16 | ||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -114 | 0 | -114 | ||||||||||||||||||||||||||||||
Total liabilities | 1 | -269 | -305 | -573 | ||||||||||||||||||||||||||||||
Total net assets | $ | 4,534 | $ | 5,306 | $ | 749 | $ | 10,589 | ||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 995 | $ | 0 | $ | 0 | $ | 995 | ||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 1,057 | 0 | 0 | 1,057 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 321 | 0 | 321 | ||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | ||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | ||||||||||||||||||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | ||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | ||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning | ||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other | ||||||||||||||||||||||||||||||||||
U.S. government corporations and agencies | 118 | 12 | 0 | 130 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||||||||||||||||
and political subdivisions of the states | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||
Pledged assets for Zion decommissioning subtotal(c) | 132 | 386 | 89 | 607 | ||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 2 | 0 | 0 | 2 | ||||||||||||||||||||||||||||||
Mutual funds(d)(e) | 69 | 0 | 0 | 69 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 71 | 0 | 0 | 71 | ||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||
Economic hedges | 861 | 3,173 | 641 | 4,675 | ||||||||||||||||||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | ||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal(g) | 80 | 1,076 | 656 | 1,812 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 0 | 114 | 0 | 114 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 63 | 0 | 63 | ||||||||||||||||||||||||||||||
Other Investments | 2 | 0 | 17 | 19 | ||||||||||||||||||||||||||||||
Total assets | 4,062 | 5,778 | 945 | 10,785 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -236 | -3,566 | ||||||||||||||||||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | ||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities(g)(h) | -83 | -228 | -289 | -600 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market liabilities | 0 | -84 | 0 | -84 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -33 | 0 | -33 | ||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -102 | 0 | -102 | ||||||||||||||||||||||||||||||
Total liabilities | -83 | -363 | -289 | -735 | ||||||||||||||||||||||||||||||
Total net assets | $ | 3,979 | $ | 5,415 | $ | 656 | $ | 10,050 | ||||||||||||||||||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||||||||||||||||||||||||||||||||
(b) Excludes net assets (liabilities) of $(5) million and $30 million at December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||
(c) Excludes net assets of $7 million at both December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||
(d) The mutual funds held by the Rabbi trusts include $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. | ||||||||||||||||||||||||||||||||||
(e) Excludes $32 million and $28 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||
(f) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||
(g) The Level 3 balance does not include current assets for Generation and current liabilities for ComEd of $226 million at December 31, 2012 related to the fair value of Generation's financial swap contract with ComEd. | ||||||||||||||||||||||||||||||||||
(h) The Level 3 balance includes the current and noncurrent liability of $17 million and $176 million at December 31, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Nuclear Decommissioning Trust Fund Investment | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 367 | $ | 17 | $ | 656 | (a) Includes a reduction for the reclassification of $155 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | |||||||||||||||||||||||
Total realized / unrealized gains (losses) | (b) Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. | |||||||||||||||||||||||||||||||||
Included in net income | 2 | 0 | -44 | (a) | 0 | -42 | (c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | |||||||||||||||||||||||||||
Included in other comprehensive income | 0 | 0 | 0 | 2 | 2 | |||||||||||||||||||||||||||||
Included in regulatory assets | 8 | 0 | -126 | (b) | 0 | -118 | ||||||||||||||||||||||||||||
Change in collateral | 0 | 0 | 7 | 0 | 7 | |||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | |||||||||||||||||||||||||||||
Sales | -28 | -39 | -11 | -8 | -86 | |||||||||||||||||||||||||||||
Settlements | -18 | - | -18 | |||||||||||||||||||||||||||||||
Transfers into Level 3 | 0 | 0 | 86 | (c) | 1 | 87 | ||||||||||||||||||||||||||||
Transfers out of Level 3 | 0 | 0 | -35 | -1 | -36 | |||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 272 | $ | 15 | $ | 749 | ||||||||||||||||||||||||
The amount of total gains included in income | ||||||||||||||||||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | 0 | $ | 167 | $ | 0 | $ | 168 | ||||||||||||||||||||||||
(a) Includes a reduction for the reclassification of $211 million of realized gains due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2013. | ||||||||||||||||||||||||||||||||||
(b) Excludes decreases in fair value of $11 million of and realized losses reclassified due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||
(c) Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | ||||||||||||||||||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net (a) | ||||||||||||||||||||||||||||||||
Total gains (losses) included in income for the year ended | ||||||||||||||||||||||||||||||||||
31-Dec-13 | $ | -152 | $ | 108 | $ | 2 | ||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and liabilities | ||||||||||||||||||||||||||||||||||
held for the year ended December 31, 2013 | $ | 40 | $ | 127 | $ | 1 | ||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other, net | ||||||||||||||||||||||||||||||||
Total gains included in income for the year ended | ||||||||||||||||||||||||||||||||||
31-Dec-12 | $ | 54 | $ | 5 | $ | 0 | ||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities | ||||||||||||||||||||||||||||||||||
held for the year ended December 31, 2012 | $ | 230 | $ | -16 | $ | 0 | ||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique | ' | ' | ||||||||||||||||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 (c) | Valuation Technique | Unobservable Input | Range | Type of trade | Fair Value at December 31, 2012 (d) | Valuation Technique | Unobservable Input | Range | |||||||||||||||||||||||||
Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 488 | Discounted Cash Flow | Forward power price | $ | 8 | - | $ | 176 | (d) | Mark-to-market derivatives – Economic Hedges (Generation) (a) | $ | 473 | Discounted Cash Flow | Forward power price | $ | 14 | - | $ | 79 | ||||||||||||||
Forward gas price | $ | 2.98 | - | $ | 16.63 | (d) | Forward gas price | $ | 3.26 | - | $ | 6.27 | ||||||||||||||||||||||
Option Model | Volatility percentage | 15 | % | - | 142 | % | Option Model | Volatility percentage | 28 | % | - | 132 | % | |||||||||||||||||||||
Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | 3 | Discounted Cash Flow | Forward power price | $ | 10 | - | $ | 176 | (d) | Mark-to-market derivatives – Proprietary trading (Generation) (a) | $ | -6 | Discounted Cash Flow | Forward power price | $ | 15 | - | $ | 106 | ||||||||||||||
Option Model | Volatility percentage | 14 | % | - | 19 | % | Option Model | Volatility percentage | 16 | % | - | 48 | % | |||||||||||||||||||||
Mark-to-market derivatives (ComEd) | $ | -193 | Discounted Cash Flow | Forward heat rate (b) | 8 | - | 9 | Mark-to-market derivatives – Transactions with affiliates (Generation and ComEd) (b) | $ | 226 | Discounted Cash Flow | Marketability reserve | 8 | % | - | 9 | % | |||||||||||||||||
Marketability reserve | 3.5 | % | - | 8 | % | |||||||||||||||||||||||||||||
Renewable factor | 84 | % | - | 128 | % | Mark-to-market derivatives (ComEd) | $ | -67 | Discounted Cash Flow | Forward heat rate (c) | 8 | - | 9.5 | |||||||||||||||||||||
_____________________ | Marketability reserve | 3.5 | % | - | 8.3 | % | ||||||||||||||||||||||||||||
Renewable factor | 81 | % | - | 123 | % | |||||||||||||||||||||||||||||
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | ||||||||||||||||||||||||||||||||||
Includes current assets for Generation and current liabilities for ComEd of $226 million, related to the fair value of the five-year financial swap contract between Generation and ComEd that ended in May 2013, which eliminates in consolidation. | ||||||||||||||||||||||||||||||||||
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery. | ||||||||||||||||||||||||||||||||||
The fair values do not include cash collateral held on Level 3 positions of $33 million as of December 31, 2012. | ||||||||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ' | ||||||||||||||||||||||||||||||||
Fair Value Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ' | ||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||
Short-term liabilities | $ | 22 | $ | 0 | $ | 22 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||
due within one year) | 7,729 | 0 | 6,586 | 1,062 | 7,483 | 7,849 | ||||||||||||||||||||||||||||
SNF obligation | 1,021 | 0 | 790 | 0 | 1,020 | 763 | ||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 1,006 | $ | 0 | $ | 0 | $ | 1,006 | ||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | 0 | 0 | 459 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 1,776 | 0 | 0 | 1,776 | ||||||||||||||||||||||||||||||
Exchange traded funds | 115 | 0 | 0 | 115 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 2,271 | 0 | 2,271 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | 0 | 4,162 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||
government corporations and agencies | 882 | 0 | 0 | 882 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 294 | 0 | 294 | ||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 87 | 0 | 87 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 10 | 0 | 10 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 40 | 0 | 40 | ||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 7 | 0 | 7 | ||||||||||||||||||||||||||||||
Mutual funds | 0 | 18 | 0 | 18 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 314 | 314 | ||||||||||||||||||||||||||||||
Private Equity | 0 | 0 | 5 | 5 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 14 | 0 | 14 | ||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 26 | 0 | 26 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 16 | 0 | 0 | 16 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||
government corporations and agencies | 45 | 4 | 0 | 49 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 20 | 0 | 20 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 227 | 0 | 227 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | 0 | 296 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 112 | 112 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(e) | -863 | -3,131 | -430 | -4,424 | ||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | -46 | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||
Interest Rate mark-to-market derivative assets | 30 | 32 | 0 | 62 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | -30 | -2 | 0 | -32 | ||||||||||||||||||||||||||||||
Interest Rate mark-to-market derivative assets subtotal | 0 | 30 | 0 | 30 | ||||||||||||||||||||||||||||||
Other investments | 0 | 0 | 15 | 15 | ||||||||||||||||||||||||||||||
Total assets | 4,266 | 5,568 | 1,054 | 10,888 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||
Economic hedges | -540 | -1,890 | -397 | -2,827 | ||||||||||||||||||||||||||||||
Proprietary trading | -328 | -1,256 | -119 | -1,703 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(e) | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal | 1 | -139 | -112 | -250 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | -31 | -13 | 0 | -44 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | 0 | 32 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -12 | 0 | -12 | ||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -29 | 0 | -29 | ||||||||||||||||||||||||||||||
Total liabilities | 1 | -180 | -112 | -291 | ||||||||||||||||||||||||||||||
Total net assets | $ | 4,267 | $ | 5,388 | $ | 942 | $ | 10,597 | ||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents(a) | $ | 487 | $ | 0 | $ | 0 | $ | 487 | ||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 245 | 0 | 0 | 245 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 1,480 | 0 | 0 | 1,480 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 1,933 | 0 | 1,933 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 1,480 | 1,933 | 0 | 3,413 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||
government corporations and agencies | 1,057 | 0 | 0 | 1,057 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 321 | 0 | 321 | ||||||||||||||||||||||||||||||
Debt securities issued by foreign governments | 0 | 93 | 0 | 93 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 1,788 | 0 | 1,788 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 24 | 0 | 24 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 45 | 0 | 45 | ||||||||||||||||||||||||||||||
Residential mortgage-backed securities (non-agency) | 0 | 11 | 0 | 11 | ||||||||||||||||||||||||||||||
Mutual funds | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 1,057 | 2,305 | 0 | 3,362 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 183 | 183 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 15 | 0 | 15 | ||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments subtotal(b) | 2,782 | 4,253 | 183 | 7,218 | ||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning | ||||||||||||||||||||||||||||||||||
Cash equivalents | 0 | 23 | 0 | 23 | ||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||
Individually held | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||
Commingled funds | 0 | 9 | 0 | 9 | ||||||||||||||||||||||||||||||
Equity funds subtotal | 14 | 9 | 0 | 23 | ||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury and other U.S. | ||||||||||||||||||||||||||||||||||
government corporations and agencies | 118 | 12 | 0 | 130 | ||||||||||||||||||||||||||||||
Debt securities issued by states of the United States and | ||||||||||||||||||||||||||||||||||
political subdivisions of the states | 0 | 37 | 0 | 37 | ||||||||||||||||||||||||||||||
Corporate debt securities | 0 | 249 | 0 | 249 | ||||||||||||||||||||||||||||||
Federal agency mortgage-backed securities | 0 | 49 | 0 | 49 | ||||||||||||||||||||||||||||||
Commercial mortgage-backed securities (non-agency) | 0 | 6 | 0 | 6 | ||||||||||||||||||||||||||||||
Fixed income subtotal | 118 | 353 | 0 | 471 | ||||||||||||||||||||||||||||||
Middle market lending | 0 | 0 | 89 | 89 | ||||||||||||||||||||||||||||||
Other debt obligations | 0 | 1 | 0 | 1 | ||||||||||||||||||||||||||||||
Pledged assets for Zion Station decommissioning subtotal(c) | 132 | 386 | 89 | 607 | ||||||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Cash equivalents | 1 | 0 | 0 | 1 | ||||||||||||||||||||||||||||||
Mutual funds(d) | 13 | 0 | 0 | 13 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 14 | 0 | 0 | 14 | ||||||||||||||||||||||||||||||
Commodity mark-to-market derivative assets | ||||||||||||||||||||||||||||||||||
Economic hedges | 861 | 3,173 | 867 | 4,901 | ||||||||||||||||||||||||||||||
Proprietary trading | 1,042 | 2,078 | 73 | 3,193 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | -1,823 | -4,175 | -58 | -6,056 | ||||||||||||||||||||||||||||||
Commodity mark-to-market assets subtotal | 80 | 1,076 | 882 | 2,038 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets | 0 | 101 | 0 | 101 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | -51 | 0 | -51 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative assets subtotal | 0 | 50 | 0 | 50 | ||||||||||||||||||||||||||||||
Other investments | 2 | 0 | 17 | 19 | ||||||||||||||||||||||||||||||
Total assets | 3,497 | 5,765 | 1,171 | 10,433 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Commodity mark-to-market derivative liabilities | ||||||||||||||||||||||||||||||||||
Economic hedges | -1,041 | -2,289 | -169 | -3,499 | ||||||||||||||||||||||||||||||
Proprietary trading | -1,084 | -1,959 | -78 | -3,121 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral(f) | 2,042 | 4,020 | 25 | 6,087 | ||||||||||||||||||||||||||||||
Commodity mark-to-market liabilities subtotal | -83 | -228 | -222 | -533 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities | 0 | -84 | 0 | -84 | ||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 0 | 51 | 0 | 51 | ||||||||||||||||||||||||||||||
Interest rate mark-to-market derivative liabilities subtotal | 0 | -33 | 0 | 0 | -33 | |||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -28 | 0 | -28 | ||||||||||||||||||||||||||||||
Total liabilities | -83 | -289 | -222 | -594 | ||||||||||||||||||||||||||||||
Total net assets | $ | 3,414 | $ | 5,476 | $ | 949 | $ | 9,839 | ||||||||||||||||||||||||||
(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | ||||||||||||||||||||||||||||||||||
(b) Excludes net assets (liabilities) of $(5) million and $30 million at December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||
(c) Excludes net assets of $7 million at both December 31, 2013 December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | ||||||||||||||||||||||||||||||||||
(d) Excludes $10 million and $8 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | ||||||||||||||||||||||||||||||||||
(e) Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | ||||||||||||||||||||||||||||||||||
(f) The Level 3 balance includes current assets for Generation of $226 million at December 31, 2012 related to the fair value of Generation's financial swap contract with ComEd, which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | For the Year Ended December 31, 2012 | Nuclear Decommissioning Trust Fund Investments | Pledged Assets for Zion Station Decommissioning | Mark-to-Market Derivatives | Other Investments | Total | |||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | Balance as of January 1, 2012 | $ | 13 | $ | 37 | $ | 817 | $ | 0 | $ | 867 | |||||||||||||
Total unrealized / realized gains (losses) | Total realized / unrealized gains (losses) | |||||||||||||||||||||||||||||||||
Included in income | 2 | 0 | -51 | (a)(b) | 0 | -49 | Included in income | 0 | 0 | 66 | (a) | 0 | 66 | |||||||||||||||||||||
Included in other comprehensive income | 0 | 0 | -219 | (b) | 2 | -217 | Included in other comprehensive income | 0 | 0 | -475 | (b) | 0 | -475 | |||||||||||||||||||||
Included in noncurrent payables to affiliates | 8 | 0 | 0 | 0 | 8 | Included in noncurrent payables to affiliates | 1 | 0 | 0 | 0 | 1 | |||||||||||||||||||||||
Change in collateral | 0 | 0 | 7 | 0 | 7 | Changes in collateral | 0 | 0 | -32 | 0 | -32 | |||||||||||||||||||||||
Purchases, sales, issuances and settlements | Purchases, sales, issuances and settlements | |||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | Purchases | 169 | 63 | 334 | (c) | 17 | 583 | ||||||||||||||||||||||
Sales | -28 | -39 | -11 | -8 | -86 | Sales | 0 | -11 | 0 | 0 | -11 | |||||||||||||||||||||||
Settlements | -18 | 0 | 0 | 0 | -18 | Transfers into Level 3 | 0 | 0 | 39 | 0 | 39 | |||||||||||||||||||||||
Transfers into Level 3 | 0 | 0 | 86 | (c) | 1 | 87 | Transfers out of Level 3 | 0 | 0 | -89 | 0 | -89 | ||||||||||||||||||||||
Transfers out of Level 3 | 0 | 0 | -35 | -1 | -36 | |||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | Balance as of December 31, 2012 | $ | 183 | $ | 89 | $ | 660 | 17 | $ | 949 | ||||||||||||||
The amount of total losses included in income | ||||||||||||||||||||||||||||||||||
attributed to the change in unrealized gains related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | 0 | $ | 156 | $ | 0 | $ | 157 | The amount of total gains included in income | |||||||||||||||||||||||
(a) Includes a reduction for the reclassification of $207 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2013. | attributed to the change in unrealized gains related to assets and liabilities as of December 31, 2012 | $ | 0 | $ | 0 | $ | 165 | $ | 0 | $ | 165 | |||||||||||||||||||||||
(b) Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | (a) Includes a reduction for the reclassification of $99 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | |||||||||||||||||||||||||||||||||
(c) Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | (b) Includes $98 million of increases in fair value and $566 million of realized losses reclassified from OCI due to settlements associated with Generation's financial swap contract with ComEd for the year ended December 31, 2012. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||
(c) Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. | ||||||||||||||||||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other - net (a) | ||||||||||||||||||||||||||||||||
Total gains (losses) included in income for the year ended | ||||||||||||||||||||||||||||||||||
31-Dec-13 | $ | -158 | $ | 107 | $ | 2 | ||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and | ||||||||||||||||||||||||||||||||||
liabilities held for the year ended December 31, 2013 | $ | 30 | $ | 126 | $ | 1 | ||||||||||||||||||||||||||||
Operating Revenue | Purchased Power and Fuel | Other - net (a) | ||||||||||||||||||||||||||||||||
Total gains included in income for the year ended | ||||||||||||||||||||||||||||||||||
31-Dec-12 | $ | 61 | $ | 5 | $ | 0 | ||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and | ||||||||||||||||||||||||||||||||||
liabilities held for the year ended December 31, 2012 | $ | 181 | $ | -16 | $ | 0 | ||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ' | ' | ||||||||||||||||||||||||||||||||
Fair Value Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ' | ||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||
Short-term liabilities | $ | 184 | $ | 0 | $ | 184 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||
due within one year) | 5,675 | 0 | 6,238 | 17 | 5,567 | 6,548 | ||||||||||||||||||||||||||||
Long-term debt to financing trust | 206 | 0 | 0 | 202 | 206 | 212 | ||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | Includes $98 million of increases in fair value and $566 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the year ended December 31, 2012. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||
Rabbi trust investments | Includes $34 million of decreases in the fair value and realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2012 . | |||||||||||||||||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||
Total assets | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | ||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (b) | 0 | 0 | -193 | -193 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -8 | -193 | -201 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | -8 | $ | -193 | $ | -196 | ||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 111 | $ | 0 | $ | 0 | $ | 111 | ||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds | 8 | 0 | 0 | 8 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 8 | 0 | 0 | 8 | ||||||||||||||||||||||||||||||
Total assets | 119 | 0 | 0 | 119 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -8 | 0 | -8 | ||||||||||||||||||||||||||||||
Mark-to-market derivative liabilities (a)(b) | 0 | 0 | -293 | -293 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -8 | -293 | -301 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 119 | $ | -8 | $ | -293 | $ | -182 | ||||||||||||||||||||||||||
(a) The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||
(b) The Level 3 balance includes the current and noncurrent liability of $17 million and $176 million at December 31, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | ||||||||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
For the Year Ended December 31, 2013 | Mark-to-Market Derivatives | |||||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | -293 | ||||||||||||||||||||||||||||||||
Total realized / unrealized gains included in regulatory assets (a)(b) | 100 | |||||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | -193 | ||||||||||||||||||||||||||||||||
(a) Includes $11 million of decrease in fair value and realized gains due to settlements of $215 million associated with ComEd's financial swap contract with Generation for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | ||||||||||||||||||||||||||||||||||
(b) Includes $126 million of increases in the fair value and realized losses due to settlements of $7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2013 . | ||||||||||||||||||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
Twelve Months Ended December 31, 2012 | Mark-to-Market Derivatives | |||||||||||||||||||||||||||||||||
Balance as of January 1, 2012 | $ | -800 | ||||||||||||||||||||||||||||||||
Total realized / unrealized gains included in regulatory assets (a)(b) | 507 | |||||||||||||||||||||||||||||||||
Balance as of December 31, 2012 | $ | -293 | ||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | ' | ' | ||||||||||||||||||||||||||||||||
Fair Value Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ' | ||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||
Short-term liabilities | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 210 | $ | 210 | ||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||
due within one year) | 2,197 | 0 | 2,358 | 0 | 1,947 | 2,264 | ||||||||||||||||||||||||||||
Long-term debt to financing trusts | 184 | 0 | 0 | 180 | 184 | 188 | ||||||||||||||||||||||||||||
Preferred securities | 0 | 0 | 0 | 0 | 87 | 82 | ||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | (a) Excludes $14 million and $13 million of the cash surrender value of life insurance investments at December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 175 | $ | 0 | $ | 0 | $ | 175 | ||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds (a) | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||
Total assets | 184 | 0 | 0 | 184 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -17 | 0 | -17 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -17 | 0 | -17 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 184 | $ | -17 | $ | 0 | $ | 167 | ||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 346 | $ | 0 | $ | 0 | $ | 346 | ||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds (a) | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 9 | 0 | 0 | 9 | ||||||||||||||||||||||||||||||
Total assets | 355 | 0 | 0 | 355 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -18 | 0 | -18 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -18 | 0 | -18 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 355 | $ | -18 | $ | 0 | $ | 337 | ||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | ' | ' | ||||||||||||||||||||||||||||||||
Fair Value Tables [Line Items] | ' | ' | ||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | ' | ' | ||||||||||||||||||||||||||||||||
31-Dec-13 | 31-Dec-12 | |||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair | |||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Amount | Value | |||||||||||||||||||||||||||||
Short-term liabilities | $ | 138 | $ | 3 | $ | 135 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||||
Long-term debt (including amounts | ||||||||||||||||||||||||||||||||||
due within one year) | 2,011 | 0 | 2,148 | 0 | 2,178 | 2,468 | ||||||||||||||||||||||||||||
Long-term debt to financing trusts | 258 | 0 | 0 | 249 | 258 | 263 | ||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ' | ' | ||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 31 | $ | 0 | $ | 0 | $ | 31 | ||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds | 6 | 0 | 0 | 6 | ||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 6 | 0 | 0 | 6 | ||||||||||||||||||||||||||||||
Total assets | 37 | 0 | 0 | 37 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -6 | 0 | -6 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -6 | 0 | -6 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 37 | $ | -6 | $ | 0 | $ | 31 | ||||||||||||||||||||||||||
As of December 31, 2012 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 33 | $ | 0 | $ | 0 | $ | 33 | ||||||||||||||||||||||||||
Rabbi trust investments | ||||||||||||||||||||||||||||||||||
Mutual funds | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||
Rabbit trust investments subtotal | 5 | 0 | 0 | 5 | ||||||||||||||||||||||||||||||
Total assets | 38 | 0 | 0 | 38 | ||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||
Deferred compensation obligation | 0 | -5 | 0 | -5 | ||||||||||||||||||||||||||||||
Total liabilities | 0 | -5 | 0 | -5 | ||||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 38 | $ | -5 | $ | 0 | $ | 33 |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||||
Derivative Financial Instruments [Line Items] | ' | ||||||||||||||||||||||||||||
Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense | ' | ||||||||||||||||||||||||||||
Twelve Months Ended December 31, | |||||||||||||||||||||||||||||
Income Statement | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Location | Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||
Generation | Interest expense(a) | $ | -15 | $ | -6 | $ | 0 | $ | 0 | $ | -6 | $ | 0 | ||||||||||||||||
Exelon | Interest expense | $ | -24 | $ | -9 | $ | 1 | $ | 11 | $ | -3 | $ | -1 | ||||||||||||||||
______ ____ | |||||||||||||||||||||||||||||
For the years ended December 31, 2013 and 2012, the loss on Generation swaps included $16 million and $12 realized in earnings, respectively, with $2 million and an immaterial amount excluded from hedge effectiveness testing, respectively. | |||||||||||||||||||||||||||||
Summary of the derivative fair value | ' | ||||||||||||||||||||||||||||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||||||||||||||
Generation | Other | Exelon | |||||||||||||||||||||||||||
Description | Derivatives Designated as Hedging Instruments | Economic Hedges | Proprietary Trading (a) | Collateral and Netting (b) | Subtotal | Derivatives Designated as Hedging Instruments | Total | ||||||||||||||||||||||
Mark-to-market derivative assets (Current Assets) | $ | 0 | $ | 3 | $ | 20 | $ | -19 | $ | 4 | $ | 0 | $ | 4 | |||||||||||||||
Mark-to-market derivative assets (Noncurrent Assets) | 38 | 8 | 32 | -32 | 46 | 13 | 59 | ||||||||||||||||||||||
Total mark-to-market derivative assets | $ | 38 | $ | 11 | $ | 52 | $ | -51 | $ | 50 | $ | 13 | $ | 63 | |||||||||||||||
Mark-to-market derivative liabilities (Current Liabilities) | $ | -1 | $ | -1 | $ | -19 | $ | 19 | $ | -2 | $ | 0 | $ | -2 | |||||||||||||||
Mark-to-market derivative liabilities (Noncurrent Liabilities) | -31 | 0 | -32 | 32 | -31 | 0 | -31 | ||||||||||||||||||||||
Total mark-to-market derivative liabilities | -32 | -1 | -51 | 51 | -33 | 0 | -33 | ||||||||||||||||||||||
Total mark-to-market derivative net assets (liabilities) | $ | 6 | $ | 10 | $ | 1 | $ | 0 | $ | 17 | $ | 13 | $ | 30 | |||||||||||||||
Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | |||||||||||||||||||||||||||||
Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||||||||||||||
Generation | ComEd | Exelon | |||||||||||||||||||||||||||
Collateral | |||||||||||||||||||||||||||||
Economic | Proprietary | and | Subtotal | Economic | Total | ||||||||||||||||||||||||
Derivatives | Hedges | Trading | Netting(a) | (b) | Hedges(c) | Derivatives | |||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(current assets) | $ | 2,616 | $ | 1,476 | $ | -3,364 | $ | 728 | $ | 0 | $ | 728 | |||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(noncurrent assets) | 1,344 | 285 | -1,060 | 569 | 0 | 569 | |||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
assets | $ | 3,960 | $ | 1,761 | $ | -4,424 | $ | 1,297 | $ | 0 | $ | 1,297 | |||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(current liabilities) | $ | -2,023 | $ | -1,410 | $ | 3,292 | $ | -141 | $ | -17 | $ | -158 | |||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(noncurrent liabilities) | -804 | -293 | 988 | -109 | -176 | -285 | |||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
liabilities | $ | -2,827 | $ | -1,703 | $ | 4,280 | $ | -250 | $ | -193 | $ | -443 | |||||||||||||||||
Total mark-to-market derivative net | |||||||||||||||||||||||||||||
assets (liabilities) | $ | 1,133 | $ | 58 | $ | -144 | $ | 1,047 | $ | -193 | $ | 854 | |||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above. | |||||||||||||||||||||||||||||
(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | |||||||||||||||||||||||||||||
(c) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||
Generation | ComEd | Exelon | |||||||||||||||||||||||||||
Economic | Collateral | Economic | Intercompany | ||||||||||||||||||||||||||
Hedges | Proprietary | and | Subtotal | Hedges | Eliminations | Total | |||||||||||||||||||||||
Derivatives | (a) | Trading | Netting(b) | (c) | (a)(d) | (a) | Derivatives | ||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(current assets) | $ | 2,883 | $ | 2,469 | $ | -4,418 | $ | 934 | $ | 0 | $ | 0 | $ | 934 | |||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
with affiliate (current assets) | 226 | 0 | 0 | 226 | 0 | -226 | 0 | ||||||||||||||||||||||
Mark-to-market derivative assets | |||||||||||||||||||||||||||||
(noncurrent assets) | 1,792 | 724 | -1,638 | 878 | 0 | 0 | 878 | ||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
assets | $ | 4,901 | $ | 3,193 | $ | -6,056 | $ | 2,038 | $ | 0 | $ | -226 | $ | 1,812 | |||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(current liabilities) | $ | -2,419 | $ | -2,432 | $ | 4,519 | $ | -332 | $ | -18 | $ | 0 | $ | -350 | |||||||||||||||
Mark-to-market derivative liability | |||||||||||||||||||||||||||||
with affiliate (current liabilities) | 0 | 0 | 0 | 0 | -226 | 226 | 0 | ||||||||||||||||||||||
Mark-to-market derivative liabilities | |||||||||||||||||||||||||||||
(noncurrent liabilities) | -1,080 | -689 | 1,568 | -201 | -49 | 0 | -250 | ||||||||||||||||||||||
Total mark-to-market derivative | |||||||||||||||||||||||||||||
liabilities | $ | -3,499 | $ | -3,121 | $ | 6,087 | $ | -533 | $ | -293 | $ | 226 | $ | -600 | |||||||||||||||
Total mark-to-market derivative net | |||||||||||||||||||||||||||||
assets (liabilities) | $ | 1,402 | $ | 72 | $ | 31 | $ | 1,505 | $ | -293 | $ | 0 | $ | 1,212 | |||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above. | |||||||||||||||||||||||||||||
(b) Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above. | |||||||||||||||||||||||||||||
(c) Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $ (31) million at December 31, 2012. | |||||||||||||||||||||||||||||
(d) Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||
The activity of accumulated OCI related to cash flow hedges | ' | ||||||||||||||||||||||||||||
Total Cash Flow Hedge OCI Activity, Net of Income Tax | |||||||||||||||||||||||||||||
Generation | Exelon | ||||||||||||||||||||||||||||
Income Statement Location | Energy-Related Hedges | Total Cash Flow Hedges | |||||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
1-Jan-12 | $ | 925 | (a)(d) | $ | 488 | ||||||||||||||||||||||||
Effective portion of changes in fair value | 432 | (b) | 330 | (e) | |||||||||||||||||||||||||
Reclassifications from accumulated OCI to | |||||||||||||||||||||||||||||
net income | Operating Revenues | -828 | (c) | -453 | |||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | 3 | 3 | ||||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
31-Dec-12 | 532 | (a)(d) | 368 | ||||||||||||||||||||||||||
Effective portion of changes in fair value | 0 | 29 | (e) | ||||||||||||||||||||||||||
Reclassifications from accumulated OCI to | |||||||||||||||||||||||||||||
net income | Operating Revenues | -413 | (c) | -277 | |||||||||||||||||||||||||
Accumulated OCI derivative gain at | |||||||||||||||||||||||||||||
31-Dec-13 | $ | 119 | (d) | $ | 120 | ||||||||||||||||||||||||
__________ | |||||||||||||||||||||||||||||
(a) Includes $133 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011 . | |||||||||||||||||||||||||||||
(b) Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the year ended December 31, 2012. As of the merger date, cash flow hedges were discontinued, as such, this amount represents changes in fair value prior to the merger date. | |||||||||||||||||||||||||||||
(c) Includes $133 million and $375 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||||||
(d) Excludes $5 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||||||||||||||||
(e) Includes $15 million and $9 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2013 and 2012, respectively | |||||||||||||||||||||||||||||
Other Derivatives - Gain (loss) and reclassification | ' | ||||||||||||||||||||||||||||
Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. | |||||||||||||||||||||||||||||
Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues. | |||||||||||||||||||||||||||||
Change in fair value and reclassification of derivative contracts | ' | ||||||||||||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | |||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | Operating | |||||||||||||||||||||||||||
Year Ended December 31, 2013 | Revenues | and Fuel | Total | Revenues (a) | Total | ||||||||||||||||||||||||
Change in fair value | $ | 285 | $ | 180 | $ | 465 | $ | -6 | $ | 459 | |||||||||||||||||||
Reclassification to realized at settlement | -65 | 104 | 39 | 13 | 52 | ||||||||||||||||||||||||
Net mark-to-market gains | $ | 220 | $ | 284 | $ | 504 | $ | 7 | $ | 511 | |||||||||||||||||||
Generation | Intercompany Eliminations | Exelon | |||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | Operating | |||||||||||||||||||||||||||
Year Ended December 31, 2012 | Revenues | and Fuel | Total | Revenues (a) | Total | ||||||||||||||||||||||||
Change in fair value | $ | -362 | $ | 215 | $ | -147 | $ | -94 | $ | -241 | |||||||||||||||||||
Reclassification to realized at settlement | 429 | 238 | 667 | 101 | 768 | ||||||||||||||||||||||||
Net mark-to-market gains | $ | 67 | $ | 453 | $ | 520 | $ | 7 | $ | 527 | |||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | ||||||||||||||||||||||||||||
Year Ended December 31, 2011 (As Reported) | Revenues | and Fuel | Total | ||||||||||||||||||||||||||
Change in fair value | $ | 87 | $ | 131 | $ | 218 | |||||||||||||||||||||||
Reclassification to realized at settlement | -296 | -219 | -515 | ||||||||||||||||||||||||||
Net mark-to-market (losses)(b) | $ | -209 | $ | -88 | $ | -297 | |||||||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||
Purchased | |||||||||||||||||||||||||||||
Operating | Power | ||||||||||||||||||||||||||||
Year Ended December 31, 2011 (Pro Forma) | Revenues | and Fuel | Total | ||||||||||||||||||||||||||
Change in fair value | $ | 258 | $ | -40 | $ | 218 | |||||||||||||||||||||||
Reclassification to realized at settlement | -516 | 1 | -515 | ||||||||||||||||||||||||||
Net mark-to-market (losses)(b) | $ | -258 | $ | -39 | $ | -297 | |||||||||||||||||||||||
For the Years Ended | |||||||||||||||||||||||||||||
Location on Income | December 31, | ||||||||||||||||||||||||||||
Statement | 2013 | 2012 | 2011 | ||||||||||||||||||||||||||
Change in fair value | Operating Revenue | $ | -21 | $ | -12 | $ | 23 | ||||||||||||||||||||||
Reclassification to realized at settlement | Operating Revenue | -18 | 108 | -26 | |||||||||||||||||||||||||
Net mark-to-market gains (losses) | Operating Revenue | $ | -39 | $ | 96 | $ | -3 | ||||||||||||||||||||||
Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements | ' | ||||||||||||||||||||||||||||
Total | Number of | Net Exposure of | |||||||||||||||||||||||||||
Exposure | Counterparties | Counterparties | |||||||||||||||||||||||||||
Before Credit | Credit | Net | Greater than 10% | Greater than 10% | |||||||||||||||||||||||||
Rating as of December 31, 2013 | Collateral | Collateral (a) | Exposure | of Net Exposure | of Net Exposure | ||||||||||||||||||||||||
Investment grade | $ | 1,621 | $ | 172 | $ | 1,449 | $ | 1 | $ | 491 | |||||||||||||||||||
Non-investment grade | 27 | 9 | 18 | 0 | 0 | ||||||||||||||||||||||||
No external ratings | |||||||||||||||||||||||||||||
Internally rated - investment grade | 416 | 1 | 415 | 1 | 226 | ||||||||||||||||||||||||
Internally rated - non-investment grade | 30 | 2 | 28 | 0 | 0 | ||||||||||||||||||||||||
Total | $ | 2,094 | $ | 184 | $ | 1,910 | $ | 2 | $ | 717 | |||||||||||||||||||
Net Credit Exposure by Type of Counterparty | 31-Dec-13 | ||||||||||||||||||||||||||||
Financial Institutions | $ | 256 | |||||||||||||||||||||||||||
Investor-owned utilities, marketers, power producers | 684 | ||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 907 | ||||||||||||||||||||||||||||
Other | 63 | ||||||||||||||||||||||||||||
Total | $ | 1,910 | |||||||||||||||||||||||||||
As of December 31, 2013, credit collateral held from counterparties where Generation had credit exposure included $155 million of cash and $29 million of letters of credit | |||||||||||||||||||||||||||||
For the Years Ended December 31, | |||||||||||||||||||||||||||||
Credit-Risk Related Contingent Feature | 2013 | 2012 | |||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | $ | ($1,056) | $ | ($1,849) | |||||||||||||||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements (b) | $846 | $1,426 | |||||||||||||||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature (c) | $ | ($210) | $ | ($423) | |||||||||||||||||||||||||
____________________ | |||||||||||||||||||||||||||||
Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent ignoring the effects of master netting agreements. | |||||||||||||||||||||||||||||
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | |||||||||||||||||||||||||||||
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. | |||||||||||||||||||||||||||||
Debt_and_Credit_Agreements_Yea
Debt and Credit Agreements Year-End (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||
Schedule Of Short Term Debt [Text Block] | ' | ||||||||||||||||||
Maximum Program Size at December 31, | Outstanding Commercial Paper at December 31, | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | |||||||||||||||||
Commercial Paper Issuer | 2013 (a) | 2012 (a) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Exelon Corporate | $ | 500 | $ | 500 | $ | 0 | $ | 0 | 0.27 | % | 0.47 | % | |||||||
Generation | 5,600 | 5,600 | 0 | 0 | 0.32 | % | 0.45 | % | |||||||||||
ComEd | 1,000 | 1,000 | 184 | 0 | 0.4 | % | 0.5 | % | |||||||||||
PECO | 600 | 600 | 0 | 0 | n.a. | n.a. | |||||||||||||
BGE | 600 | 600 | 135 | 0 | 0.31 | % | 0.43 | % | |||||||||||
Total | $ | 8,300 | $ | 8,300 | $ | 319 | $ | 0 | |||||||||||
(a) Equals aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of a $75 million bilateral agreement) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||||
Exelon | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 254 | $ | 199 | $ | 218 | |||||||||||||
Maximum borrowings outstanding | 682 | 505 | 600 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.37 | % | 0.48 | % | 0.5 | % | |||||||||||||
Average interest rates, at December 31 | 0.35 | % | n.a. | 0.44 | % | ||||||||||||||
Generation | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 42 | $ | 4 | $ | 51 | |||||||||||||
Maximum borrowings outstanding | 291 | 165 | 304 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.45 | % | 0.48 | ||||||||||||||
Average interest rates, at December 31 | n.a. | n.a. | n.a. | ||||||||||||||||
ComEd | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 203 | $ | 110 | $ | 36 | |||||||||||||
Maximum borrowings outstanding | 446 | 366 | 407 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.4 | % | 0.5 | % | 0.71 | % | |||||||||||||
Average interest rates, at December 31 | 0.37 | % | n.a. | n.a. | |||||||||||||||
BGE | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 35 | $ | 6 | $ | 26 | |||||||||||||
Maximum borrowings outstanding | 135 | 76 | 190 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.31 | % | 0.43 | % | 0.38 | % | |||||||||||||
Average interest rates, computed at December 31 | 0.31 | % | n.a. | n.a. | |||||||||||||||
Schedule Of Line Of Credit Facilities Text Block | ' | ||||||||||||||||||
Available Capacity at December 31, 2013 | |||||||||||||||||||
Borrower | Aggregate Bank Commitment (a) | Facility Draws | Outstanding Letters of Credit | Actual | To Support Additional Commercial Paper (b) | ||||||||||||||
Exelon Corporate | $ | 500 | $ | — | $ | 2 | $ | 498 | $ | 498 | |||||||||
Generation | 5,675 | — | 1,413 | 4,262 | 4,187 | ||||||||||||||
ComEd | 1,000 | — | — | 1,000 | 816 | ||||||||||||||
PECO | 600 | — | 1 | 599 | 599 | ||||||||||||||
BGE | 600 | — | — | 600 | 465 | ||||||||||||||
Total | $ | 8,375 | $ | — | $ | 1,416 | $ | 6,959 | $ | 6,565 | |||||||||
Schedule Of Credit Agreement Covenants [Text Block] | ' | ||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Credit facility threshold | 2.50 to 1 | 3.00 to 1 | 2.00 to 1 | 2.00 to 1 | 2.00 to 1 | ||||||||||||||
At December 31, 2013, the interest coverage ratios at the Registrants were as follows: | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Interest coverage ratio | 7.67 | 11.45 | 5.2 | 8.29 | 7.85 | ||||||||||||||
Schedule Of Debt Instruments Text Block | ' | ||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b) : | |||||||||||||||||||
Fixed rates | 1.2 | % | - | 7.63 | % | 2013-2043 | $ | 7,746 | $ | 7,397 | |||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2013-2036 | 1,750 | 1,850 | |||||||||||
Rate stabilization bonds | 5.68 | % | - | 5.82 | % | 2016-2017 | 265 | 332 | |||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2014-2042 | 7,571 | 8,021 | |||||||||||
Pollution control notes: | |||||||||||||||||||
Fixed rates | 4.1 | % | 2014 | 20 | 20 | ||||||||||||||
Non-recourse debt: | |||||||||||||||||||
Fixed rates | 2.33 | % | - | 5.5 | % | 2031-2037 | 1,077 | 238 | |||||||||||
Variable rates | 1.96 | % | - | 2.77 | % | 2013-2053 | 150 | 262 | |||||||||||
Notes payable and other (c) | 4.5 | % | - | 7.83 | % | 2014-2053 | 181 | 177 | |||||||||||
Total long-term debt | 18,760 | 18,297 | |||||||||||||||||
Unamortized debt discount and premium, net | -19 | -17 | |||||||||||||||||
Fair value adjustment | 384 | 448 | |||||||||||||||||
Fair value hedge carrying value adjustment, net | 7 | 17 | |||||||||||||||||
Long-term debt due within one year | -1,509 | -1,047 | |||||||||||||||||
Long-term debt | $ | 17,623 | $ | 17,698 | |||||||||||||||
Long-term debt to financing trusts (d) | |||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2033 | $ | 206 | $ | 206 | ||||||||||||
Subordinated debentures to PECO Trust III | 7.38 | % | 2028 | 81 | 81 | ||||||||||||||
Subordinated debentures to PECO Trust IV | 5.75 | % | 2033 | 103 | 103 | ||||||||||||||
Subordinated debentures to BGE Trust | 6.2 | % | 2043 | 258 | 258 | ||||||||||||||
Total long-term debt to financing trusts | $ | 648 | $ | 648 | |||||||||||||||
(a) Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes. | |||||||||||||||||||
(c) Includes capital lease obligations of $41 million and $30 million at December 31, 2013 and 2012, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $5 million and $19 million will be made in 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. | |||||||||||||||||||
(d) Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets. | |||||||||||||||||||
Schedule Of Maturities Of Long Term Debt [Text Block] | ' | ||||||||||||||||||
Year | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
2014 | $ | 1,428 | $ | 561 | $ | 617 | $ | 250 | $ | — | |||||||||
2015 | 1,615 | 555 | 260 | — | — | ||||||||||||||
2016 | 1,346 | 81 | 665 | 300 | 300 | ||||||||||||||
2017 | 1,396 | 706 | 425 | — | 265 | ||||||||||||||
2018 | 1,345 | 5 | 840 | 500 | — | ||||||||||||||
Thereafter | 12,278 | (a) | 5,644 | 3,093 | (b) | 1,334 | (c) | 1,708 | (d) | ||||||||||
Total | $ | 19,408 | $ | 7,552 | $ | 5,900 | $ | 2,384 | $ | 2,273 | |||||||||
(a) Includes $648 million due to ComEd, PECO and BGE financing trusts. | |||||||||||||||||||
(b) Includes $206 million due to ComEd financing trust. | |||||||||||||||||||
(c) Includes $184 million due to PECO financing trusts. | |||||||||||||||||||
(d) Includes $258 million due to BGE financing trust. | |||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||
Schedule Of Debt Instruments Text Block | ' | ||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | 2014-2042 | $ | 6,271 | $ | 6,721 | ||||||||||
Social Security Administration | 2.93 | % | 2015 | 1 | — | ||||||||||||||
Pollution control notes: | |||||||||||||||||||
Fixed rates | 4.1 | % | 2014 | 20 | 20 | ||||||||||||||
Non-recourse debt: | |||||||||||||||||||
Fixed rates | 2.33 | % | - | 5.5 | % | 2031-2037 | 1,077 | 238 | |||||||||||
Variable rates | 1.96 | % | - | 2.77 | % | 2014-2030 | 150 | 262 | |||||||||||
Notes payable and other (a) | 4.5 | % | - | 7.83 | % | 2014-2022 | 33 | 30 | |||||||||||
1 | |||||||||||||||||||
Total long-term debt | 7,552 | 7,271 | |||||||||||||||||
Fair value adjustment | 166 | 199 | |||||||||||||||||
Unamortized debt discount and premium, net | 11 | 13 | |||||||||||||||||
Long-term debt due within one year | -561 | -28 | |||||||||||||||||
Long-term debt | $ | 7,168 | $ | 7,455 | |||||||||||||||
Includes Generation's capital lease obligations of $33 million and $30 million at December 31, 2013 and 2012, respectively. Generation will make lease payments of $4 million, $4 million, $4 million, $5 million, $5 million and $11 million in 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. | |||||||||||||||||||
Commonwealth Edison Co [Member] | ' | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||
Schedule Of Debt Instruments Text Block | ' | ||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b): | |||||||||||||||||||
Fixed rates | 1.63 | % | - | 7.63 | % | 2013-2043 | $ | 5,546 | $ | 5,447 | |||||||||
Notes payable and other (c) | 6.95 | % | - | 7.49 | % | 2014-2053 | 148 | 140 | |||||||||||
Total long-term debt | 5,694 | 5,587 | |||||||||||||||||
Unamortized debt discount and premium, net | -19 | -20 | |||||||||||||||||
Long-term debt due within one year | -617 | -252 | |||||||||||||||||
Long-term debt | $ | 5,058 | $ | 5,315 | |||||||||||||||
Long-term debt to financing trust (d) | |||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2042 | $ | 206 | $ | 206 | ||||||||||||
(a) Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes. | |||||||||||||||||||
(c) Includes ComEd's capital lease obligations of $ 8 million at December 31, 2013. Lease payments of less than $1 million will be made from 2014 through expiration at 2053. | |||||||||||||||||||
(d) Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets. | |||||||||||||||||||
PECO Energy Co [Member] | ' | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||
Schedule Of Debt Instruments Text Block | ' | ||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
First Mortgage Bonds (a) (b): | |||||||||||||||||||
Fixed rates | 1.2 | % | - | 5.95 | % | 2013-2043 | $ | 2,200 | $ | 1,950 | |||||||||
Total long-term debt | 2,200 | 1,950 | |||||||||||||||||
Unamortized debt discount and premium, net | -3 | -3 | |||||||||||||||||
Long-term debt due within one year | -250 | -300 | |||||||||||||||||
Long-term debt | $ | 1,947 | $ | 1,647 | |||||||||||||||
Long-term debt to financing trusts (c) | |||||||||||||||||||
Subordinated debentures to PECO Trust III | 7.38 | % | 2028 | $ | 81 | $ | 81 | ||||||||||||
Subordinated debentures to PECO Trust IV | 5.75 | % | 2033 | 103 | 103 | ||||||||||||||
Long-term debt to financing trusts | $ | 184 | $ | 184 | |||||||||||||||
(a) Substantially all of PECO's assets are subject to the lien of its mortgage indenture. | |||||||||||||||||||
(b) Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes. | |||||||||||||||||||
(c) Amounts owed to this financing trust are recorded as debt to financing trusts within PECO's Consolidated Balance Sheets. | |||||||||||||||||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||||||||||
Debt Instrument [Line Items] | ' | ||||||||||||||||||
Schedule Of Maturities Of Long Term Debt [Text Block] | ' | ||||||||||||||||||
Maturity | December 31, | ||||||||||||||||||
Rates | Date | 2013 | 2012 | ||||||||||||||||
Long-term debt | |||||||||||||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2013-2036 | $ | 1,750 | $ | 1,850 | |||||||||
Rate stabilization bonds | 5.68 | % | 5.82 | % | 2016-2017 | 265 | $ | 332 | |||||||||||
Total long-term debt | 2,015 | 2,182 | |||||||||||||||||
Unamortized debt discount and premium, net | -4 | -4 | |||||||||||||||||
Long-term debt due within one year | -70 | -467 | |||||||||||||||||
Long-term debt | $ | 1,941 | $ | 1,711 | |||||||||||||||
Long-term debt to financing trusts (a) | |||||||||||||||||||
Subordinated debentures to BGE Capital Trust II | 6.2 | % | 2043 | $ | 258 | $ | 258 | ||||||||||||
Debt_and_Credit_Agreements_Qua
Debt and Credit Agreements Quarter-End (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Debt and Credit Agreements [Line Items] | ' | ||||||||||||||||||
Commercial paper and credit facility borrowings outstanding | ' | ||||||||||||||||||
Maximum Program Size at December 31, | Outstanding Commercial Paper at December 31, | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | |||||||||||||||||
Commercial Paper Issuer | 2013 (a) | 2012 (a) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
Exelon Corporate | $ | 500 | $ | 500 | $ | 0 | $ | 0 | 0.27 | % | 0.47 | % | |||||||
Generation | 5,600 | 5,600 | 0 | 0 | 0.32 | % | 0.45 | % | |||||||||||
ComEd | 1,000 | 1,000 | 184 | 0 | 0.4 | % | 0.5 | % | |||||||||||
PECO | 600 | 600 | 0 | 0 | n.a. | n.a. | |||||||||||||
BGE | 600 | 600 | 135 | 0 | 0.31 | % | 0.43 | % | |||||||||||
Total | $ | 8,300 | $ | 8,300 | $ | 319 | $ | 0 | |||||||||||
(a) Equals aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of a $75 million bilateral agreement) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||||
Exelon | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 254 | $ | 199 | $ | 218 | |||||||||||||
Maximum borrowings outstanding | 682 | 505 | 600 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.37 | % | 0.48 | % | 0.5 | % | |||||||||||||
Average interest rates, at December 31 | 0.35 | % | n.a. | 0.44 | % | ||||||||||||||
Generation | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 42 | $ | 4 | $ | 51 | |||||||||||||
Maximum borrowings outstanding | 291 | 165 | 304 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.45 | % | 0.48 | ||||||||||||||
Average interest rates, at December 31 | n.a. | n.a. | n.a. | ||||||||||||||||
ComEd | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 203 | $ | 110 | $ | 36 | |||||||||||||
Maximum borrowings outstanding | 446 | 366 | 407 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.4 | % | 0.5 | % | 0.71 | % | |||||||||||||
Average interest rates, at December 31 | 0.37 | % | n.a. | n.a. | |||||||||||||||
BGE | |||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||
Average borrowings | $ | 35 | $ | 6 | $ | 26 | |||||||||||||
Maximum borrowings outstanding | 135 | 76 | 190 | ||||||||||||||||
Average interest rates, computed on a daily basis | 0.31 | % | 0.43 | % | 0.38 | % | |||||||||||||
Average interest rates, computed at December 31 | 0.31 | % | n.a. | n.a. |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||
Income Taxes [Line Items] | ' | |||||||||||||||||
Income Tax Expense Benefit Detail [Text Block] | ' | |||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 744 | $ | 250 | $ | 160 | $ | 126 | $ | 9 | ||||||||
Deferred | 140 | 360 | -27 | 23 | 100 | |||||||||||||
Investment tax credit amortization | -15 | -11 | -2 | -1 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | 181 | 50 | 50 | 16 | — | |||||||||||||
Deferred | -6 | -34 | -29 | -2 | 26 | |||||||||||||
Total | $ | 1,044 | $ | 615 | $ | 152 | $ | 162 | $ | 134 | ||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 37 | $ | 104 | $ | -40 | $ | 88 | $ | -97 | ||||||||
Deferred | 701 | 326 | 237 | 25 | 101 | |||||||||||||
Investment tax credit amortization | -11 | -6 | -2 | -2 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | -25 | -12 | 6 | 4 | — | |||||||||||||
Deferred | -75 | 88 | 38 | 12 | 4 | |||||||||||||
Total | $ | 627 | $ | 500 | $ | 239 | $ | 127 | $ | 7 | ||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Included in operations: | ||||||||||||||||||
Federal | ||||||||||||||||||
Current | $ | 1 | $ | 431 | $ | -329 | $ | -71 | $ | -71 | ||||||||
Deferred | 1,200 | 435 | 544 | 223 | 130 | |||||||||||||
Investment tax credit amortization | -12 | -7 | -3 | -2 | -1 | |||||||||||||
State | ||||||||||||||||||
Current | -3 | 74 | -123 | -37 | — | |||||||||||||
Deferred | 271 | 123 | 161 | 33 | 17 | |||||||||||||
Total | $ | 1,457 | $ | 1,056 | $ | 250 | $ | 146 | $ | 75 | ||||||||
__________ | ||||||||||||||||||
(a) Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 - December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012 - December 31, 2012. | ||||||||||||||||||
(b) BGE activity represents the activity for the twelve months ended December 31, 2012 and 2011. | ||||||||||||||||||
(c) Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger. | ||||||||||||||||||
Net interest receivable (payable) as of | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
31-Dec-13 | $ | -349 | $ | -37 | $ | -174 | $ | 3 | $ | — | ||||||||
31-Dec-12 | 31 | -20 | 107 | 2 | — | |||||||||||||
Net interest expense (income) for the years ended | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
31-Dec-13 | $ | 391 | $ | 17 | $ | 281 | $ | -1 | $ | — | ||||||||
31-Dec-12 | -1 | 11 | -20 | -1 | 9 | |||||||||||||
31-Dec-11 | -56 | -40 | -14 | -1 | -3 | |||||||||||||
Effective Income Tax Rate Reconciliation | ' | |||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | 4.7 | 1.6 | 3.4 | 1.6 | 4.9 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 3.7 | 6.1 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.3 | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.7 | — | 0.2 | |||||||||||||
Amortization of investment tax credit, net deferred taxes | -1.9 | -3 | -0.6 | -0.1 | — | |||||||||||||
Production tax credits and other credits | -2.1 | -3.4 | -0.1 | — | — | |||||||||||||
Plant basis differences | -1.6 | — | -0.8 | -7.1 | -0.2 | |||||||||||||
Other | -0.1 | 0.7 | 0.3 | -0.3 | -0.9 | |||||||||||||
Effective income tax rate | 37.6 | % | 36.7 | % | 37.9 | % | 29.1 | % | 39 | % | ||||||||
For the Year Ended December 31, 2012 | Exelon (a) | Generation (a) | ComEd | PECO | BGE (b) | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | -3.6 | 4.7 | 4.6 | 2 | 24.3 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 5.4 | 9.1 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.4 | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.4 | — | 11.6 | |||||||||||||
Amortization of investment tax credit, net deferred taxes | -1.1 | -1.3 | -0.4 | -0.3 | -8.6 | |||||||||||||
Production tax credits and other credits | -2.2 | -3.7 | — | — | — | |||||||||||||
Plant basis differences | -2.4 | — | -0.3 | -11.5 | -9 | |||||||||||||
Merger expenses (c) | 2.4 | — | — | — | 24.2 | |||||||||||||
Fines and Penalties | 2.6 | 4.4 | — | — | — | |||||||||||||
Other | -1.1 | -0.5 | -0.6 | -0.2 | -13.9 | |||||||||||||
Effective income tax rate | 34.9 | % | 47.3 | % | 38.7 | % | 25 | % | 63.6 | % | ||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE (b) | |||||||||||||
U.S. Federal statutory rate | 35 | % | 35 | % | 35 | % | 35 | % | 35 | % | ||||||||
Increase (decrease) due to: | ||||||||||||||||||
State income taxes, net of Federal income tax benefit | 4.4 | 4.5 | 3.6 | -0.5 | 5.2 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 0.5 | 0.7 | — | — | — | |||||||||||||
Domestic production activities deduction | -0.3 | -0.4 | — | — | — | |||||||||||||
Tax exempt income | -0.2 | -0.2 | — | — | — | |||||||||||||
Health care reform legislation | -0.2 | — | -1 | — | -0.5 | |||||||||||||
Amortization of investment tax credit | -0.3 | -0.3 | -0.4 | -0.3 | -0.5 | |||||||||||||
Production tax credits | -0.9 | -1.2 | — | — | — | |||||||||||||
Plant basis differences | -1 | — | -0.3 | -6.9 | -2 | |||||||||||||
Other | -0.2 | -0.7 | 0.6 | — | -1.7 | |||||||||||||
Effective income tax rate | 36.8 | % | 37.4 | % | 37.5 | % | 27.3 | % | 35.5 | % | ||||||||
Tax Effects Of Temporary Differences [Text Block] | ' | |||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Plant basis differences | $ | -11,612 | $ | -3,879 | $ | -3,523 | $ | -2,573 | $ | -1,538 | ||||||||
Accrual based contracts | -214 | -214 | — | — | — | |||||||||||||
Derivatives and other financial instruments | -509 | -505 | -4 | — | — | |||||||||||||
Deferred pension and post-retirement obligation | 1,489 | -362 | -522 | — | -74 | |||||||||||||
Nuclear decommissioning activities | -647 | -646 | — | — | — | |||||||||||||
Deferred debt refinancing costs | 173 | 79 | -21 | -3 | -5 | |||||||||||||
Regulatory | -1,611 | — | -241 | 42 | -253 | |||||||||||||
Tax loss carryforward | 252 | 76 | 47 | 11 | 52 | |||||||||||||
Tax credit carryforward | 534 | 534 | — | — | — | |||||||||||||
Investment in CENG | -541 | -541 | — | — | — | |||||||||||||
Other, net | 804 | 67 | 154 | 122 | 26 | |||||||||||||
Deferred income tax liabilities (net) | $ | -11,882 | $ | -5,391 | $ | -4,110 | $ | -2,401 | $ | -1,792 | ||||||||
Unamortized investment tax credits | -490 | -454 | -22 | -3 | -6 | |||||||||||||
Total deferred income tax liabilities (net) and | ||||||||||||||||||
unamortized investment tax credits | $ | -12,372 | $ | -5,845 | $ | -4,132 | $ | -2,404 | $ | -1,798 | ||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||
Plant basis differences | $ | -10,689 | $ | -3,545 | $ | -3,537 | $ | -2,437 | $ | -1,553 | ||||||||
Accrual based contracts | -389 | -389 | — | — | — | |||||||||||||
Derivatives and other financial instruments | -392 | -479 | -4 | — | — | |||||||||||||
Deferred pension and post-retirement obligation | 2,356 | -439 | -598 | -11 | -12 | |||||||||||||
Nuclear decommissioning activities | -604 | -604 | — | — | — | |||||||||||||
Deferred debt refinancing costs | -537 | 163 | -25 | -4 | -4 | |||||||||||||
Regulatory | -1,857 | — | -116 | 50 | -253 | |||||||||||||
Tax loss carryforward | 421 | 226 | 32 | 14 | 105 | |||||||||||||
Tax credit carryforward | 226 | 226 | — | — | — | |||||||||||||
Investment in CENG | -405 | -419 | — | — | — | |||||||||||||
Other, net | 701 | 9 | 83 | 100 | 67 | |||||||||||||
Deferred income tax liabilities (net) | $ | -11,169 | $ | -5,251 | $ | -4,165 | $ | -2,288 | $ | -1,650 | ||||||||
Unamortized investment tax credits | -251 | -216 | -24 | -3 | -6 | |||||||||||||
Total deferred income tax liabilities (net) and | ||||||||||||||||||
unamortized investment tax credits | $ | -11,420 | $ | -5,467 | $ | -4,189 | $ | -2,291 | $ | -1,656 | ||||||||
Summary Of Loss Carryforwards [Text Block] | ' | |||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Federal | ||||||||||||||||||
Federal net operating loss | $ | 377 | (a) | $ | 36 | $ | 139 | $ | 0 | $ | 31 | |||||||
Deferred taxes on Federal net operating loss | 132 | 13 | 49 | 0 | 11 | |||||||||||||
Federal general business credits carryforward | 556 | (b) | 556 | 0 | 0 | 0 | ||||||||||||
State | ||||||||||||||||||
State net operating losses and other credit | ||||||||||||||||||
carryforwards | 3,061 | (c) | 1,498 | (d) | 0 | 167 | (e) | 768 | (f) | |||||||||
Deferred taxes on state tax attributes (net) | 161 | 82 | 0 | 11 | 41 | |||||||||||||
Valuation allowance on state tax attributes | 13 | 11 | 0 | 0 | 1 | |||||||||||||
__________ | ||||||||||||||||||
Exelon's federal net operating loss will expire beginning in 2031 | ||||||||||||||||||
Exelon's federal general business credit carryforwards will expire beginning in 2032 | ||||||||||||||||||
Exelon's state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||||||||||||
Generation's state net operating losses losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||||||||||||
PECO's state net operating losses will expire beginning in 2031 | ||||||||||||||||||
BGE's state net operating losses will expire beginning in 2026 | ||||||||||||||||||
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns Roll Forward [Text Block] | ' | |||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2013 | $ | 1,024 | $ | 876 | $ | 67 | $ | 44 | $ | — | ||||||||
Increases based on tax positions related to 2013 | 19 | 19 | — | — | — | |||||||||||||
Change to positions that only affect timing | 649 | 36 | 257 | — | — | |||||||||||||
Increases based on tax positions prior to 2013 | 493 | 493 | — | — | — | |||||||||||||
Decreases based on tax positions prior to 2013 | -6 | -5 | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | -4 | -4 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2013 | $ | 2,175 | $ | 1,415 | $ | 324 | $ | 44 | $ | — | ||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2012 | $ | 807 | $ | 683 | $ | 70 | $ | 48 | $ | 11 | ||||||||
Merger Balance Transfer | 195 | 183 | — | — | — | |||||||||||||
Increases based on tax positions related to 2012 | 34 | 3 | — | — | — | |||||||||||||
Change to positions that only affect timing | -88 | -69 | -3 | -4 | -11 | |||||||||||||
Increases based on tax positions prior to 2012 | 91 | 91 | — | — | — | |||||||||||||
Decreases based on tax positions prior to 2012 | -6 | -6 | — | — | — | |||||||||||||
Decreases related to settlements with taxing authorities | -2 | -2 | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | -7 | -7 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2012 | $ | 1,024 | $ | 876 | $ | 67 | $ | 44 | $ | — | ||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Unrecognized tax benefits at January 1, 2011 | $ | 787 | $ | 664 | $ | 72 | $ | 44 | $ | 73 | ||||||||
Increases based on tax positions related to 2011 | 5 | 1 | — | 4 | — | |||||||||||||
Change to positions that only affect timing | 21 | 24 | -2 | — | -62 | |||||||||||||
Decreases based on tax positions prior to 2011 | -3 | -3 | — | — | — | |||||||||||||
Decrease from expiration of statute of limitations | -3 | -3 | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2011 | $ | 807 | $ | 683 | $ | 70 | $ | 48 | $ | 11 |
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2013 | ||||||||||||
Asset Retirement Obligations Tables [Line Items] | ' | |||||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | |||||||||||
Exelon and Generation | ||||||||||||
Nuclear decommissioning ARO at January 1, 2012 | $ | 3,680 | ||||||||||
Accretion expense | 231 | |||||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 833 | |||||||||||
Costs incurred to decommission retired plants | -3 | |||||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | 4,741 | |||||||||||
Accretion expense | 259 | |||||||||||
Net decrease due to changes in, and timing of, estimated future cash flows | -140 | |||||||||||
Costs incurred to decommission retired plants | -5 | |||||||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | ||||||||||
(a) Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | |||||||||||
Exelon and Generation | ||||||||||||
For the Years Ended December 31, | ||||||||||||
2013 | 2012 | 2011 | ||||||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Regulatory Agreement Units (a) | $ | 406 | $ | 386 | $ | -74 | ||||||
Net unrealized gains (losses) on decommissioning | ||||||||||||
trust funds — Non-Regulatory Agreement Units (b) (c) | 146 | 105 | -4 | |||||||||
__________ | ||||||||||||
(a) Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | ||||||||||||
(b) Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||
(c) Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||
Non-nuclear asset retirement obligation rollforward | ' | |||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||
Non-nuclear AROs at January 1, 2012 | $ | 209 | $ | 92 | $ | 89 | $ | 28 | $ | 1 | ||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 27 | 18 | 8 | 1 | 7 | |||||||
Development projects | 47 | 47 | — | — | — | |||||||
Accretion expense (b) | 13 | 8 | 4 | 1 | — | |||||||
Merger with Constellation (c) | 58 | 50 | — | — | — | |||||||
Payments | -11 | -8 | -2 | -1 | — | |||||||
Non-nuclear AROs at December 31, 2012 | 343 | 207 | 99 | 29 | 8 | |||||||
Net increase due to changes in, and timing of, | ||||||||||||
estimated future cash flows (a) | 1 | -11 | — | — | 12 | |||||||
Development projects | 2 | 2 | — | — | — | |||||||
Accretion expense (b) | 18 | 13 | 4 | 1 | — | |||||||
Payments | -13 | -10 | -2 | — | -1 | |||||||
Non-nuclear AROs at December 31, 2013 (d) | $ | 351 | $ | 201 | $ | 101 | $ | 30 | $ | 19 | ||
During the year ended December 31, 2013, Generation recorded an increase in operating and maintenance expense of $13 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2013. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd, PECO, and BGE did not record any reductions in operating and maintenance expense for the year ended December 31, 2012. | ||||||||||||
For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | ||||||||||||
Exelon's ARO includes $8 million of BGE costs incurred prior to the closing of Exelon's merger with Constellation. Refer to Note 4 – Merger and Acquisitions for additional information. | ||||||||||||
Includes $ 2 million, $ 1 million, and $0 million as the current portion of the ARO at December 31, 2013 for ComEd, PECO, and BGE, respectively, which is included in other current liabilities on Exelon's and each of the respective utilities' Consolidated Balance Sheets. | ||||||||||||
Zion Station pledged assets | ' | |||||||||||
Exelon and Generation | ||||||||||||
2013 | 2012 | |||||||||||
Carrying value of Zion Station pledged assets | $ | 458 | $ | 614 | ||||||||
Payable to Zion Solutions (a) | 414 | 564 | ||||||||||
Current portion of payable to Zion Solutions (b) | 109 | 132 | ||||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 498 | 335 | ||||||||||
(a) Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | ||||||||||||
(b) Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets |
Nuclear_Decommissioning_Tables
Nuclear Decommissioning (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Schedule Of Nuclear Decommissioning [Line Items] | ' | |||||||||
Nuclear decommissioning asset retirement obligation rollforward | ' | |||||||||
Exelon and Generation | ||||||||||
Nuclear decommissioning ARO at January 1, 2012 | $ | 3,680 | ||||||||
Accretion expense | 231 | |||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 833 | |||||||||
Costs incurred to decommission retired plants | -3 | |||||||||
Nuclear decommissioning ARO at December 31, 2012 (a) | 4,741 | |||||||||
Accretion expense | 259 | |||||||||
Net decrease due to changes in, and timing of, estimated future cash flows | -140 | |||||||||
Costs incurred to decommission retired plants | -5 | |||||||||
Nuclear decommissioning ARO at December 31, 2013 (a) | $ | 4,855 | ||||||||
(a) Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||
Unrealized Gains (Losses) on nuclear decommissioning trust funds | ' | |||||||||
Exelon and Generation | ||||||||||
For the Years Ended December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Net unrealized gains (losses) on decommissioning | ||||||||||
trust funds — Regulatory Agreement Units (a) | $ | 406 | $ | 386 | $ | -74 | ||||
Net unrealized gains (losses) on decommissioning | ||||||||||
trust funds — Non-Regulatory Agreement Units (b) (c) | 146 | 105 | -4 | |||||||
__________ | ||||||||||
(a) Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | ||||||||||
(b) Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||
(c) Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||
Zion Station pledged assets | ' | |||||||||
Exelon and Generation | ||||||||||
2013 | 2012 | |||||||||
Carrying value of Zion Station pledged assets | $ | 458 | $ | 614 | ||||||
Payable to Zion Solutions (a) | 414 | 564 | ||||||||
Current portion of payable to Zion Solutions (b) | 109 | 132 | ||||||||
Withdrawals by Zion Solutions to pay decommissioning costs (c) | 498 | 335 | ||||||||
(a) Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | ||||||||||
(b) Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets |
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||
Retirement Benefits [Line Items] | ' | |||||||||||||||||||
Schedule Of Pension And Other Postretirement Participation [Text Block] | ' | |||||||||||||||||||
Operating Company | ||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||
Qualified Pension Plans: | ||||||||||||||||||||
Exelon Corporation Retirement Program | X | X | X | X | ||||||||||||||||
Exelon Corporation Cash Balance Pension Plan | X | X | X | X | ||||||||||||||||
Exelon Corporation Pension Plan for | ||||||||||||||||||||
Bargaining Unit Employees | X | X | X | |||||||||||||||||
Exelon New England Union Employees Pension Plan | X | |||||||||||||||||||
Exelon Employee Pension Plan for Clinton, | ||||||||||||||||||||
TMI and Oyster Creek | X | X | X | |||||||||||||||||
Pension Plan of Constellation Energy Group, Inc. | X | X | X | |||||||||||||||||
Constellation Mystic Power, LLC Union Employees | ||||||||||||||||||||
Pension Plan Including Plan A and Plan B | X | |||||||||||||||||||
Non-Qualified Pension Plans: | ||||||||||||||||||||
Exelon Corporation Supplemental Pension Benefit Plan | ||||||||||||||||||||
and 2000 Excess Benefit Plan | X | X | X | X | ||||||||||||||||
Exelon Corporation Supplemental Management | ||||||||||||||||||||
Retirement Plan | X | X | X | X | ||||||||||||||||
Constellation Energy Group, Inc. Senior Executive | ||||||||||||||||||||
Supplemental Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Supplemental | ||||||||||||||||||||
Pension Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Benefits Restoration | ||||||||||||||||||||
Plan | X | X | X | |||||||||||||||||
Baltimore Gas & Electric Company Executive | ||||||||||||||||||||
Benefit Plan | X | X | X | |||||||||||||||||
Baltimore Gas & Electric Company Manager | ||||||||||||||||||||
Benefit Plan | X | X | X | |||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||
PECO Energy Company Retiree Medical Plan | X | X | X | |||||||||||||||||
Exelon Corporation Health Care Program | X | X | X | |||||||||||||||||
Exelon Corporation Employees' Life Insurance Plan | X | X | X | X | ||||||||||||||||
Constellation Energy Group, Inc. Retiree Medical Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Retiree Dental Plan | X | X | X | |||||||||||||||||
Constellation Energy Group, Inc. Employee Life | ||||||||||||||||||||
Insurance Plan and Family Life Insurance Plan | X | X | X | |||||||||||||||||
Constellation Mystic Power, LLC Post-Employment | ||||||||||||||||||||
Medical Account Savings Plan | X | |||||||||||||||||||
Exelon New England Union Post-Employment | ||||||||||||||||||||
Medical Savings Account Plan | X | |||||||||||||||||||
Defined Benefit Plan Change In Benefit Obligation RollForward [Text Block] | ' | |||||||||||||||||||
Other | ||||||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||
Net benefit obligation at beginning of year | $ | 16,800 | $ | 13,538 | $ | 4,820 | $ | 4,062 | ||||||||||||
Service cost | 317 | 280 | 162 | 156 | ||||||||||||||||
Interest cost | 650 | 698 | 194 | 205 | ||||||||||||||||
Plan participants’ contributions | 0 | 0 | 34 | 34 | ||||||||||||||||
Actuarial loss (gain) | -1,363 | 1,520 | -551 | 313 | ||||||||||||||||
Plan amendments | 1 | 0 | 15 | -103 | ||||||||||||||||
Acquisitions/divestitures | 0 | 1,880 | 0 | 362 | ||||||||||||||||
Curtailments | 0 | -10 | 0 | -8 | ||||||||||||||||
Settlements(a) | -69 | -169 | 0 | 0 | ||||||||||||||||
Contractual termination benefits | 0 | 15 | 0 | 6 | ||||||||||||||||
Gross benefits paid | -877 | -952 | -223 | -219 | ||||||||||||||||
Federal subsidy on benefits paid | 0 | 0 | 0 | 12 | ||||||||||||||||
Net benefit obligation at end of year | $ | 15,459 | $ | 16,800 | $ | 4,451 | $ | 4,820 | ||||||||||||
Change in plan assets: | ||||||||||||||||||||
Fair value of net plan assets at beginning of year | $ | 13,357 | $ | 11,302 | $ | 2,135 | $ | 1,797 | ||||||||||||
Actual return on plan assets | 821 | 1,484 | 209 | 197 | ||||||||||||||||
Employer contributions | 339 | 149 | 83 | 325 | ||||||||||||||||
Plan participants’ contributions | 0 | 0 | 34 | 34 | ||||||||||||||||
Benefits paid(b) | -877 | -952 | -223 | -218 | ||||||||||||||||
Acquisitions/divestitures | 0 | 1,543 | 0 | 0 | ||||||||||||||||
Settlements(a) | -69 | -169 | 0 | 0 | ||||||||||||||||
Fair value of net plan assets at end of year | $ | 13,571 | $ | 13,357 | $ | 2,238 | $ | 2,135 | ||||||||||||
Schedule of Amounts Recognized in Balance Sheet [Table Text Block] | ' | |||||||||||||||||||
Other | ||||||||||||||||||||
Pension Benefits | Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Other current liabilities | $ | 12 | $ | 15 | $ | 23 | $ | 23 | ||||||||||||
Pension obligations | 1,876 | 3,428 | 0 | 0 | ||||||||||||||||
Non-pension postretirement benefit obligations | 0 | 0 | 2,190 | 2,662 | ||||||||||||||||
Unfunded status (net benefit obligation less | ||||||||||||||||||||
net plan assets) | $ | 1,888 | $ | 3,443 | $ | 2,213 | $ | 2,685 | ||||||||||||
Defined Benefit Plan Pension Plans With Projected Benefit Obligations And Accumulated Benefit Obligations In Excess Of Plan Assets [Text Block] | ' | |||||||||||||||||||
PBO in excess of plan assets | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Projected benefit obligation | $ | 15,452 | $ | 16,800 | ||||||||||||||||
Fair value of net plan assets | 13,564 | 13,357 | ||||||||||||||||||
ABO in excess of plan assets | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Projected benefit obligation | $ | 15,452 | $ | 16,796 | ||||||||||||||||
Accumulated benefit obligation | 14,552 | 15,657 | ||||||||||||||||||
Fair value of net plan assets | 13,564 | 13,353 | ||||||||||||||||||
Schedule of Defined Benefit Plans Disclosures [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Components of net periodic benefit | ||||||||||||||||||||
cost: | ||||||||||||||||||||
Service cost | $ | 317 | $ | 280 | $ | 212 | $ | 162 | $ | 156 | $ | 142 | ||||||||
Interest cost | 650 | 698 | 649 | 194 | 205 | 207 | ||||||||||||||
Expected return on assets | -1,015 | -988 | -939 | -132 | -115 | -111 | ||||||||||||||
Amortization of: | ||||||||||||||||||||
Transition obligation | 0 | 0 | 0 | 0 | 11 | 9 | ||||||||||||||
Prior service cost (credit) | 14 | 15 | 14 | -19 | -17 | -38 | ||||||||||||||
Actuarial loss | 562 | 450 | 331 | 83 | 81 | 66 | ||||||||||||||
Curtailment benefits | 0 | 0 | 0 | 0 | -7 | 0 | ||||||||||||||
Settlement charges | 9 | 31 | 0 | 0 | 0 | 0 | ||||||||||||||
Contractual termination benefits (a) | 0 | 14 | 0 | 0 | 6 | 0 | ||||||||||||||
Net periodic benefit cost | $ | 537 | $ | 500 | $ | 267 | $ | 288 | $ | 320 | $ | 275 | ||||||||
ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012. | ||||||||||||||||||||
Prescription Drug Benefit Reduction In Accumulated Postretirement Benefit Obligation For Subsidy [Text Block] | ' | |||||||||||||||||||
2013 | 2012 | 2011 | ||||||||||||||||||
Amortization of the actuarial experience loss | $ | 0 | $ | -17 | $ | 3 | ||||||||||||||
Reduction in current period service cost | 0 | 0 | 9 | |||||||||||||||||
Reduction in interest cost on the APBO | 0 | 0 | 16 | |||||||||||||||||
Total effect of subsidy on net periodic postretirement benefit cost | $ | 0 | $ | -17 | $ | 28 | ||||||||||||||
Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets [Text Block] | ' | |||||||||||||||||||
(a) Represents cash settlements only. | ||||||||||||||||||||
(b) Exelon's other postretirement benefits paid for the year ended December 31, 2012 are net of $1.3 million of reinsurance proceeds received from the Department of Health and Human Services as part of the Early Retiree Reinsurance Program pursuant to the Affordable Care Act of 2010. In 2013, the Program was no longer accepting applications for reimbursement. | ||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Changes in plan assets and benefit | ||||||||||||||||||||
obligations recognized in AOCI | ||||||||||||||||||||
and regulatory assets (liabilities): | ||||||||||||||||||||
Current year actuarial (gain) loss | $ | -1,169 | $ | 1,693 | $ | 744 | $ | -628 | $ | 304 | $ | 74 | ||||||||
Amortization of actuarial gain (loss) | -562 | -450 | -331 | -83 | -81 | -66 | ||||||||||||||
Current year prior service (credit) cost | 0 | 1 | 0 | 15 | -109 | 0 | ||||||||||||||
Amortization of prior service (cost) | ||||||||||||||||||||
credit | -14 | -15 | -14 | 19 | 17 | 38 | ||||||||||||||
Current year transition (asset) obligation | 0 | 0 | 0 | 0 | 1 | 0 | ||||||||||||||
Amortization of transition asset | ||||||||||||||||||||
(obligation) | 0 | 0 | 0 | 0 | -11 | -9 | ||||||||||||||
Curtailments | 0 | -10 | 0 | 0 | -1 | 0 | ||||||||||||||
Settlements | -8 | -31 | 0 | 0 | 0 | 0 | ||||||||||||||
Total recognized in AOCI and | ||||||||||||||||||||
regulatory assets (liabilities)(a) | $ | -1,753 | $ | 1,188 | $ | 399 | $ | -677 | $ | 120 | $ | 37 | ||||||||
Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million loss related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million loss related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. | ||||||||||||||||||||
Changes In Plan Assets And Benefit Obligations Not Recognized In OCI And Regulatory Assets [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
Prior service cost (credit) | $ | 62 | $ | 76 | $ | -73 | $ | -107 | ||||||||||||
Actuarial loss | 6,192 | 7,931 | 474 | 1,185 | ||||||||||||||||
Total(a) | $ | 6,254 | $ | 8,007 | $ | 401 | $ | 1,078 | ||||||||||||
(a) Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013. Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. | ||||||||||||||||||||
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
Prior service cost (credit) | $ | 14 | $ | -16 | ||||||||||||||||
Actuarial loss | 427 | 32 | ||||||||||||||||||
Total(a) | $ | 441 | $ | 16 | ||||||||||||||||
(a) Of the $441 million related to pension benefits at December 31, 2013, $232 million and $209 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $16 million related to other postretirement benefits at December 31, 2013, $7 million and $9 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. | ||||||||||||||||||||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Discount rate | 4.80% | 3.92% | 4.74% | 4.90% | 4.00% | 4.80% | ||||||||||||||
Rate of compensation increase | (a) | (b) | 3.75% | (a) | (b) | 3.75% | ||||||||||||||
Mortality table | IRS required mortality table for 2014 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2014 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | ||||||||||||||
Health care cost trend on covered charges | N/A | N/A | N/A | 6.00% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | ||||||||||||||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||
Discount rate | 3.92% (a) | 4.74% (b) | 5.26% | 4.00% (a) | 4.80% (b) | 5.30% | ||||||||||||||
Expected return on plan assets | 7.50% (c) | 7.50% (c) | 8.00% (c) | 6.45% (c) | 6.68% (c) | 7.08% (c) | ||||||||||||||
Rate of compensation increase | (d) | 3.75% | 3.75% | (d) | 3.75% | 3.75% | ||||||||||||||
Mortality table | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2011 funding valuation | IRS required mortality table for 2013 funding valuation | IRS required mortality table for 2012 funding valuation | IRS required mortality table for 2011 funding valuation | ||||||||||||||
Health care cost trend on covered charges | N/A | N/A | N/A | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 6.50% decreasing to ultimate trend of 5.00% in 2017 | 7.00% decreasing to ultimate trend of 5.00% in 2015 | ||||||||||||||
(a) The discount rates above represent the initial discount rates used to establish Exelon's pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurements. | ||||||||||||||||||||
(b) The discount rates above represent the initial discounts rates used to establish Exelon's pension and other postretirement benefits costs for 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements. | ||||||||||||||||||||
(c) Not applicable to pension and other postretirement benefit plans that do not have plan assets. | ||||||||||||||||||||
(d) 3.25% for 2013-2017 and 3.75% thereafter. | ||||||||||||||||||||
Pension And Other Postretirement Benefit Contributions [Text Block] | ' | |||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||
2013 | 2012 | 2011 (c) | 2013 (a) | 2012 (a) | 2011 (a) | |||||||||||||||
Generation | $ | 119 | $ | 48 | $ | 954 | $ | 30 | $ | 135 | $ | 121 | ||||||||
ComEd | 118 | 25 | 873 | 4 | 119 | 108 | ||||||||||||||
PECO | 11 | 13 | 110 | 20 | 33 | 28 | ||||||||||||||
BGE (b) | 0 | 0 | 0 | 24 | 12 | 0 | ||||||||||||||
BSC | 91 | 63 | 157 | 5 | 24 | 20 | ||||||||||||||
Exelon | $ | 339 | $ | 149 | $ | 2,094 | $ | 83 | $ | 323 | $ | 277 | ||||||||
(a) The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, and $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011. Effective January 1, 2013, Exelon is no longer receiving this subsidy. | ||||||||||||||||||||
(b) BGE's pension benefit contributions for 2012 and 2011 exclude $0 million and $54 million, respectively, of pension contributions made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. BGE's other postretirement benefit payments for 2012 and 2011 exclude $4 million and $13 million, respectively, of other postretirement benefit payments made by BGE prior to the closing of Exelon's merger with Constellation on March 12, 2012. These pre-merger contributions are not included in Exelon's financial statements but are reflected in BGE's financial statements. | ||||||||||||||||||||
(c) The increase in 2011 pension contributions was related to Exelon's $2.1 billion contribution to its pension plans as a result of accelerated cash benefits associated with the Tax Relief Act of 2010. | ||||||||||||||||||||
Defined Benefit Plan Estimated Future Benefit Payments [Text Block] | ' | |||||||||||||||||||
Other Postretirement | ||||||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||||||
2014 | $ | 929 | $ | 204 | ||||||||||||||||
2015 | 851 | 210 | ||||||||||||||||||
2016 | 873 | 219 | ||||||||||||||||||
2017 | 902 | 228 | ||||||||||||||||||
2018 | 1,015 | 238 | ||||||||||||||||||
2019 through 2023 | 5,257 | 1,383 | ||||||||||||||||||
Total estimated future benefit payments through 2023 | $ | 9,827 | $ | 2,482 | ||||||||||||||||
Schedule Of Pension And Other Postretirement Benefit Costs [Text Block] | ' | |||||||||||||||||||
For the Year Ended December 31, | Generation | ComEd | PECO | BSC (a) | BGE (b)(c) | Exelon | ||||||||||||||
2013 | $ | 347 | $ | 309 | $ | 43 | $ | 71 | $ | 55 | $ | 825 | ||||||||
2012 | 341 | 282 | 50 | 99 | 60 | 820 | ||||||||||||||
2011 | 249 | 213 | 32 | 48 | 51 | 542 | ||||||||||||||
___________________ | ||||||||||||||||||||
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | ||||||||||||||||||||
The amounts included in capital and operating and maintenance expense for the years ended December 31, 2012 and 2011 include $12 million and $51 million, respectively, in costs incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. These amounts are not included in Exelon's capital expenditures and operating and maintenance expense for the years ended December 31, 2012 and 2011. | ||||||||||||||||||||
BGE's pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012. | ||||||||||||||||||||
Defined Benefit Plan Weighted Average Asset Allocations And Target Allocations [Text Block] | ' | |||||||||||||||||||
Pension Plans | Percentage of Plan Assets | |||||||||||||||||||
at December 31, | ||||||||||||||||||||
Asset Category | Target Allocation | 2013 | 2012 | |||||||||||||||||
Equity securities | 31 | % | 35 | % | 35 | % | ||||||||||||||
Fixed income securities | 38 | % | 37 | 40 | ||||||||||||||||
Alternative investments (a) | 31 | % | 28 | 25 | ||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||
Other Postretirement Benefit Plans | Percentage of Plan Assets | |||||||||||||||||||
at December 31, | ||||||||||||||||||||
Asset Category | Target Allocation | 2013 | 2012 | |||||||||||||||||
Equity securities | 41 | % | 45 | % | 46 | % | ||||||||||||||
Fixed income securities | 39 | % | 37 | 40 | ||||||||||||||||
Alternative investments (a) | 20 | % | 18 | 14 | ||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||
(a) Alternative investments include private equity, hedge funds and real estate. | ||||||||||||||||||||
Defined Benefit Plan Fair Value Of Plan Assets [Text Block] | ' | |||||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Pension plan assets | ||||||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 3,090 | 0 | 2 | 3,092 | ||||||||||||||||
Commingled funds | 0 | 1,167 | 0 | 1,167 | ||||||||||||||||
Mutual funds | 270 | 0 | 0 | 270 | ||||||||||||||||
Equity securities subtotal | 3,360 | 1,167 | 2 | 4,529 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 908 | 9 | 0 | 917 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 88 | 0 | 88 | ||||||||||||||||
Foreign debt securities | 0 | 205 | 0 | 205 | ||||||||||||||||
Corporate debt securities | 0 | 2,927 | 41 | 2,968 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 90 | 0 | 90 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 26 | 0 | 26 | ||||||||||||||||
Commingled funds | 0 | 558 | 0 | 558 | ||||||||||||||||
Mutual funds | 5 | 315 | 0 | 320 | ||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||
Assets | 0 | 7 | 0 | 7 | ||||||||||||||||
Liabilities | 0 | -134 | 0 | -134 | ||||||||||||||||
Fixed income securities subtotal | 913 | 4,091 | 41 | 5,045 | ||||||||||||||||
Private equity | 0 | 0 | 806 | 806 | ||||||||||||||||
Hedge funds | 0 | 1,266 | 1,039 | 2,305 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 264 | 0 | 0 | 264 | ||||||||||||||||
Commingled funds | 0 | 2 | 0 | 2 | ||||||||||||||||
Real estate funds | 0 | 0 | 582 | 582 | ||||||||||||||||
Real estate subtotal | 264 | 2 | 582 | 848 | ||||||||||||||||
Pension plan assets subtotal | 4,537 | 6,526 | 2,470 | 13,533 | ||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||
Cash equivalents | 51 | 0 | 0 | 51 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 286 | 0 | 0 | 286 | ||||||||||||||||
Commingled funds | 0 | 515 | 0 | 515 | ||||||||||||||||
Mutual funds | 164 | 0 | 0 | 164 | ||||||||||||||||
Equity securities subtotal | 450 | 515 | 0 | 965 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 17 | 1 | 0 | 18 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 149 | 0 | 149 | ||||||||||||||||
Foreign debt securities | 0 | 2 | 0 | 2 | ||||||||||||||||
Corporate debt securities | 0 | 50 | 0 | 50 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 45 | 0 | 45 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 7 | 0 | 7 | ||||||||||||||||
Commingled funds | 0 | 218 | 0 | 218 | ||||||||||||||||
Mutual funds | 305 | 0 | 0 | 305 | ||||||||||||||||
Fixed income securities subtotal | 322 | 472 | 0 | 794 | ||||||||||||||||
Private equity | 0 | 0 | 2 | 2 | ||||||||||||||||
Hedge funds | 0 | 295 | 4 | 299 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 8 | 0 | 0 | 8 | ||||||||||||||||
Real estate funds | 0 | 5 | 109 | 114 | ||||||||||||||||
Real estate subtotal | 8 | 5 | 109 | 122 | ||||||||||||||||
Other postretirement benefit plan assets subtotal | 831 | 1,287 | 115 | 2,233 | ||||||||||||||||
Total pension and other postretirement | ||||||||||||||||||||
benefit plan assets (c) | $ | 5,368 | $ | 7,813 | $ | 2,585 | $ | 15,766 | ||||||||||||
At December 31, 2012 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||
Pension plan assets | ||||||||||||||||||||
Cash equivalents | $ | 1 | $ | 0 | $ | 0 | $ | 1 | ||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 2,562 | 0 | 0 | 2,562 | ||||||||||||||||
Commingled funds | 0 | 1,111 | 0 | 1,111 | ||||||||||||||||
Mutual funds | 323 | 0 | 0 | 323 | ||||||||||||||||
Equity securities subtotal | 2,885 | 1,111 | 0 | 3,996 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 1,037 | 0 | 0 | 1,037 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 108 | 0 | 108 | ||||||||||||||||
Foreign debt securities | 0 | 252 | 0 | 252 | ||||||||||||||||
Corporate debt securities | 0 | 3,330 | 0 | 3,330 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 117 | 0 | 117 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 28 | 0 | 28 | ||||||||||||||||
Commingled funds | 0 | 274 | 0 | 274 | ||||||||||||||||
Mutual funds | 4 | 291 | 0 | 295 | ||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||
Assets | 0 | 9 | 0 | 9 | ||||||||||||||||
Liabilities | 0 | -21 | 0 | -21 | ||||||||||||||||
Fixed income securities subtotal | 1,041 | 4,388 | 0 | 5,429 | ||||||||||||||||
Private equity | 0 | 0 | 754 | 754 | ||||||||||||||||
Hedge funds | 0 | 1,080 | 1,235 | 2,315 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 280 | 0 | 0 | 280 | ||||||||||||||||
Commingled funds | 0 | 75 | 0 | 75 | ||||||||||||||||
Real estate funds | 0 | 0 | 426 | 426 | ||||||||||||||||
Real estate subtotal | 280 | 75 | 426 | 781 | ||||||||||||||||
Pension plan assets subtotal | 4,207 | 6,654 | 2,415 | 13,276 | ||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||
Cash equivalents | 44 | 0 | 0 | 44 | ||||||||||||||||
Equity securities: | ||||||||||||||||||||
Individually held | 198 | 0 | 0 | 198 | ||||||||||||||||
Commingled funds | 0 | 530 | 0 | 530 | ||||||||||||||||
Mutual funds | 230 | 0 | 0 | 230 | ||||||||||||||||
Equity securities subtotal | 428 | 530 | 0 | 958 | ||||||||||||||||
Fixed income securities: | ||||||||||||||||||||
Debt securities issued by the U.S. Treasury and | ||||||||||||||||||||
other U.S. government corporations and agencies | 18 | 0 | 0 | 18 | ||||||||||||||||
Debt securities issued by states of the United States | ||||||||||||||||||||
and by political subdivisions of the states | 0 | 125 | 0 | 125 | ||||||||||||||||
Foreign debt securities | 0 | 3 | 0 | 3 | ||||||||||||||||
Corporate debt securities | 0 | 50 | 0 | 50 | ||||||||||||||||
Federal agency mortgage-backed securities | 0 | 52 | 0 | 52 | ||||||||||||||||
Non-Federal agency mortgage-backed securities | 0 | 6 | 0 | 6 | ||||||||||||||||
Commingled funds | 0 | 271 | 0 | 271 | ||||||||||||||||
Mutual funds | 295 | 2 | 0 | 297 | ||||||||||||||||
Fixed income securities subtotal | 313 | 509 | 0 | 822 | ||||||||||||||||
Private equity | 0 | 0 | 1 | 1 | ||||||||||||||||
Hedge funds | 0 | 188 | 12 | 200 | ||||||||||||||||
Real estate: | ||||||||||||||||||||
Individually held | 7 | 0 | 0 | 7 | ||||||||||||||||
Commingled funds | 0 | 2 | 0 | 2 | ||||||||||||||||
Real estate funds | 0 | 6 | 95 | 101 | ||||||||||||||||
Real estate subtotal | 7 | 8 | 95 | 110 | ||||||||||||||||
Other postretirement benefit plan assets subtotal | 792 | 1,235 | 108 | 2,135 | ||||||||||||||||
Total pension and other postretirement | ||||||||||||||||||||
benefit plan assets (c) | $ | 4,999 | $ | 7,889 | $ | 2,523 | $ | 15,411 | ||||||||||||
See Note 11 - Fair Value of Assets and Liabilities for a description of levels within the fair value hierarchy. | ||||||||||||||||||||
Derivative instruments have a total notional amount of $2,651 million and $2,498 million at December 31, 2013 and 2012, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss. | ||||||||||||||||||||
Excludes net assets of $43 million and $81 million at December 31, 2013 and 2012, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases. | ||||||||||||||||||||
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation [Text Block] | ' | |||||||||||||||||||
Hedge | Private | Real | Debt | Preferred | ||||||||||||||||
funds | equity | estate | securities | stock | Total | |||||||||||||||
Pension Assets | ||||||||||||||||||||
Balance as of January 1, 2013 | $ | 1,235 | $ | 754 | $ | 426 | $ | 0 | $ | 0 | $ | 2,415 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 143 | 86 | 63 | 0 | 0 | 292 | ||||||||||||||
Relating to assets sold during the period | 3 | 0 | -4 | 0 | 0 | -1 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 360 | 123 | 226 | 41 | 2 | 752 | ||||||||||||||
Sales | -76 | 0 | -91 | 0 | 0 | -167 | ||||||||||||||
Settlements(a) | -3 | -157 | -38 | 0 | 0 | -198 | ||||||||||||||
Transfers into (out of) Level 3(b) | -623 | 0 | 0 | 0 | 0 | -623 | ||||||||||||||
Balance as of December 31, 2013 | $ | 1,039 | $ | 806 | $ | 582 | $ | 41 | $ | 2 | $ | 2,470 | ||||||||
Other Postretirement Benefits | ||||||||||||||||||||
Balance as of January 1, 2013 | $ | 12 | $ | 1 | $ | 95 | $ | 0 | $ | 0 | $ | 108 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 1 | 0 | 11 | 0 | 0 | 12 | ||||||||||||||
Relating to assets sold during the period | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 0 | 1 | 3 | 0 | 0 | 4 | ||||||||||||||
Sales | -1 | 0 | 0 | 0 | 0 | -1 | ||||||||||||||
Settlements(a) | -4 | 0 | 0 | 0 | 0 | -4 | ||||||||||||||
Transfers into (out of) Level 3(b) | -4 | 0 | 0 | 0 | 0 | -4 | ||||||||||||||
Balance as of December 31, 2013 | $ | 4 | $ | 2 | $ | 109 | $ | 0 | $ | 0 | $ | 115 | ||||||||
Hedge | Private | Real | Debt | Preferred | ||||||||||||||||
funds | equity | estate | securities | stock | Total | |||||||||||||||
Pension Assets | ||||||||||||||||||||
Balance as of January 1, 2012 | $ | 1,525 | $ | 672 | $ | 229 | $ | 0 | $ | 0 | $ | 2,426 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 138 | 55 | 24 | 0 | 0 | 217 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 447 | 108 | 134 | 0 | 0 | 689 | ||||||||||||||
Sales | -6 | 0 | 0 | 0 | 0 | -6 | ||||||||||||||
Settlements(a) | -4 | -128 | -28 | 0 | 0 | -160 | ||||||||||||||
Transfers into (out of) Level 3(c)(d)(e) | -865 | 47 | 67 | 0 | 0 | -751 | ||||||||||||||
Balance as of December 31, 2012 | $ | 1,235 | $ | 754 | $ | 426 | $ | 0 | $ | 0 | $ | 2,415 | ||||||||
Other Postretirement Benefits | ||||||||||||||||||||
Balance as of January 1, 2012 | $ | 157 | $ | 1 | $ | 7 | $ | 0 | $ | 0 | $ | 165 | ||||||||
Actual return on plan assets: | ||||||||||||||||||||
Relating to assets still held at the reporting date | 11 | 0 | 3 | 0 | 0 | 14 | ||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||
Purchases | 32 | 0 | 91 | 0 | 0 | 123 | ||||||||||||||
Sales | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Settlements(a) | 0 | 0 | -1 | 0 | 0 | -1 | ||||||||||||||
Transfers into (out of) Level 3(c)(d)(e) | -188 | 0 | -5 | 0 | 0 | -193 | ||||||||||||||
Balance as of December 31, 2012 | $ | 12 | $ | 1 | $ | 95 | $ | 0 | $ | 0 | $ | 108 | ||||||||
Represents cash settlements only. | ||||||||||||||||||||
As of December 31, 2012, hedge fund investments that contained redemption restrictions limiting Exelon's ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $627 million in 2013. | ||||||||||||||||||||
In connection with the acquisition of Constellation in March 2012, Exelon assumed Constellation's pension plan assets resulting in transfers into Level 3 of $141 million. | ||||||||||||||||||||
In 2012, Exelon refined its policy over the criteria that hedge fund investments must meet in order to be categorized within Level 2 and Level 3 of the fair value hierarchy. Therefore, certain hedge fund investments that were categorized within Level 3 in prior periods have been re-categorized as Level 2 investments as of December 31, 2012. The re-categorization of these hedge fund investments is reflected as transfers out of Level 3 of $1.1 billion. | ||||||||||||||||||||
In 2012, the liquidity terms of a certain real estate investment changed to allow redemption within a reasonable period of time from the redemption date which led to a transfer out of Level 3 to Level 2 of $5 million. | ||||||||||||||||||||
Schedule Of Defined Contributions [Text Block] | ' | |||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | PECO | BGE (a) | BSC (b) | ||||||||||||||
2013 | $ | 85 | $ | 40 | $ | 22 | $ | 8 | $ | 8 | $ | 7 | ||||||||
2012 | 67 | 30 | 19 | 7 | 7 | 5 | ||||||||||||||
2011 | 78 | 40 | 22 | 9 | 7 | 7 |
Serverance_And_Plant_Retiremen
Serverance And Plant Retirements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||
Corporate Restructuring And Plant Retirements Tables [Abstract] | ' | ||||||||||||||||
Total severance benefits costs, recorded as operating and maintenance expense | ' | ||||||||||||||||
Year Ended December 31, 2012 | |||||||||||||||||
Severance Benefits (a) | Exelon (b) | Generation | ComEd (b) | PECO | BGE (b) | ||||||||||||
Severance charges | $ | 124 | $ | 80 | $ | 14 | $ | 7 | $ | 17 | |||||||
Stock compensation | 7 | 4 | 1 | 0 | 1 | ||||||||||||
Other charges | 7 | 4 | 1 | 0 | 1 | ||||||||||||
Total severance benefits | $ | 138 | $ | 88 | $ | 16 | $ | 7 | $ | 19 | |||||||
_________________ | |||||||||||||||||
The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012. | |||||||||||||||||
Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||
Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity) | ' | ||||||||||||||||
Severance liability | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Balance at December 31, 2011 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | |||||||
Severance charges (a) | 124 | 38 | 2 | 0 | 11 | ||||||||||||
Stock compensation | 7 | 2 | 0 | 0 | 0 | ||||||||||||
Other charges (b) | 7 | 2 | 0 | 0 | 1 | ||||||||||||
Payments | -27 | -9 | -1 | 0 | -1 | ||||||||||||
Balance at December 31, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | 0 | $ | 11 | |||||||
Severance charges | 5 | 1 | 0 | 0 | 0 | ||||||||||||
Stock compensation | 1 | 0 | 0 | 0 | 0 | ||||||||||||
Payments | -64 | -24 | -1 | 0 | -5 | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | 0 | $ | 0 | $ | 6 | |||||||
_____________________ | |||||||||||||||||
(a) Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon's ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2012 and December 31, 2013. | |||||||||||||||||
(b) Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services. | |||||||||||||||||
_____________________ | |||||||||||||||||
(a) Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon's ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2012 and December 31, 2013. | |||||||||||||||||
(b) Primarily includes life insurance, employer payroll taxes, educational assistance, and outplacement services. | |||||||||||||||||
Cash payments under the plan began in the second quarter of 2012. Substantially all cash payments under the plan are expected to be made by the end of 2016. | |||||||||||||||||
Ongoing Severance Plans | |||||||||||||||||
The Registrants provide severance and health and welfare benefits under Exelon's ongoing severance benefit plans to terminated employees in the normal course of business, which were not directly related to the merger with Constellation. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated. | |||||||||||||||||
For the years ended December 31, 2013, 2012, and 2011, the Registrants recorded the following severance costs associated with these ongoing severance benefits within operating and maintenance expense in their Consolidated Statements of Operations: | |||||||||||||||||
Schedule Of Severance Costs [TableTextBlock] | ' | ||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||
Severance charges - 2013 | $ | 18 | $ | 16 | $ | 2 | $ | 0 | $ | 0 | |||||||
Severance charges - 2012 | 19 | 14 | 2 | 1 | 3 | ||||||||||||
Severance charges - 2011 | 5 | 5 | 0 | 0 | 4 |
Preferred_Securities_Tables
Preferred Securities (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Schedule Of Redeemable Preferred [Line Items] | ' | |||||||||
Temporary Equity Table [Text Block] | ' | |||||||||
December 31, | ||||||||||
Redemption Price (a) | 2012 | 2012 | ||||||||
Shares Outstanding | Dollar Amount | |||||||||
Series (without mandatory redemption) | ||||||||||
$4.68 (Series D) | $ | 104 | 150,000 | $ | 15 | |||||
$4.40 (Series C) | 112.5 | 274,720 | 27 | |||||||
$4.30 (Series B) | 102 | 150,000 | 15 | |||||||
$3.80 (Series A) | 106 | 300,000 | 30 | |||||||
Total preferred securities | 874,720 | $ | 87 | |||||||
(a) Redeemable, at the option of PECO, at the indicated dollar amounts per share, plus accrued dividends. | ||||||||||
StockBased_Compensation_Plans_1
Stock-Based Compensation Plans (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2013 | |||||||||||
Stock-Based Compensation Plans [Line Items] | ' | ||||||||||
Stock Based Compensation Components [Text Block] | ' | ||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Components of Stock-Based Compensation Expense | 2013 | 2012 | 2011 | ||||||||
Performance share awards | $ | 48 | $ | 46 | $ | 26 | |||||
Restricted stock units | 61 | 50 | 31 | ||||||||
Stock options | 3 | 15 | 8 | ||||||||
Other stock-based awards | 6 | 4 | 4 | ||||||||
Total stock-based compensation expense included in | |||||||||||
operating and maintenance expense | 118 | 115 | 69 | ||||||||
Income tax benefit | -44 | -44 | -27 | ||||||||
Total after-tax stock-based compensation expense | $ | 74 | $ | 71 | $ | 42 | |||||
Stock Based Compensation Expense Subsidiaries [Text Block] | ' | ||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
Subsidiaries | 2013 | 2012 | 2011 (d) | ||||||||
Generation | $ | 48 | $ | 42 | $ | 31 | |||||
ComEd | 9 | 11 | 5 | ||||||||
PECO | 5 | 5 | 5 | ||||||||
BGE (a) | 6 | 5 | 6 | ||||||||
BSC (b) | 50 | 52 | 28 | ||||||||
Total (c) | $ | 118 | $ | 115 | $ | 69 | |||||
(a) BGE's stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the year ended December 31, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | |||||||||||
(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. | |||||||||||
(c) The stock-based compensation expense (pre-tax) for December 31, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd does not reflect the impact of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | |||||||||||
(d) The total stock-based compensation expense (pre-tax) for December 31, 2011 of $69 million does not include the $6 million expense for BGE as those costs were incurred prior to the closing of Exelon's merger with Constellation on March 12, 2012. | |||||||||||
Stock Based Compensation Tax Benefit [Text Block] | ' | ||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Realized tax benefit when exercised/distributed: | |||||||||||
Stock options | $ | 0 | $ | 3 | $ | 2 | |||||
Restricted stock units | 11 | 11 | 8 | ||||||||
Performance share awards | 11 | 7 | 7 | ||||||||
Stock deferral plan | 1 | 0 | 1 | ||||||||
Excess tax benefits included in other financing activities of Exelon’s | |||||||||||
Consolidated Statements of Cash Flows: | |||||||||||
Stock options | $ | 0 | $ | 2 | $ | 1 | |||||
Weighted Average Assumptions And Grand Date Fair Value Of Stock Options [Text Block] | ' | ||||||||||
Year Ended December 31, | |||||||||||
2012 | 2011 | ||||||||||
Dividend yield | 5.28 | % | 4.84 | % | |||||||
Expected volatility | 23.2 | % | 24.4 | % | |||||||
Risk-free interest rate | 1.3 | % | 2.65 | % | |||||||
Expected life (years) | 6.25 | 6.25 | |||||||||
Weighted average grant date fair value (per share) | $ | 4.18 | $ | 6.22 | |||||||
Stock Option Activity [Text Block] | ' | ||||||||||
Weighted | Weighted | ||||||||||
Average | Average | ||||||||||
Exercise | Remaining | ||||||||||
Price | Contractual | Aggregate | |||||||||
(per | Life | Intrinsic | |||||||||
Shares | share) | (years) | Value | ||||||||
Balance of shares outstanding at December 31, 2012 | 21,903,781 | $ | 45.91 | ||||||||
Options reinstated | 751,122 | 38.6 | |||||||||
Options exercised | -670,957 | 28.02 | |||||||||
Options forfeited | -54,743 | 39.36 | |||||||||
Options expired | -893,758 | 49.08 | |||||||||
Balance of shares outstanding at December 31, 2013 | 21,035,445 | $ | 46.07 | 4.72 | $ | 10 | |||||
Exercisable at December 31, 2013 (a) | 20,188,327 | $ | 46.31 | 4.58 | $ | 10 | |||||
(a) Includes stock options issued to retirement eligible employees. | |||||||||||
Stock Options Exercised [Text Block] | ' | ||||||||||
Year Ended | |||||||||||
December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
Intrinsic value (a) | $ | 4 | $ | 19 | $ | 5 | |||||
Cash received for exercise price | 19 | 47 | 13 | ||||||||
(a) The difference between the market value on the date of exercise and the option exercise price. | |||||||||||
Non Vested Stock Option [Text Block] | ' | ||||||||||
Weighted Average | |||||||||||
Exercise Price | |||||||||||
Shares | (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,960,665 | $ | 40.56 | ||||||||
Vested | -1,058,804 | 40.89 | |||||||||
Forfeited | -54,743 | 39.36 | |||||||||
Nonvested at December 31, 2013 (a) | 847,118 | $ | 40.22 | ||||||||
(a) Excludes 1,348,913 and 2,647,536 of stock options issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
Non Vested Restricted Stock [Text Block] | ' | ||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 2,029,161 | $ | 42.12 | ||||||||
Granted | 2,828,187 | 31.06 | |||||||||
Vested | -842,439 | 42.9 | |||||||||
Forfeited | -108,199 | 36.37 | |||||||||
Undistributed vested awards (b) | -520,013 | 32.62 | |||||||||
Nonvested at December 31, 2013 (a) | 3,386,697 | $ | 34.1 | ||||||||
(a) Excludes 931,628 and 686,121 of restricted stock units issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
Non Vested Performance Shares [Text Block] | ' | ||||||||||
Weighted Average | |||||||||||
Grant Date Fair | |||||||||||
Shares | Value (per share) | ||||||||||
Nonvested at December 31, 2012 (a) | 1,312,734 | $ | 40.08 | ||||||||
Granted | 2,629,171 | 31.55 | |||||||||
Vested | -612,624 | 40.13 | |||||||||
Forfeited | -24,451 | 32.17 | |||||||||
Undistributed vested awards (b) | -1,290,640 | 34.28 | |||||||||
Nonvested at December 31, 2013 (a) | 2,014,190 | $ | 32.74 | ||||||||
(a) Excludes 1,411,824 and 204,643 of performance share awards issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | |||||||||||
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2013. | |||||||||||
Not Settled Performance Share Awards Balance Sheet Presentation [Text Block] | ' | ||||||||||
December 31, | |||||||||||
2013 | 2012 | ||||||||||
Current liabilities (a) | $ | 13 | $ | 7 | |||||||
Deferred credits and other liabilities (b) | 24 | 11 | |||||||||
Common stock | 32 | 35 | |||||||||
Total | $ | 69 | $ | 53 | |||||||
(a) Represents the current liability related to performance share awards expected to be settled in cash. | |||||||||||
(b) Represents the long-term liability related to performance share awards expected to be settled in cash. | |||||||||||
Changes_in_Accumulated_Other_C1
Changes in Accumulated Other Comprehensive Income (Tables) | 12 Months Ended | |||||||||||||
Dec. 31, 2013 | ||||||||||||||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | |||||||||||||
Schedule Of Accumulated Other Comprehensive Income Loss Table [Text Block] | ' | |||||||||||||
Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | |||||||||
Exelon (a) | ||||||||||||||
Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | ||
OCI before reclassifications | 29 | 2 | 669 | -10 | 101 | 791 | ||||||||
Amounts reclassified from AOCI (b) | -277 | 0 | 208 | 0 | 5 | -64 | ||||||||
Net current-period OCI | -248 | 2 | 877 | -10 | 106 | 727 | ||||||||
Ending balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | ||
Generation (a) | ||||||||||||||
Beginning balance | $ | 512 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | $ | 513 | ||
OCI before reclassifications | 15 | 2 | 0 | -10 | 102 | 109 | ||||||||
Amounts reclassified from AOCI (b) | -413 | 0 | 0 | 0 | 5 | -408 | ||||||||
Net current-period OCI | -398 | 2 | 0 | -10 | 107 | -299 | ||||||||
Ending balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | ||
ComEd (a) | ||||||||||||||
PECO (a) | ||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | ||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | ||
BGE (a) | ||||||||||||||
Reclassification Out Of Accumulated Other Comprehensive Income Table [Text Block] | ' | |||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the statement where Net Income is presented | ||||||||||||
Exelon | Generation | |||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||
Energy related hedges | $ | 464 | $ | 683 | Operating revenues | |||||||||
Other cash flow hedges | -3 | 0 | Interest expense | |||||||||||
461 | 683 | Total before tax | ||||||||||||
-184 | -270 | Tax expense | ||||||||||||
$ | 277 | $ | 413 | Net of tax | ||||||||||
Gains and (losses) on available for sale securities | ||||||||||||||
Amortization of pension and other postretirement benefit plan items | ||||||||||||||
Prior service costs | $ | -2 | $ | 0 | (b) | |||||||||
Actuarial losses | -339 | 0 | (b) | |||||||||||
Deferred compensation unit plan | -1 | 0 | (c) | |||||||||||
-342 | 0 | Total before tax | ||||||||||||
134 | 0 | Tax benefit | ||||||||||||
$ | -208 | $ | 0 | Net of tax | ||||||||||
Equity investments | ||||||||||||||
Capital activity | $ | -8 | $ | -8 | Equity in losses of unconsolidated affiliates | |||||||||
-8 | -8 | Total before tax | ||||||||||||
3 | 3 | Tax benefit | ||||||||||||
$ | -5 | $ | -5 | Net of tax | ||||||||||
Total Reclassifications | $ | 64 | $ | 408 | Net of Tax |
Earnings_Per_Share_and_Equity_1
Earnings Per Share and Equity (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Earnings Per Share and Equity Tables [Abstract] | ' | |||||||||
Reconciliation of basic and diluted earnings per share | ' | |||||||||
Year Ended December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Net income attributable to common shareholders | $ | 1,719 | $ | 1,160 | $ | 2,495 | ||||
Weighted average common shares outstanding — basic | 856 | 816 | 663 | |||||||
Assumed exercise and/or distributions of stock-based awards | 4 | 3 | 2 | |||||||
Weighted average common shares outstanding — diluted | 860 | 819 | 665 |
Commitments_and_Contingencies_1
Commitments and Contingencies (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2013 | ||||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Utility Energy Purchase Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
ComEd | ||||||||||||||||||||||||
Electric supply procurement(a) | $ | 736 | $ | 323 | $ | 136 | $ | 137 | $ | 140 | $ | 0 | $ | 0 | ||||||||||
Renewable energy and RECs(b) | 1,589 | 72 | 74 | 76 | 77 | 83 | 1,207 | |||||||||||||||||
PECO | ||||||||||||||||||||||||
Electric supply procurement(c) | 681 | 590 | 91 | 0 | 0 | 0 | 0 | |||||||||||||||||
AECs(d) | 14 | 2 | 2 | 2 | 2 | 2 | 4 | |||||||||||||||||
BGE | ||||||||||||||||||||||||
Electric supply procurement(e) | 1,256 | 783 | 400 | 73 | 0 | 0 | 0 | |||||||||||||||||
Curtailment services(f) | 132 | 45 | 40 | 34 | 13 | 0 | 0 | |||||||||||||||||
_________________ | ||||||||||||||||||||||||
ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. The ICC's December 18, 2013 order approved the reduction of ComEd's commitments under the long-term contracts for the June 2014 through May 2015 procurement period, however the amount of the reduction will not be finalized and approved by the ICC until March 2014. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
BGE entered into various contracts for the procurement of electricity beginning 2013 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 3 – Regulatory Matters for additional information. | ||||||||||||||||||||||||
Fuel Purchase Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Generation | $ | 8,490 | $ | 1,212 | $ | 1,256 | $ | 1,040 | $ | 1,044 | $ | 763 | $ | 3,175 | ||||||||||
PECO | 507 | 179 | 112 | 98 | 37 | 15 | 66 | |||||||||||||||||
BGE | 609 | 129 | 59 | 57 | 57 | 51 | 256 | |||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,520 | $ | 1,217 | $ | 298 | $ | — | $ | 5 | $ | — | $ | — | ||||||||||
Surety bonds (b) | 339 | 301 | 2 | 6 | 4 | 1 | 25 | |||||||||||||||||
Performance guarantees (c) | 1,107 | 350 | — | — | — | — | 757 | |||||||||||||||||
Energy marketing contract | ||||||||||||||||||||||||
guarantees (d) | 3,161 | 3,161 | — | — | — | — | — | |||||||||||||||||
Lease guarantees (e) | 44 | — | — | — | — | — | 44 | |||||||||||||||||
Nuclear insurance premiums (f) | 3,529 | — | — | — | — | — | 3,529 | |||||||||||||||||
Total commercial commitments | $ | 9,700 | $ | 5,029 | $ | 300 | $ | 6 | $ | 9 | $ | 1 | $ | 4,355 | ||||||||||
(a) Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Guarantees issued to ensure performance under specific contracts, including $211 million issued on behalf of CENG nuclear generating facilities for credit support, $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II. | ||||||||||||||||||||||||
(d) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $463 million at December 31, 2013, which represents the total amount Exelon could be required to fund based on December 31, 2013 market prices. | ||||||||||||||||||||||||
(e) Lease guarantees - Guarantees issued to ensure payments on building leases. | ||||||||||||||||||||||||
(f) Nuclear insurance premiums - Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||
Operating Leases Of Lessee Disclosure [Text Block] | ' | |||||||||||||||||||||||
Exelon | Generation | ComEd (b) | PECO (b) | BGE (b)(c) | ||||||||||||||||||||
2014 | $ | 103 | $ | 49 | $ | 13 | $ | 13 | $ | 12 | ||||||||||||||
2015 | 91 | 50 | 11 | 3 | 11 | |||||||||||||||||||
2016 | 89 | 49 | 11 | 3 | 9 | |||||||||||||||||||
2017 | 82 | 48 | 7 | 3 | 8 | |||||||||||||||||||
2018 | 63 | 40 | 2 | 3 | 7 | |||||||||||||||||||
Remaining years | 398 | 336 | 3 | — | 14 | |||||||||||||||||||
Total minimum future lease payments | $ | 826 | (a) | $ | 572 | (a) | $ | 47 | $ | 25 | $ | 61 | ||||||||||||
(a) Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments. | ||||||||||||||||||||||||
(b) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd's, PECO's and BGE's annual obligation for these arrangements, included in each of the years 2014 - 2018, was $1 million, $3 million and $1 million respectively. | ||||||||||||||||||||||||
(c) Includes all future lease payments on a 99 year real estate lease that expires in 2105. | ||||||||||||||||||||||||
Operating Leases Rent Expense [Text Block] | ' | |||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation (a) | ComEd | PECO | BGE | |||||||||||||||||||
2013 | $ | 806 | $ | 744 | $ | 15 | $ | 21 | $ | 11 | ||||||||||||||
2012 | 930 | 872 | 18 | 27 | 12 | |||||||||||||||||||
2011 | 711 | 659 | 18 | 28 | 15 | |||||||||||||||||||
(a) Includes Generation's PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation's PPAs and other capacity contracts totaled $694 million, $801 million and $630 million during 2013, 2012 and 2011, respectively. | ||||||||||||||||||||||||
Accrued environmental liabilities [Text Block] | ' | |||||||||||||||||||||||
Total environmental investigation | Portion of total related to MGP | |||||||||||||||||||||||
31-Dec-13 | and remediation reserve | investigation and remediation | ||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||
Generation | 56 | 0 | ||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||
Total environmental investigation | Portion of total related to MGP | |||||||||||||||||||||||
31-Dec-12 | and remediation reserve | investigation and remediation | ||||||||||||||||||||||
Exelon | $ | 351 | $ | 298 | ||||||||||||||||||||
Generation | 42 | 0 | ||||||||||||||||||||||
ComEd | 261 | 254 | ||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||
BGE | 1 | 0 | ||||||||||||||||||||||
Other Purchase Obligation [Table Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Exelon | $ | 262 | $ | 61 | $ | 34 | $ | 32 | $ | 31 | $ | 26 | $ | 78 | ||||||||||
Generation | 504 | 170 | 131 | 45 | 42 | 30 | 86 | |||||||||||||||||
ComEd (a) | 122 | 88 | 5 | 5 | 5 | 5 | 14 | |||||||||||||||||
PECO (a) | 40 | 30 | 1 | 1 | 1 | 1 | 6 | |||||||||||||||||
BGE (a) | 53 | 44 | 2 | 5 | 2 | — | — | |||||||||||||||||
Exelon Generation Co L L C [Member] | ' | |||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Energy Commitments [Text Block] | ' | |||||||||||||||||||||||
Net Capacity | REC | Transmission Rights | Purchased Energy | |||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | from CENG | Total | ||||||||||||||||||||
2014 | $ | 412 | $ | 117 | $ | 25 | $ | 824 | $ | 1,378 | ||||||||||||||
2015 | 367 | 110 | 13 | — | 490 | |||||||||||||||||||
2016 | 284 | 76 | 2 | — | 362 | |||||||||||||||||||
2017 | 223 | 25 | 2 | — | 250 | |||||||||||||||||||
2018 | 112 | 3 | 2 | — | 117 | |||||||||||||||||||
Thereafter | 414 | 3 | 32 | — | 449 | |||||||||||||||||||
Total | $ | 1,812 | $ | 334 | $ | 76 | $ | 824 | $ | 3,046 | ||||||||||||||
(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at December 31, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | ||||||||||||||||||||||||
(b) The table excludes renewable energy purchases that are contingent in nature. | ||||||||||||||||||||||||
(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | ||||||||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,477 | $ | 1,174 | $ | 298 | $ | — | $ | 5 | $ | — | $ | — | ||||||||||
Performance guarantees (b) | 357 | 343 | — | — | — | — | 14 | |||||||||||||||||
Energy marketing contract guarantees (c) | 832 | 832 | — | — | — | — | — | |||||||||||||||||
Nuclear insurance premiums (d) | 3,529 | — | — | — | — | — | 3,529 | |||||||||||||||||
Total commercial commitments | $ | 6,195 | $ | 2,349 | $ | 298 | $ | — | $ | 5 | $ | — | $ | 3,543 | ||||||||||
(a) Letters of credit (non-debt) - Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Performance guarantees - Guarantees issued to ensure performance under specific contracts including $211 million issued on behalf of CENG nuclear generating facilities for credit support. | ||||||||||||||||||||||||
(c) Energy marketing contract guarantees - Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $749 million of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation's estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.2 billion at December 31, 2013, which represents the total amount Generation could be required to fund based on December 31, 2013 market prices. | ||||||||||||||||||||||||
(d) Nuclear insurance premiums - Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See Nuclear Insurance section within this note for additional details on Generation's nuclear insurance premiums. | ||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ' | |||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 19 | $ | 19 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 9 | 9 | — | — | — | — | — | |||||||||||||||||
Performance guarantees (c) | 200 | — | — | — | — | — | 200 | |||||||||||||||||
Total commercial commitments | $ | 228 | $ | 28 | $ | — | $ | — | $ | — | $ | — | $ | 200 | ||||||||||
(a) Letters of credit (non-debt) - ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd. | ||||||||||||||||||||||||
PECO Energy Co [Member] | ' | |||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 22 | $ | 22 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 3 | 3 | — | — | — | — | — | |||||||||||||||||
Performance guarantees(c) | 178 | — | — | — | — | — | 178 | |||||||||||||||||
Total commercial commitments | $ | 203 | $ | 25 | $ | — | $ | — | $ | — | $ | — | $ | 178 | ||||||||||
(a) Letters of credit (non-debt) - PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
(b) Surety bonds - Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
(c) Performance guarantees - Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO. | ||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | ' | |||||||||||||||||||||||
Commitments And Contingencies Tables Disclosure [Line Items] | ' | |||||||||||||||||||||||
Commercial Commitments [Text Block] | ' | |||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||
2019 | ||||||||||||||||||||||||
Total | 2014 | 2015 | 2016 | 2017 | 2018 | and beyond | ||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Surety bonds (b) | 9 | 9 | — | — | — | — | — | |||||||||||||||||
Performance guarantees (c) | 250 | — | — | — | — | — | 250 | |||||||||||||||||
Total commercial commitments | $ | 260 | $ | 10 | $ | — | $ | — | $ | — | $ | — | $ | 250 | ||||||||||
Letters of credit (non-debt) - BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | ||||||||||||||||||||||||
Surety bond – Guarantees issued related to contract and commercial agreements, excluding bid bonds. | ||||||||||||||||||||||||
Performance guarantee - Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE. | ||||||||||||||||||||||||
Supplemental_Financial_Informa1
Supplemental Financial Information (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Supplemental Financial Information Tables [Line Items] | ' | ||||||||||||||||||
Components of taxes other than income | ' | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 449 | $ | 79 | $ | 241 | $ | 129 | $ | 82 | |||||||||
Property | 302 | 205 | 24 | 14 | 112 | ||||||||||||||
Payroll | 159 | 89 | 27 | 13 | 15 | ||||||||||||||
Other | 185 | 16 | 7 | 2 | 4 | ||||||||||||||
Total taxes other than income | $ | 1,095 | $ | 389 | $ | 299 | $ | 158 | $ | 213 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 463 | $ | 82 | $ | 239 | $ | 141 | $ | 75 | |||||||||
Property | 227 | 189 | 22 | 13 | 111 | ||||||||||||||
Payroll | 131 | 78 | 26 | 12 | 18 | ||||||||||||||
Other | 198 | 20 | 8 | -4 | 4 | ||||||||||||||
Total taxes other than income | $ | 1,019 | $ | 369 | $ | 295 | $ | 162 | $ | 208 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Taxes other than income | |||||||||||||||||||
Utility (a) | $ | 443 | $ | 27 | $ | 243 | $ | 173 | $ | 79 | |||||||||
Property | 177 | 146 | 22 | 9 | 107 | ||||||||||||||
Payroll | 123 | 71 | 25 | 13 | 17 | ||||||||||||||
Other | 42 | 20 | 6 | 10 | 4 | ||||||||||||||
Total taxes other than income | $ | 785 | $ | 264 | $ | 296 | $ | 205 | $ | 207 | |||||||||
(a) Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
Components of non-operating income and expenses | ' | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 256 | $ | 256 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 77 | 77 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | 406 | 406 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 146 | 146 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets — | |||||||||||||||||||
Zion Station decommissioning | 7 | 7 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -546 | -546 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 346 | 346 | 0 | 0 | 0 | ||||||||||||||
Investment income | 8 | -1 | 0 | -1 | 9 | (c) | |||||||||||||
Long-term lease income | 28 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 24 | 4 | 0 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 22 | 0 | 11 | 4 | 7 | ||||||||||||||
Other | 45 | 19 | 15 | 3 | 1 | ||||||||||||||
Other, net | $ | 473 | $ | 368 | $ | 26 | $ | 6 | $ | 17 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 189 | $ | 189 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement Units | 102 | 102 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | 386 | 386 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | 105 | 105 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets — | |||||||||||||||||||
Zion Station decommissioning | 73 | 73 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -530 | -530 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 325 | 325 | 0 | 0 | 0 | ||||||||||||||
Investment income | 20 | 3 | 1 | 2 | 11 | (c) | |||||||||||||
Long-term lease income | 29 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 15 | 2 | 20 | 0 | 0 | ||||||||||||||
AFUDC - Equity | 17 | 0 | 6 | 4 | 10 | ||||||||||||||
Credit facility termination fees | -85 | -85 | 0 | 0 | 0 | ||||||||||||||
Other | 25 | -6 | 12 | 2 | 2 | ||||||||||||||
Other, net | $ | 346 | $ | 239 | $ | 39 | $ | 8 | $ | 23 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Other, Net | |||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||
Net realized income on decommissioning trust funds (a) - | |||||||||||||||||||
Regulatory agreement units | $ | 177 | $ | 177 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Non-regulatory agreement units | 45 | 45 | 0 | 0 | 0 | ||||||||||||||
Net unrealized losses on decommissioning trust funds — | |||||||||||||||||||
Regulatory agreement units | -74 | -74 | 0 | 0 | 0 | ||||||||||||||
Non-regulatory agreement units | -4 | -4 | 0 | 0 | 0 | ||||||||||||||
Net unrealized gains on pledged assets - | |||||||||||||||||||
Zion Station decommissioning | 48 | 48 | 0 | 0 | 0 | ||||||||||||||
Regulatory offset to decommissioning trust fund-related | |||||||||||||||||||
activities(b) | -130 | -130 | 0 | 0 | 0 | ||||||||||||||
Total decommissioning-related activities | 62 | 62 | 0 | 0 | 0 | ||||||||||||||
Investment income | 10 | 1 | 1 | 3 | 13 | (c) | |||||||||||||
Long-term lease income | 28 | 0 | 0 | 0 | 0 | ||||||||||||||
Interest income related to uncertain income tax positions | 53 | 31 | 14 | 1 | 0 | ||||||||||||||
AFUDC - Equity | 17 | 0 | 8 | 9 | 15 | ||||||||||||||
Bargain purchase gain related to Wolf Hollow acquisition | 36 | 36 | 0 | 0 | 0 | ||||||||||||||
Other | -3 | -8 | 6 | 1 | -2 | ||||||||||||||
Other, net | $ | 203 | $ | 122 | $ | 29 | $ | 14 | $ | 26 | |||||||||
(a) Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||||||||||||||||
(b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 3 – Regulatory Matters for additional information regarding the rate stabilization deferral. | |||||||||||||||||||
Components of depreciation, amortization and accretion, and other, net | ' | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,893 | $ | 813 | $ | 545 | $ | 219 | $ | 264 | |||||||||
Regulatory assets | 212 | 0 | 119 | 9 | 84 | ||||||||||||||
Amortization of intangible assets, net | 48 | 43 | 5 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities(a) | 430 | 507 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel(a) | 921 | 921 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 275 | 275 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 3,779 | $ | 2,559 | $ | 669 | $ | 228 | $ | 348 | |||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization, accretion and depletion | |||||||||||||||||||
Property, plant and equipment | $ | 1,712 | $ | 733 | $ | 525 | $ | 207 | $ | 245 | |||||||||
Regulatory assets | 129 | 0 | 80 | 10 | 53 | ||||||||||||||
Amortization of intangible assets, net | 40 | 35 | 5 | 0 | 0 | ||||||||||||||
Amortization of energy contract assets and liabilities(a) | 1,110 | 1,110 | 0 | 0 | 0 | ||||||||||||||
Nuclear fuel(a) | 848 | 848 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 240 | 240 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization, accretion and depletion | $ | 4,079 | $ | 2,966 | $ | 610 | $ | 217 | $ | 298 | |||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Depreciation, amortization and accretion | |||||||||||||||||||
Property, plant and equipment | $ | 1,284 | $ | 570 | $ | 502 | $ | 191 | $ | 224 | |||||||||
Regulatory assets | 63 | 0 | 52 | 11 | 50 | ||||||||||||||
Nuclear fuel(a) | 755 | 755 | 0 | 0 | 0 | ||||||||||||||
ARO accretion(b) | 214 | 214 | 0 | 0 | 0 | ||||||||||||||
Total depreciation, amortization and accretion | $ | 2,316 | $ | 1,539 | $ | 554 | $ | 202 | $ | 274 | |||||||||
(a) Included in revenues or fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
(b) Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||
Cash Flow Supplemental Disclosures | ' | ||||||||||||||||||
For the Year Ended December 31, 2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 866 | $ | 291 | $ | 283 | $ | 95 | $ | 130 | |||||||||
Income taxes (net of refunds) | 112 | -18 | 33 | 70 | 42 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 825 | $ | 345 | $ | 308 | $ | 43 | $ | 56 | |||||||||
Earnings from equity method investments | -10 | -10 | 0 | 0 | 0 | ||||||||||||||
Provision for uncollectible accounts | 101 | 10 | -15 | 61 | 44 | ||||||||||||||
Provision for excess and obsolete inventory | 9 | 9 | 0 | 0 | 0 | ||||||||||||||
Stock-based compensation costs | 120 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -169 | -169 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 104 | 104 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 12 | 0 | 9 | 3 | 0 | ||||||||||||||
Amortization of rate stabilization deferral | 66 | 0 | 0 | 0 | 66 | ||||||||||||||
Amortization of debt fair value adjustment | -34 | -34 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | -271 | 0 | -271 | 0 | 0 | ||||||||||||||
Amortization of debt costs | 18 | 10 | 1 | 2 | 2 | ||||||||||||||
Impairment of investments in direct financing leases (e) | 14 | 0 | 0 | 0 | 0 | ||||||||||||||
Impairment charges (f) | 149 | 149 | 0 | 0 | 0 | ||||||||||||||
Other | -58 | 0 | -4 | -1 | -15 | ||||||||||||||
Total other non-cash operating activities | $ | 876 | $ | 414 | $ | 28 | $ | 108 | $ | 153 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 12 | $ | 0 | $ | -35 | $ | 9 | $ | 38 | |||||||||
Other regulatory assets and liabilities | -64 | 0 | -43 | -16 | -71 | ||||||||||||||
Other current assets | -165 | -151 | -2 | 13 | -8 | ||||||||||||||
Other noncurrent assets and liabilities | 319 | 15 | 268 | (g) | -12 | -23 | |||||||||||||
Total changes in other assets and liabilities | $ | 102 | $ | -136 | $ | 188 | $ | -6 | $ | -64 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | -128 | $ | -128 | $ | 0 | $ | 0 | $ | 4 | |||||||||
Change in capital expenditures not paid | -38 | -107 | (h) | -8 | 13 | -48 | |||||||||||||
Consolidated VIE dividend to non-controlling interest | 63 | 63 | 0 | 0 | 0 | ||||||||||||||
Indemnification of like-kind exchange position (i) | 0 | 0 | 176 | 0 | 0 | ||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(d) Relates to integration costs to achieve distribution synergies related to the merger transaction. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(e) Relates to an other than temporary decline in the estimated residual value of one of Exelon's direct financing leases. See Note 8 – Impairment of Long-Lived Assets for more information. | |||||||||||||||||||
(f) Relates to the cancellation of uprate projects and write down of certain wind projects at Generation. See Note 8 – Impairment of Long-Lived Assets for more information. | |||||||||||||||||||
(g) Relates primarily to interest payable related to like-kind exchange tax position. See Note 14 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
(h) Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | |||||||||||||||||||
(i) See Note 14 – Income Taxes for discussion of the like-kind exchange tax position. | |||||||||||||||||||
For the Year Ended December 31, 2012 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 761 | $ | 286 | $ | 288 | $ | 113 | $ | 136 | |||||||||
Income taxes (net of refunds) | -171 | 175 | -42 | -64 | -112 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 820 | $ | 341 | $ | 282 | $ | 50 | $ | 57 | |||||||||
Loss in equity method investments | 91 | 91 | 0 | 0 | 0 | ||||||||||||||
Provision for uncollectible accounts | 164 | 22 | 42 | 60 | 44 | ||||||||||||||
Provision for excess and obsolete inventory | 6 | 6 | 1 | 0 | 0 | ||||||||||||||
Stock-based compensation costs | 94 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | -145 | -145 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 160 | 160 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 18 | 0 | 13 | 3 | 2 | ||||||||||||||
Amortization of rate stabilization deferral | 57 | 0 | 0 | 0 | 67 | ||||||||||||||
Amortization of debt fair value adjustment | -34 | -34 | 0 | 0 | 0 | ||||||||||||||
Merger-related commitments (d) | 141 | 32 | 0 | 0 | 27 | ||||||||||||||
Severance costs | 99 | 34 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (c) | -96 | 0 | -96 | 0 | 0 | ||||||||||||||
Amortization of debt costs | 19 | 11 | 5 | 3 | 2 | ||||||||||||||
Other | -11 | 19 | 5 | 9 | -6 | ||||||||||||||
Total other non-cash operating activities | $ | 1,383 | $ | 537 | $ | 252 | $ | 125 | $ | 193 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 71 | $ | 0 | $ | 28 | $ | 20 | $ | 26 | |||||||||
Other regulatory assets and liabilities | -404 | 0 | -68 | 18 | -112 | ||||||||||||||
Other current assets | 213 | -30 | -7 | -12 | -7 | ||||||||||||||
Other noncurrent assets and liabilities | -248 | -98 | -95 | -10 | 8 | ||||||||||||||
Total changes in other assets and liabilities | $ | -368 | $ | -128 | $ | -142 | $ | 16 | $ | -85 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | 781 | $ | 781 | $ | 2 | $ | 0 | $ | 0 | |||||||||
Change in capital expenditures not paid | 160 | 103 | (e) | 15 | 26 | -4 | |||||||||||||
Merger with Constellation, common stock issued | 7,365 | 5,264 | 0 | 0 | 0 | ||||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 – Regulatory Matters for more information. | |||||||||||||||||||
(d) Relates to the integration costs to achieve distribution synergies related to the merger transaction. See Note 4 – Mergers and Acquisitions for more information on merger-related commitments. | |||||||||||||||||||
(e) Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | |||||||||||||||||||
For the Year Ended December 31, 2011 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||
Interest (net of amount capitalized) | $ | 649 | $ | 158 | $ | 296 | $ | 128 | $ | 122 | |||||||||
Income taxes (net of refunds) | -457 | 347 | -676 | -65 | -54 | ||||||||||||||
Other non-cash operating activities: | |||||||||||||||||||
Pension and non-pension postretirement benefit costs | $ | 542 | $ | 249 | $ | 213 | $ | 32 | $ | 51 | |||||||||
Provision for uncollectible accounts | 121 | 0 | 57 | 64 | 44 | ||||||||||||||
Stock-based compensation costs | 67 | 0 | 0 | 0 | 0 | ||||||||||||||
Other decommissioning-related activity (a) | 16 | 16 | 0 | 0 | 0 | ||||||||||||||
Energy-related options (b) | 137 | 137 | 0 | 0 | 0 | ||||||||||||||
Amortization of regulatory asset related to debt costs | 21 | 0 | 18 | 3 | 2 | ||||||||||||||
Amortization of rate stabilization deferral | 0 | 0 | 0 | 0 | 57 | ||||||||||||||
Deferral of storm costs | 0 | 0 | 0 | 0 | -16 | ||||||||||||||
Uncollectible accounts recovery, net | 14 | 0 | 14 | 0 | 0 | ||||||||||||||
Discrete impacts from 2010 Rate Case Order (c) | -32 | 0 | -32 | 0 | 0 | ||||||||||||||
Bargain purchase gain related to Wolf Hollow Acquisition | -36 | -36 | 0 | 0 | 0 | ||||||||||||||
Discrete impacts from EIMA (d) | -82 | 0 | -82 | 0 | 0 | ||||||||||||||
Other | 2 | 55 | -4 | 1 | -9 | ||||||||||||||
Total other non-cash operating activities | $ | 770 | $ | 421 | $ | 184 | $ | 100 | $ | 129 | |||||||||
Changes in other assets and liabilities: | |||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | -45 | $ | 0 | $ | -49 | $ | 4 | $ | -52 | |||||||||
Other regulatory assets and liabilities | 0 | 0 | 44 | 26 | 10 | ||||||||||||||
Other current assets | -101 | -23 | -14 | -12 | -88 | ||||||||||||||
Other noncurrent assets and liabilities | 122 | -34 | 64 | -4 | -31 | ||||||||||||||
Total changes in other assets and liabilities | $ | -24 | $ | -57 | $ | 45 | $ | 14 | $ | -161 | |||||||||
Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Non-cash investing and financing activities: | |||||||||||||||||||
Change in ARC | $ | 186 | $ | 186 | $ | 0 | $ | 0 | $ | 0 | |||||||||
Change in capital expenditures not paid | 96 | 125 | (e) | 7 | -35 | -7 | |||||||||||||
(a) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||||||||
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||||||||||||||||
(c) In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 3 - Regulatory Matters for more information. | |||||||||||||||||||
(d) Includes the establishment of a regulatory asset, pursuant to EIMA, for the 2011 annual reconciliation in ComEd's distribution formula rate tariff and the deferral of costs associated with significant 2011 storms, partially offset by an accrual to fund a new Science and Technology Innovation Trust. See Note 3 - Regulatory Matters for more information. | |||||||||||||||||||
(e) Includes $120 million of changes in capital expenditures not paid between December 31, 2011 and 2010 related to Antelope Valley. | |||||||||||||||||||
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, respectively, and reimbursements of $95 million, $37 million and $58 million, respectively, related to PECO's and BGE's DOE SGIG programs. For the year ended December 31, 2012, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $103 million, $56 million and $47 million, respectively, and reimbursements of $113 million, $66 million and $47 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 3 - Regulatory Matters for additional information regarding the DOE SGIG. | |||||||||||||||||||
Investments Table Text Block | ' | ||||||||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Investments | |||||||||||||||||||
Equity method investments: | |||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | 0 | $ | 6 | $ | 8 | $ | 8 | |||||||||
Keystone Fuels, LLC | 32 | 32 | 0 | 0 | 0 | ||||||||||||||
Conemaugh Fuels, LLC | 21 | 21 | 0 | 0 | 0 | ||||||||||||||
CENG | 1,925 | 1,925 | 0 | 0 | 0 | ||||||||||||||
Safe Harbor | 285 | 285 | 0 | 0 | 0 | ||||||||||||||
Malacha | 8 | 8 | 0 | 0 | 0 | ||||||||||||||
Other investments | 31 | 31 | 0 | 0 | 0 | ||||||||||||||
Total equity method investments | 2,324 | 2,302 | 6 | 8 | 8 | ||||||||||||||
Other investments: | |||||||||||||||||||
Net investment in direct financing leases | 698 | 0 | 0 | 0 | 0 | ||||||||||||||
Employee benefit trusts and investments (b) | 90 | 23 | 5 | 23 | 5 | ||||||||||||||
Total investments | $ | 3,112 | $ | 2,325 | $ | 11 | $ | 31 | $ | 13 | |||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Investments | |||||||||||||||||||
Equity method investments: | |||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | 0 | $ | 6 | $ | 8 | $ | 8 | |||||||||
Keystone Fuels, LLC | 38 | 38 | 0 | 0 | 0 | ||||||||||||||
Conemaugh Fuels, LLC | 26 | 26 | 0 | 0 | 0 | ||||||||||||||
CENG | 1,849 | 1,849 | 0 | 0 | 0 | ||||||||||||||
Safe Harbor | 293 | 293 | 0 | 0 | 0 | ||||||||||||||
Malacha | 8 | 8 | 0 | 0 | 0 | ||||||||||||||
Other investments | 34 | 33 | 0 | 0 | 0 | ||||||||||||||
Total equity method investments | 2,270 | 2,247 | 6 | 8 | 8 | ||||||||||||||
Other investments: | |||||||||||||||||||
Net investment in direct financing leases | 685 | 0 | 0 | 0 | 0 | ||||||||||||||
Employee benefit trusts and investments (b) | 100 | 22 | 8 | 22 | 5 | ||||||||||||||
Total investments | $ | 3,055 | $ | 2,269 | $ | 14 | $ | 30 | $ | 13 | |||||||||
(a) Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the Consolidated Balance Sheets. See Note 1 - Significant Accounting Policies for additional information. | |||||||||||||||||||
(b) The Registrants' investments in these marketable securities are recorded at fair market value. | |||||||||||||||||||
Accrued Liabilities Current Table | ' | ||||||||||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Accrued expenses | |||||||||||||||||||
Compensation-related accruals (a) | $ | 683 | $ | 337 | $ | 135 | $ | 47 | $ | 55 | |||||||||
Taxes accrued | 315 | 212 | 62 | 24 | 16 | ||||||||||||||
Interest accrued | 234 | 72 | 95 | 32 | 29 | ||||||||||||||
Severance accrued | 66 | 31 | 3 | 1 | 4 | ||||||||||||||
Other accrued expenses | 335 | (b) | 324 | (b) | 12 | 2 | 7 | ||||||||||||
Total accrued expenses | $ | 1,633 | $ | 976 | $ | 307 | $ | 106 | $ | 111 | |||||||||
31-Dec-12 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||
Accrued expenses | |||||||||||||||||||
Compensation-related accruals (a) | $ | 708 | $ | 371 | $ | 125 | $ | 45 | $ | 38 | |||||||||
Taxes accrued | 353 | 247 | 61 | 3 | 22 | ||||||||||||||
Interest accrued | 232 | 60 | 96 | 32 | 37 | ||||||||||||||
Severance accrued | 91 | 42 | 4 | 1 | 5 | ||||||||||||||
Other accrued expenses | 412 | (b) | 396 | (b) | 9 | 1 | 0 | ||||||||||||
Total accrued expenses | $ | 1,796 | $ | 1,116 | $ | 295 | $ | 82 | $ | 102 | |||||||||
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. | ||||||||||||||||||
(b) | Includes $228 million and $327 million for amounts accrued related to Antelope Valley as of December 31, 2013 and December 31, 2012, respectively. | ||||||||||||||||||
Accumulated Other Comprehensive Income Net Of Taxes | ' | ||||||||||||||||||
Gains and (Losses) on Cash Flow Hedges | Unrealized Gains and (Losses) on Marketable Securities | Pension and Non-Pension Postretirement Benefit Plan items | Foreign Currency Items | AOCI of Equity Investments | Total | ||||||||||||||
Exelon (a) | |||||||||||||||||||
Beginning balance | $ | 368 | $ | 0 | $ | -3,137 | $ | 0 | $ | 2 | $ | -2,767 | |||||||
OCI before reclassifications | 29 | 2 | 669 | -10 | 101 | 791 | |||||||||||||
Amounts reclassified from AOCI (b) | -277 | 0 | 208 | 0 | 5 | -64 | |||||||||||||
Net current-period OCI | -248 | 2 | 877 | -10 | 106 | 727 | |||||||||||||
Ending balance | $ | 120 | $ | 2 | $ | -2,260 | $ | -10 | $ | 108 | $ | -2,040 | |||||||
Generation (a) | |||||||||||||||||||
Beginning balance | $ | 512 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | $ | 513 | |||||||
OCI before reclassifications | 15 | 2 | 0 | -10 | 102 | 109 | |||||||||||||
Amounts reclassified from AOCI (b) | -413 | 0 | 0 | 0 | 5 | -408 | |||||||||||||
Net current-period OCI | -398 | 2 | 0 | -10 | 107 | -299 | |||||||||||||
Ending balance | $ | 114 | $ | 2 | $ | 0 | $ | -10 | $ | 108 | $ | 214 | |||||||
ComEd (a) | |||||||||||||||||||
PECO (a) | |||||||||||||||||||
Beginning balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||||||
OCI before reclassifications | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||
Amounts reclassified from AOCI (b) | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||
Net current-period OCI | 0 | 0 | 0 | 0 | 0 | 0 | |||||||||||||
Ending balance | $ | 0 | $ | 1 | $ | 0 | $ | 0 | $ | 0 | $ | 1 | |||||||
BGE (a) |
Segment_Information_Tables
Segment Information (Tables) | 12 Months Ended | ||||||||||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||||||
Analysis and reconciliation of reportable segment information | ' | ||||||||||||||||||||||||||
Intersegment | |||||||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE(b) | Other(c) | Eliminations | Exelon | |||||||||||||||||||||
Operating revenues(d): | |||||||||||||||||||||||||||
2013 | $ | 15,630 | $ | 4,464 | $ | 3,100 | $ | 3,065 | $ | 1,241 | $ | -2,612 | $ | 24,888 | |||||||||||||
2012 | 14,437 | 5,443 | 3,186 | 2,091 | 1,396 | -3,064 | 23,489 | ||||||||||||||||||||
2011 | 10,447 | 6,056 | 3,720 | 0 | 830 | -1,990 | 19,063 | ||||||||||||||||||||
Intersegment revenues(e): | |||||||||||||||||||||||||||
2013 | $ | 1,367 | $ | 3 | $ | 1 | $ | 13 | $ | 1,237 | $ | -2,607 | $ | 14 | |||||||||||||
2012 | 1,660 | 2 | 3 | 9 | 1,381 | -3,049 | 6 | ||||||||||||||||||||
2011 | 1,161 | 2 | 5 | 0 | 831 | -1,990 | 9 | ||||||||||||||||||||
Depreciation and amortization | |||||||||||||||||||||||||||
2013 | $ | 856 | $ | 669 | $ | 228 | $ | 348 | $ | 52 | $ | 0 | $ | 2,153 | |||||||||||||
2012 | 768 | 610 | 217 | 238 | 48 | 0 | 1,881 | ||||||||||||||||||||
2011 | 570 | 554 | 202 | 0 | 21 | 0 | 1,347 | ||||||||||||||||||||
Operating expenses(d): | |||||||||||||||||||||||||||
2013 | $ | 13,976 | $ | 3,510 | $ | 2,434 | $ | 2,616 | $ | 1,324 | $ | -2,618 | $ | 21,242 | |||||||||||||
2012 | 13,226 | 4,557 | 2,563 | 2,053 | 1,662 | -3,043 | 21,018 | ||||||||||||||||||||
2011 | 7,571 | 5,074 | 3,065 | 0 | 863 | -1,990 | 14,583 | ||||||||||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | |||||||||||||||||||||||||||
2013 | $ | 10 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | 10 | |||||||||||||
2012 | -91 | 0 | 0 | 0 | 0 | 0 | -91 | ||||||||||||||||||||
2011 | -1 | 0 | 0 | 0 | 0 | 0 | -1 | ||||||||||||||||||||
Interest expense, net: | |||||||||||||||||||||||||||
2013 | $ | 357 | $ | 579 | $ | 115 | $ | 122 | $ | 183 | $ | 0 | $ | 1,356 | |||||||||||||
2012 | 301 | 307 | 123 | 111 | 86 | 0 | 928 | ||||||||||||||||||||
2011 | 170 | 345 | 134 | 0 | 77 | 0 | 726 | ||||||||||||||||||||
Income (loss) before income taxes: | |||||||||||||||||||||||||||
2013 | $ | 1,675 | $ | 401 | $ | 557 | $ | 344 | $ | -191 | $ | -13 | $ | 2,773 | |||||||||||||
2012 | 1,058 | 618 | 508 | -54 | -325 | -7 | 1,798 | ||||||||||||||||||||
2011 | 2,827 | 666 | 535 | 0 | -59 | -13 | 3,956 | ||||||||||||||||||||
Income taxes: | |||||||||||||||||||||||||||
2013 | $ | 615 | $ | 152 | $ | 162 | $ | 134 | $ | -20 | $ | 1 | $ | 1,044 | |||||||||||||
2012 | 500 | 239 | 127 | -23 | -215 | -1 | 627 | ||||||||||||||||||||
2011 | 1,056 | 250 | 146 | 0 | 9 | -4 | 1,457 | ||||||||||||||||||||
Net income (loss): | |||||||||||||||||||||||||||
2013 | $ | 1,060 | $ | 249 | $ | 395 | $ | 210 | $ | -171 | $ | -14 | $ | 1,729 | |||||||||||||
2012 | 558 | 379 | 381 | -31 | -110 | -6 | 1,171 | ||||||||||||||||||||
2011 | 1,771 | 416 | 389 | 0 | -68 | -9 | 2,499 | ||||||||||||||||||||
Capital expenditures: | |||||||||||||||||||||||||||
2013 | $ | 2,752 | $ | 1,433 | $ | 537 | $ | 587 | $ | 86 | $ | 0 | $ | 5,395 | |||||||||||||
2012 | 3,554 | 1,246 | 422 | 500 | 67 | 0 | 5,789 | ||||||||||||||||||||
2011 | 2,491 | 1,028 | 481 | 0 | 42 | 0 | 4,042 | ||||||||||||||||||||
Total assets: | |||||||||||||||||||||||||||
2013 | $ | 41,232 | $ | 24,118 | $ | 9,617 | $ | 7,861 | $ | 8,317 | $ | -11,221 | $ | 79,924 | |||||||||||||
2012 | 40,681 | 22,905 | 9,353 | 7,506 | 10,432 | -12,316 | 78,561 | ||||||||||||||||||||
(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the year ended December 31, 2013 include revenue from sales to PECO of $405 and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012 include revenue from sales to PECO of $543 and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended 2011 intersegment revenues for Generation include revenue from sales to PECO of $508 million in the Mid-Atlantic region, and sales to ComEd of $653 million in the Midwest region. | |||||||||||||||||||||||||||
(b) Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2013. | |||||||||||||||||||||||||||
(c) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||||||
(d) For the years ended December 31, 2013, 2012 and 2011, utility taxes of $79 million, $82 million and $27 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2013, 2012 and 2011, utility taxes of $241 million, $239 million and $243 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2013, 2012 and 2011, utility taxes of $129 million, $141 million and $173 million, respectively, are included in revenues and expenses for PECO. For the year ended December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||||||||||||||||
(e) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. | |||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||||||||||
Segment Reporting Information [Line Items] | ' | ||||||||||||||||||||||||||
Analysis and reconciliation of reportable segment revenues for Generation | ' | ||||||||||||||||||||||||||
Generation total revenues: | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||||
Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | Revenues from external customers (a) | Intersegment revenues | Total Revenues | |||||||||||||||||||
Mid-Atlantic | $ | 5,182 | $ | 22 | $ | 5,204 | $ | 5,082 | $ | -44 | $ | 5,038 | $ | 4,052 | $ | 0 | $ | 4,052 | |||||||||
Midwest | 4,280 | -10 | 4,270 | 4,824 | 24 | 4,848 | 5,445 | 0 | 5,445 | ||||||||||||||||||
New England | 1,245 | -8 | 1,237 | 1,048 | 45 | 1,093 | 11 | 0 | 11 | ||||||||||||||||||
New York | 735 | -21 | 714 | 582 | -25 | 557 | 0 | 0 | 0 | ||||||||||||||||||
ERCOT | 1,222 | -6 | 1,216 | 1,365 | 2 | 1,367 | 575 | 0 | 575 | ||||||||||||||||||
Other Regions (b) | 946 | 22 | 968 | 755 | 78 | 833 | 201 | 0 | 201 | ||||||||||||||||||
Total Revenues for Reportable Segments | $ | 13,610 | $ | -1 | $ | 13,609 | $ | 13,656 | $ | 80 | $ | 13,736 | $ | 10,284 | $ | 0 | $ | 10,284 | |||||||||
Other (c) | 2,020 | 1 | 2,021 | 781 | -80 | 701 | 163 | 0 | 163 | ||||||||||||||||||
Total Generation Consolidated Operating Revenues | $ | 15,630 | $ | 0 | $ | 15,630 | $ | 14,437 | $ | 0 | $ | 14,437 | $ | 10,447 | $ | 0 | $ | 10,447 | |||||||||
Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation | ' | ||||||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense: | |||||||||||||||||||||||||||
2013 | 2012 | 2011 | |||||||||||||||||||||||||
RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | RNF from external customers (a) | Intersegment RNF | Total RNF | |||||||||||||||||||
Mid-Atlantic | $ | 3,273 | $ | -3 | $ | 3,270 | $ | 3,477 | $ | -44 | $ | 3,433 | $ | 3,350 | $ | 0 | $ | 3,350 | |||||||||
Midwest | 2,585 | 1 | 2,586 | 2,974 | 24 | 2,998 | 3,547 | 0 | 3,547 | ||||||||||||||||||
New England | 217 | -32 | 185 | 151 | 45 | 196 | 9 | 0 | 9 | ||||||||||||||||||
New York | 14 | -18 | -4 | 101 | -25 | 76 | - | 0 | - | ||||||||||||||||||
ERCOT | 604 | -168 | 436 | 403 | 2 | 405 | 84 | 0 | 84 | ||||||||||||||||||
Other Regions (b) | 334 | -133 | 201 | 53 | 78 | 131 | -14 | 0 | -14 | ||||||||||||||||||
Total Revenues net of purchased power and fuel expense for Reportable Segments | $ | 7,027 | $ | -353 | $ | 6,674 | $ | 7,159 | $ | 80 | $ | 7,239 | $ | 6,976 | $ | 0 | $ | 6,976 | |||||||||
Other (c) | 406 | 353 | 759 | 217 | -80 | 137 | -118 | 0 | -118 | ||||||||||||||||||
Total Generation Revenues net of purchased power and fuel expense | $ | 7,433 | $ | 0 | $ | 7,433 | $ | 7,376 | $ | 0 | $ | 7,376 | $ | 6,858 | $ | 0 | $ | 6,858 | |||||||||
(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $488 million and $1,098 million, for the years ended December 31, 2013 and 2012, respectively, and the elimination of intersegment revenues. | |||||||||||||||||||||||||||
Reconciliation of revenues from segments to consolidated | ' | ||||||||||||||||||||||||||
(a) Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||||||||||||||||
(b) Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||||||||||||||
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $767 million and $1,505 million for the years ended December 31, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 12 Months Ended | |||||||||
Dec. 31, 2013 | ||||||||||
Related Party Transaction [Line Items] | ' | |||||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | |||||||||
Year Ended | Period March 12, | |||||||||
Ended December 31, | through December 31, | |||||||||
2013 | 2012 | |||||||||
Equity investment income | $ | 123 | $ | 73 | ||||||
Amortization of basis difference in CENG | -114 | -172 | ||||||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 | ||||||
Related Party Transactions Income Statement Disclosure [Text Block] | ' | |||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
PECO (a) | $ | 10 | $ | 6 | $ | 9 | ||||
CENG (b) | 56 | 42 | 0 | |||||||
BGE | 4 | 0 | 0 | |||||||
Total operating revenues from affiliates | $ | 70 | $ | 48 | $ | 9 | ||||
Purchase power and fuel from affiliates: | ||||||||||
CENG (c) | $ | 992 | $ | 793 | $ | 0 | ||||
Keystone Fuels, LLC | 144 | 119 | 68 | |||||||
Conemaugh Fuels, LLC | 98 | 101 | 69 | |||||||
Safe Harbor Water Power Corp | 22 | 23 | 0 | |||||||
Total purchase power and fuel from affiliates | $ | 1,256 | $ | 1,036 | $ | 137 | ||||
Interest expense to affiliates, net: | ||||||||||
ComEd Financing III | $ | 13 | $ | 13 | $ | 13 | ||||
PECO Trust III | 6 | 6 | 6 | |||||||
PECO Trust IV | 6 | 6 | 6 | |||||||
BGE Capital Trust II (f) | 16 | 12 | 0 | |||||||
Total interest expense to affiliates, net | $ | 41 | $ | 37 | $ | 25 | ||||
Earnings (losses) in equity method investments: | ||||||||||
CENG (e) | $ | 9 | $ | -99 | $ | 0 | ||||
Qualifying facilities and domestic power projects | 1 | 8 | -1 | |||||||
Total earnings (losses) in equity method investments | $ | 10 | $ | -91 | $ | -1 | ||||
Related Party Transactions Balance Sheet Disclosure [Text Block] | ' | |||||||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Investments in affiliates: | ||||||||||
ComEd Financing III | $ | 6 | $ | 6 | ||||||
PECO Energy Capital Corporation | 4 | 4 | ||||||||
PECO Trust IV | 4 | 4 | ||||||||
BGE Capital Trust II | 8 | 8 | ||||||||
Total investments in affiliates | $ | 22 | $ | 22 | ||||||
Receivables from affiliates (current): | ||||||||||
CENG (b) | $ | 3 | $ | 16 | ||||||
Payables to affiliates (current): | ||||||||||
CENG (c) | $ | 85 | $ | 83 | ||||||
ComEd Financing III | 4 | 4 | ||||||||
PECO Trust III | 1 | 1 | ||||||||
BGE Capital Trust II | 4 | 4 | ||||||||
Keystone Fuels, LLC | 12 | 11 | ||||||||
Conemaugh Fuels, LLC | 9 | 9 | ||||||||
Other | 1 | 0 | ||||||||
Total payables to affiliates (current) | $ | 116 | $ | 112 | ||||||
Long-term debt due to financing trusts: | ||||||||||
ComEd Financing III | $ | 206 | $ | 206 | ||||||
PECO Trust III | 81 | 81 | ||||||||
PECO Trust IV | 103 | 103 | ||||||||
BGE Capital Trust II | 258 | 258 | ||||||||
Total long-term debt due to financing trusts | $ | 648 | $ | 648 | ||||||
Exelon Generation Co L L C [Member] | ' | |||||||||
Related Party Transaction [Line Items] | ' | |||||||||
Schedule Of Income Loss From Equity Method Investments [Text Block] | ' | |||||||||
Year Ended | Period March 12, | |||||||||
Ended December 31, | through December 31, | |||||||||
2013 | 2012 | |||||||||
Equity investment income | $ | 123 | $ | 73 | ||||||
Amortization of basis difference in CENG | -114 | -172 | ||||||||
Total equity in earnings (losses) - CENG | $ | 9 | $ | -99 | ||||||
Related Party Transactions Income Statement Disclosure [Text Block] | ' | |||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
ComEd (a) | $ | 506 | $ | 795 | $ | 653 | ||||
PECO (b) | 405 | 543 | 508 | |||||||
BGE (c) | 455 | 322 | 0 | |||||||
CENG (d) | 56 | 42 | 0 | |||||||
BSC | 1 | 0 | 0 | |||||||
Total operating revenues from affiliates | $ | 1,423 | $ | 1,702 | $ | 1,161 | ||||
Purchase power and fuel from affiliates: | ||||||||||
PECO | $ | 0 | $ | 0 | $ | 1 | ||||
ComEd | 1 | 0 | 0 | |||||||
BGE | 13 | 8 | 0 | |||||||
CENG (e) | 992 | 793 | 0 | |||||||
Keystone Fuels, LLC | 144 | 119 | 68 | |||||||
Conemaugh Fuels, LLC | 98 | 101 | 69 | |||||||
Safe Harbor Water Power Corporation | 22 | 23 | 0 | |||||||
Total purchase power and fuel from affiliates | $ | 1,270 | $ | 1,044 | $ | 138 | ||||
Operating and maintenance from affiliates: | ||||||||||
ComEd (f) | $ | 2 | $ | 2 | $ | 2 | ||||
PECO (f) | 1 | 3 | 5 | |||||||
BSC (g) | 571 | 625 | 314 | |||||||
Total operating and maintenance from affiliates | $ | 574 | $ | 630 | $ | 321 | ||||
Interest expense to affiliates, net: | ||||||||||
Exelon Corporate | $ | 59 | $ | 75 | $ | 0 | ||||
Earnings (losses) in equity method investments | ||||||||||
CENG (h) | 9 | -99 | 0 | |||||||
Qualifying facilities and domestic power projects | 1 | 8 | -1 | |||||||
Total earnings (losses) in equity method investments | $ | 10 | $ | -91 | $ | -1 | ||||
Cash distribution paid to member | $ | 625 | $ | 1,626 | $ | 172 | ||||
Contribution from member | $ | 26 | $ | 48 | $ | 30 | ||||
(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(b) Generation provides electric supply to PECO under contracts executed through PECO's competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(d) Exelon has a shared services agreement with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. In addition to the SSA, Generation has a power services agency agreement with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. At the closing, as described under the Master Agreement, the PSAA will be amended and extended until the complete and permanent cessation of operation of the CENG generation plants. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(e) CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Generation has a PPA under which it is purchasing 85% of the nuclear plant output owned by CENG that is not sold to third parties under pre-existing firm and unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG. This agreement will continue to be effective and is not affected by the Master Agreement, except that if the put option under the Master Agreement is exercised, then the EDF PPA would transfer to Generation upon completion of the Put Option Agreement transaction. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(f) Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. | ||||||||||
(g) Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(h) Generation's total gain (loss) in equity method investments includes equity income (loss) and amortization of basis difference. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(i) Represents the fair value of Generation's five-year financial swap contract with ComEd, which ended in 2013. | ||||||||||
(j) Generation had a $53 million receivable from ComEd at December 31, 2012 associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | ||||||||||
(k) As of December 31, 2013 and 2012, the balance consists of interest owed to Exelon Corporation related to the senior unsecured notes. In addition, the balance at December 31, 2012, includes expense related to certain invoices Exelon Corporation processed on behalf of Generation. | ||||||||||
(l) Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15 - Asset Retirement Obligations. | ||||||||||
Related Party Transactions Balance Sheet Disclosure [Text Block] | ' | |||||||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Mark-to-market derivative assets with affiliates (current): | ||||||||||
ComEd (i) | $ | 0 | $ | 226 | ||||||
Receivables from affiliates (current): | ||||||||||
CENG (d) | $ | 3 | $ | 0 | ||||||
ComEd (a)(j) | 38 | 54 | ||||||||
PECO (b) | 38 | 56 | ||||||||
BGE (c) | 27 | 31 | ||||||||
Other | 2 | 0 | ||||||||
Total receivables from affiliates (current) | $ | 108 | $ | 141 | ||||||
Receivable from affiliate (noncurrent) | ||||||||||
Exelon Corporate | $ | 0 | $ | 1 | ||||||
Payables to affiliates (current): | ||||||||||
CENG (e) | $ | 85 | $ | 83 | ||||||
Exelon Corporate (k) | 7 | 33 | ||||||||
BSC (g) | 66 | 77 | ||||||||
Keystone Fuels, LLC | 12 | 11 | ||||||||
Conemaugh Fuels, LLC | 9 | 9 | ||||||||
Other | 2 | 0 | ||||||||
Total payables to affiliates (current) | $ | 181 | $ | 213 | ||||||
Payables to affiliates (noncurrent): | ||||||||||
ComEd (l) | $ | 2,293 | $ | 2,037 | ||||||
PECO (l) | 447 | 360 | ||||||||
Total payables to affiliates (noncurrent) | $ | 2,740 | $ | 2,397 | ||||||
(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(b) Generation provides electric supply to PECO under contracts executed through PECO's competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(c) Generation provides a portion of BGE's energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information. | ||||||||||
(d) Exelon has a shared services agreement with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. In addition to the SSA, Generation has a power services agency agreement with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. At the closing, as described under the Master Agreement, the PSAA will be amended and extended until the complete and permanent cessation of operation of the CENG generation plants. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(e) CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Generation has a PPA under which it is purchasing 85% of the nuclear plant output owned by CENG that is not sold to third parties under pre-existing firm and unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG. This agreement will continue to be effective and is not affected by the Master Agreement, except that if the put option under the Master Agreement is exercised, then the EDF PPA would transfer to Generation upon completion of the Put Option Agreement transaction. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(f) Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. | ||||||||||
(g) Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(h) Generation's total gain (loss) in equity method investments includes equity income (loss) and amortization of basis difference. For further information regarding the Investment in CENG see Note 5 – Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||
(i) Represents the fair value of Generation's five-year financial swap contract with ComEd, which ended in 2013. | ||||||||||
(j) Generation had a $53 million receivable from ComEd at December 31, 2012 associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | ||||||||||
(k) As of December 31, 2013 and 2012, the balance consists of interest owed to Exelon Corporation related to the senior unsecured notes. In addition, the balance at December 31, 2012, includes expense related to certain invoices Exelon Corporation processed on behalf of Generation. | ||||||||||
(l) Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15 - Asset Retirement Obligations. | ||||||||||
Commonwealth Edison Co [Member] | ' | |||||||||
Related Party Transaction [Line Items] | ' | |||||||||
Related Party Transactions Income Statement Disclosure [Text Block] | ' | |||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates | ||||||||||
Generation | $ | 3 | $ | 2 | $ | 2 | ||||
Purchased power from affiliate | ||||||||||
Generation (a) | $ | 512 | $ | 789 | $ | 653 | ||||
Operating and maintenance from affiliate | ||||||||||
BSC (b) | $ | 157 | $ | 163 | $ | 158 | ||||
Interest expense to affiliates, net: | ||||||||||
Exelon Corporate | $ | 0 | $ | 0 | $ | 2 | ||||
ComEd Financing III | 13 | 13 | 13 | |||||||
Total interest expense to affiliates, net | $ | 13 | $ | 13 | $ | 15 | ||||
Capitalized costs | ||||||||||
BSC (b) | $ | 69 | $ | 92 | $ | 85 | ||||
Cash dividends paid to parent | $ | 220 | $ | 105 | $ | 300 | ||||
Contribution from parent | $ | 0 | $ | 11 | $ | 11 | ||||
Related Party Transactions Balance Sheet Disclosure [Text Block] | ' | |||||||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (c) | $ | 13 | $ | 10 | ||||||
Investment in affiliate | ||||||||||
ComEd Financing III | $ | 6 | $ | 6 | ||||||
Receivable from affiliates (current): | ||||||||||
Voluntary employee beneficiary association trust | $ | 3 | $ | 0 | ||||||
BGE | 0 | 3 | ||||||||
Total receivable from affiliates (current) | $ | 3 | $ | 3 | ||||||
Receivable from affiliates (noncurrent): | ||||||||||
Generation (d) | $ | 2,293 | $ | 2,037 | ||||||
Exelon Corporate (g) | 176 | 2 | ||||||||
Total receivable from affiliates (noncurrent) | $ | 2,469 | $ | 2,039 | ||||||
Payables to affiliates (current): | ||||||||||
Generation (a)(e) | $ | 38 | $ | 54 | ||||||
BSC (b) | 30 | 35 | ||||||||
ComEd Financing III | 4 | 4 | ||||||||
Exelon Corporate | 9 | 2 | ||||||||
Other | 2 | 2 | ||||||||
Total payables to affiliates (current) | $ | 83 | $ | 97 | ||||||
Mark-to-market derivative liability with affiliate (current) | ||||||||||
Generation (f) | $ | 0 | $ | 226 | ||||||
Mark-to-market derivative liability with affiliate (noncurrent) | ||||||||||
Long-term debt to ComEd financing trust | ||||||||||
ComEd Financing III | $ | 206 | $ | 206 | ||||||
____________________ | ||||||||||
(a) ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | ||||||||||
(b) ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(c) The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd's contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets. | ||||||||||
(d) ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd's customers. | ||||||||||
(e) ComEd had a $53 million payable to Generation at December 31, 2012, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Information for additional information. | ||||||||||
(f) To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation, which ended in 2013. | ||||||||||
(g) In 2013, represents indemnification from Exelon Corporate related to the like-kind exchange transaction. | ||||||||||
PECO Energy Co [Member] | ' | |||||||||
Related Party Transaction [Line Items] | ' | |||||||||
Related Party Transactions Income Statement Disclosure [Text Block] | ' | |||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
Generation (a) | $ | 1 | $ | 3 | $ | 5 | ||||
Purchased power from affiliate | ||||||||||
Generation (b) | $ | 392 | $ | 533 | $ | 495 | ||||
Operating and maintenance from affiliates: | ||||||||||
BSC (c) | $ | 98 | $ | 107 | $ | 92 | ||||
Generation | 3 | 4 | 4 | |||||||
Total operating and maintenance from affiliates | $ | 101 | $ | 111 | $ | 96 | ||||
Interest expense to affiliates, net: | ||||||||||
PECO Trust III | $ | 6 | $ | 6 | $ | 6 | ||||
PECO Trust IV | 6 | 6 | 6 | |||||||
Total interest expense to affiliates, net | $ | 12 | $ | 12 | $ | 12 | ||||
Loss in equity method investments | ||||||||||
Capitalized costs | ||||||||||
BSC (c) | $ | 46 | $ | 54 | $ | 60 | ||||
Cash dividends paid to parent | $ | 332 | $ | 343 | $ | 348 | ||||
Contribution from parent | $ | 27 | $ | 9 | $ | 18 | ||||
________ | ||||||||||
(a) PECO provides energy to Generation for Generation's own use. | ||||||||||
(b) PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs. | ||||||||||
(c) PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(d) The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time. | ||||||||||
(e) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers. | ||||||||||
Related Party Transactions Balance Sheet Disclosure [Text Block] | ' | |||||||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 3 | $ | 2 | ||||||
Investments in affiliates: | ||||||||||
PECO Energy Capital Corporation | $ | 4 | $ | 4 | ||||||
PECO Trust IV | 4 | 4 | ||||||||
Total investments in affiliates | $ | 8 | $ | 8 | ||||||
Receivable from affiliate (noncurrent): | ||||||||||
BGE | $ | 3 | $ | 2 | ||||||
Receivable from affiliate (noncurrent): | ||||||||||
Generation (e) | $ | 447 | $ | 360 | ||||||
Mark-to-market derivative liability with affiliate (current): | ||||||||||
Payables to affiliates (current): | ||||||||||
Generation (b) | $ | 38 | $ | 56 | ||||||
BSC (c) | 17 | 18 | ||||||||
Exelon Corporate | 2 | 1 | ||||||||
PECO Trust III | 1 | 1 | ||||||||
Total payables to affiliates (current) | $ | 58 | $ | 76 | ||||||
Long-term debt to financing trusts: | ||||||||||
PECO Trust III | $ | 81 | $ | 81 | ||||||
PECO Trust IV | 103 | 103 | ||||||||
Total long-term debt to financing trusts | $ | 184 | $ | 184 | ||||||
(a) PECO provides energy to Generation for Generation's own use. | ||||||||||
(b) PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs. | ||||||||||
(c) PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | ||||||||||
(d) The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time. | ||||||||||
(e) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers. | ||||||||||
Baltimore Gas and Electric Company [Member] | ' | |||||||||
Related Party Transaction [Line Items] | ' | |||||||||
Related Party Transactions Income Statement Disclosure [Text Block] | ' | |||||||||
For the Years Ended | ||||||||||
December 31, | ||||||||||
2013 | 2012 | 2011 | ||||||||
Operating revenues from affiliates: | ||||||||||
Generation (a) | $ | 13 | $ | 10 | $ | 8 | ||||
Purchased power from affiliate | ||||||||||
Generation (b) | $ | 452 | $ | 396 | $ | 348 | ||||
Operating and maintenance from affiliates: | ||||||||||
BSC (c) | $ | 83 | $ | 106 | $ | 150 | ||||
Interest expense to affiliates, net: | ||||||||||
BGE Capital Trust II | $ | 16 | $ | 16 | $ | 16 | ||||
Capitalized costs | ||||||||||
BSC (c) | $ | 15 | $ | 21 | $ | 29 | ||||
Cash dividends paid to parent | $ | 0 | $ | 0 | $ | -85 | ||||
Contribution from parent | $ | 0 | $ | 66 | $ | 0 | ||||
Related Party Transactions Balance Sheet Disclosure [Text Block] | ' | |||||||||
December 31, | ||||||||||
2013 | 2012 | |||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 1 | $ | 0 | ||||||
Investments in affiliates: | ||||||||||
BGE Capital Trust II | $ | 8 | $ | 8 | ||||||
Payables to affiliates (current): | ||||||||||
Generation (b) | $ | 27 | $ | 31 | ||||||
BSC (c) | 20 | 12 | ||||||||
Exelon (d) | 1 | 17 | ||||||||
ComEd | 0 | 3 | ||||||||
PECO | 3 | 2 | ||||||||
BGE Capital Trust II | 4 | 4 | ||||||||
Total payables to affiliates (current) | $ | 55 | $ | 69 | ||||||
Long-term debt to BGE financing trust | ||||||||||
BGE Capital Trust II | $ | 258 | $ | 258 | ||||||
Quarterly_Data_Tables
Quarterly Data (Tables) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2013 | |||||||||||||||||||
Quarterly Financial Data [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Table [Text Block] | ' | ||||||||||||||||||
Net (Loss) Income | |||||||||||||||||||
on Common | |||||||||||||||||||
Operating Revenues | Operating Income | Stock | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 6,082 | $ | 4,690 | $ | 508 | $ | 359 | $ | -4 | $ | 200 | |||||||
30-Jun | 6,141 | 5,966 | 1,005 | 714 | 490 | 286 | |||||||||||||
30-Sep | 6,502 | 6,579 | 1,254 | 603 | 738 | 296 | |||||||||||||
31-Dec | 6,163 | 6,254 | 889 | 704 | 495 | 378 | |||||||||||||
Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share [Text Block] | ' | ||||||||||||||||||
Average Basic Shares | |||||||||||||||||||
Outstanding | Net (Loss) Income | ||||||||||||||||||
(in millions) | per Basic Share | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | 855 | 705 | $ | -0.01 | $ | 0.28 | |||||||||||||
30-Jun | 856 | 853 | 0.57 | 0.34 | |||||||||||||||
30-Sep | 857 | 854 | 0.86 | 0.35 | |||||||||||||||
31-Dec | 856 | 854 | 0.6 | 0.44 | |||||||||||||||
Average Diluted Shares | |||||||||||||||||||
Outstanding | Net (Loss) Income | ||||||||||||||||||
(in millions) | per Diluted Share | ||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | 855 | 707 | $ | -0.01 | $ | 0.28 | |||||||||||||
30-Jun | 860 | 856 | 0.57 | 0.33 | |||||||||||||||
30-Sep | 860 | 857 | 0.86 | 0.35 | |||||||||||||||
31-Dec | 860 | 857 | 0.59 | 0.44 | |||||||||||||||
Per Share Information [Text Block] | ' | ||||||||||||||||||
2013 | 2012 | ||||||||||||||||||
Fourth | Third | Second | First | Fourth | Third | Second | First | ||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||
High price | $ | 30.59 | $ | 32.42 | $ | 37.8 | $ | 34.56 | $ | 37.5 | $ | 39.82 | $ | 39.37 | $ | 43.7 | |||
Low price | 26.64 | 29.42 | 29.84 | 29.1 | 28.4 | 34.54 | 36.27 | 38.31 | |||||||||||
Close | 27.39 | 29.64 | 30.88 | 34.48 | 29.74 | 35.58 | 37.62 | 39.21 | |||||||||||
Dividends | 0.31 | 0.31 | 0.31 | 0.525 | 0.525 | 0.525 | 0.525 | 0.525 | |||||||||||
Exelon Generation Co L L C [Member] | ' | ||||||||||||||||||
Quarterly Financial Data [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Table [Text Block] | ' | ||||||||||||||||||
Net (Loss) Income | |||||||||||||||||||
on Membership | |||||||||||||||||||
Operating Revenues | Operating (Loss) Income | Interest | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 3,533 | $ | 2,743 | $ | -64 | $ | 272 | $ | -18 | $ | 168 | |||||||
30-Jun | 4,070 | 3,765 | 603 | 384 | 330 | 166 | |||||||||||||
30-Sep | 4,255 | 4,031 | 721 | 174 | 490 | 91 | |||||||||||||
31-Dec | 3,772 | 3,898 | 405 | 290 | 269 | 137 | |||||||||||||
Commonwealth Edison Co [Member] | ' | ||||||||||||||||||
Quarterly Financial Data [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Table [Text Block] | ' | ||||||||||||||||||
Operating Revenues | Operating Income | Net (Loss) Income | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 1,160 | $ | 1,388 | $ | 209 | $ | 226 | $ | -81 | $ | 87 | |||||||
30-Jun | 1,080 | 1,281 | 232 | 142 | 96 | 42 | |||||||||||||
30-Sep | 1,156 | 1,484 | 278 | 218 | 126 | 90 | |||||||||||||
31-Dec | 1,068 | 1,290 | 236 | 300 | 109 | 160 | |||||||||||||
PECO Energy Co [Member] | ' | ||||||||||||||||||
Quarterly Financial Data [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Table [Text Block] | ' | ||||||||||||||||||
Net Income | |||||||||||||||||||
on Common | |||||||||||||||||||
Operating Revenues | Operating Income | Stock | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 895 | $ | 875 | $ | 203 | $ | 177 | $ | 121 | $ | 96 | |||||||
30-Jun | 672 | 715 | 138 | 151 | 72 | 79 | |||||||||||||
30-Sep | 728 | 806 | 155 | 178 | 92 | 122 | |||||||||||||
31-Dec | 805 | 790 | 168 | 117 | 102 | 79 | |||||||||||||
Baltimore Gas and Electric Company [Member] | ' | ||||||||||||||||||
Quarterly Financial Data [Line Items] | ' | ||||||||||||||||||
Quarterly Financial Information Table [Text Block] | ' | ||||||||||||||||||
Net Income (Loss) | |||||||||||||||||||
Operating | attributable to | ||||||||||||||||||
Operating Revenues | Income (Loss) | Common Shareholders | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
Quarter ended: | |||||||||||||||||||
31-Mar | $ | 880 | $ | 697 | $ | 163 | $ | -11 | $ | 77 | $ | -33 | |||||||
30-Jun | 653 | 616 | 69 | 52 | 22 | 13 | |||||||||||||
30-Sep | 737 | 720 | 114 | 30 | 50 | -4 | |||||||||||||
31-Dec | 794 | 703 | 101 | 61 | 47 | 15 |
Significant_Accounting_Policie3
Significant Accounting Policies (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Capitalized Interest And AFUDC [Line Items] | ' | ' | ' | |||
Total interest incurred | ' | $1,003,000,000 | [1] | $783,000,000 | [1] | |
Capitalized interest | 54,000,000 | 67,000,000 | 49,000,000 | |||
Credits to AFUDC debt and equity | 35,000,000 | 25,000,000 | 25,000,000 | |||
Capitalized Software [Line Items] | ' | ' | ' | |||
Net unamortized software costs | 479,000,000 | 499,000,000 | ' | |||
Amortization of capitalized software costs | 198,000,000 | 208,000,000 | 122,000,000 | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Operating and maintenance | 7,270,000,000 | 7,961,000,000 | 5,184,000,000 | |||
Interest Expense | 1,315,000,000 | 891,000,000 | 701,000,000 | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 100.00% | ' | ' | |||
Percentage ownership of common stock | 100.00% | ' | ' | |||
Minimum voting interest needed for a controlling financial interest | 50.00% | ' | ' | |||
Third Party interest in ComEd | 15,000,000 | 106,000,000 | ' | |||
Cost Method Investment Ownership Percentage | 20.00% | ' | ' | |||
New Site Development Costs [Abstract] | ' | ' | ' | |||
Capitalized development costs | 1,900,000,000 | 1,200,000,000 | ' | |||
Development costs expensed | 4,000,000 | 4,000,000 | 2,000,000 | |||
Minimum [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Equity Method Investment Ownership Percentage | 20.00% | ' | ' | |||
Maximum [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Equity Method Investment Ownership Percentage | 50.00% | ' | ' | |||
Commonwealth Edison Company [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 99.00% | ' | ' | |||
Third Party interest in ComEd | 1,000,000 | ' | ' | |||
Exelon SHC Inc [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Minority Interest Ownership Percentage By Parent | 1.00% | ' | ' | |||
CENG [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Equity Method Investment Ownership Percentage | 50.01% | ' | ' | |||
RITELine Illinois LLC [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Minority Interest Ownership Percentage By Parent | 12.50% | ' | ' | |||
Third-party percentage interest in subsidaries | 12.50% | ' | ' | |||
Third Party interest in ComEd | 1,000,000 | ' | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Capitalized Interest And AFUDC [Line Items] | ' | ' | ' | |||
Total interest incurred | 411,000,000 | [1] | 368,000,000 | [1] | 219,000,000 | [1] |
Capitalized interest | 54,000,000 | 67,000,000 | 49,000,000 | |||
Capitalized Software [Line Items] | ' | ' | ' | |||
Net unamortized software costs | 129,000,000 | 143,000,000 | ' | |||
Amortization of capitalized software costs | 67,000,000 | 81,000,000 | 41,000,000 | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Operating and maintenance | 3,960,000,000 | 4,398,000,000 | 2,827,000,000 | |||
Interest Expense | 298,000,000 | 226,000,000 | 170,000,000 | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 100.00% | ' | ' | |||
Equity Method Investment Ownership Percentage | 50.01% | ' | ' | |||
Ownership Interest Upper Bound | 99.00% | ' | ' | |||
Ownership Interest Lower Bound | 94.00% | ' | ' | |||
Third Party interest in ComEd | 17,000,000 | 108,000,000 | ' | |||
New Site Development Costs [Abstract] | ' | ' | ' | |||
Capitalized development costs | 1,900,000,000 | 1,200,000,000 | ' | |||
Development costs expensed | 4,000,000 | 4,000,000 | 2,000,000 | |||
Nuclear Fuel [Abstract] | ' | ' | ' | |||
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | 0.001 | ' | ' | |||
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Third-party percentage interest in subsidaries | 1.00% | ' | ' | |||
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Third-party percentage interest in subsidaries | 6.00% | ' | ' | |||
Exelon Generation Co L L C [Member] | Exelon SHC Inc [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 99.00% | ' | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Capitalized Interest And AFUDC [Line Items] | ' | ' | ' | |||
Total interest incurred | 584,000,000 | [1] | 310,000,000 | [1] | 349,000,000 | [1] |
Credits to AFUDC debt and equity | 16,000,000 | 9,000,000 | 12,000,000 | |||
Capitalized Software [Line Items] | ' | ' | ' | |||
Net unamortized software costs | 101,000,000 | 105,000,000 | ' | |||
Amortization of capitalized software costs | 52,000,000 | 56,000,000 | 50,000,000 | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Electrical transmission and distribution revenue | 4,461,000,000 | 5,441,000,000 | 6,054,000,000 | |||
Operating and maintenance | 1,211,000,000 | 1,182,000,000 | 1,031,000,000 | |||
Interest Expense | 566,000,000 | 294,000,000 | 330,000,000 | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 100.00% | ' | ' | |||
Commonwealth Edison Co [Member] | RITELine Illinois LLC [Member] | ' | ' | ' | |||
Consolidation Percentages Detail Tagging [Abstract] | ' | ' | ' | |||
Percentage ownership of consolidated subsidiaries | 75.00% | ' | ' | |||
Third-party percentage interest in subsidaries | 25.00% | ' | ' | |||
Third Party interest in ComEd | 1,000,000 | ' | ' | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Capitalized Interest And AFUDC [Line Items] | ' | ' | ' | |||
Total interest incurred | 117,000,000 | [1] | 125,000,000 | [1] | 138,000,000 | [1] |
Credits to AFUDC debt and equity | 6,000,000 | 6,000,000 | 13,000,000 | |||
Capitalized Software [Line Items] | ' | ' | ' | |||
Net unamortized software costs | 71,000,000 | 63,000,000 | ' | |||
Amortization of capitalized software costs | 33,000,000 | 30,000,000 | 25,000,000 | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Operating and maintenance | 647,000,000 | 698,000,000 | 698,000,000 | |||
Interest Expense | 103,000,000 | 111,000,000 | 122,000,000 | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Capitalized Interest And AFUDC [Line Items] | ' | ' | ' | |||
Total interest incurred | 129,000,000 | [1] | 149,000,000 | [1] | 136,000,000 | [1] |
Credits to AFUDC debt and equity | 13,000,000 | 15,000,000 | 22,000,000 | |||
Capitalized Software [Line Items] | ' | ' | ' | |||
Net unamortized software costs | 155,000,000 | 157,000,000 | ' | |||
Amortization of capitalized software costs | 36,000,000 | 32,000,000 | 25,000,000 | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Operating and maintenance | 551,000,000 | 622,000,000 | 530,000,000 | |||
Interest Expense | 106,000,000 | 128,000,000 | 113,000,000 | |||
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | ' | ' | ' | |||
Error Corrections And Prior Period Adjustments Restatement [Line Items] | ' | ' | ' | |||
Electrical transmission and distribution revenue | 2,000,000 | ' | ' | |||
Operating and maintenance | 3,000,000 | ' | ' | |||
Interest Expense | $5,000,000 | ' | ' | |||
[1] | Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 b December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 b December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010. (b)B B B B B B B B Includes interest expense to affiliates. |
Basis_of_Presentation_Details
Basis of Presentation (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Depreciation and amortization | $2,153 | $1,881 | $1,347 |
Operating and maintenance | 7,270 | 7,961 | 5,184 |
Capital expenditures | 5,395 | 5,789 | 4,042 |
Income Tax Expense (Benefit) | 1,044 | 627 | 1,457 |
Interest Expense | 1,315 | 891 | 701 |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Depreciation and amortization | 856 | 768 | 570 |
Operating and maintenance | 3,960 | 4,398 | 2,827 |
Capital expenditures | 2,752 | 3,554 | 2,491 |
Income Tax Expense (Benefit) | 615 | 500 | 1,056 |
Interest Expense | 298 | 226 | 170 |
Commonwealth Edison Co [Member] | ' | ' | ' |
Depreciation and amortization | 669 | 610 | 554 |
Operating and maintenance | 1,211 | 1,182 | 1,031 |
Capital expenditures | 1,433 | 1,246 | 1,028 |
Income Tax Expense (Benefit) | 152 | 239 | 250 |
Interest Expense | 566 | 294 | 330 |
PECO Energy Co [Member] | ' | ' | ' |
Depreciation and amortization | 228 | 217 | 202 |
Operating and maintenance | 647 | 698 | 698 |
Capital expenditures | 537 | 422 | 481 |
Income Tax Expense (Benefit) | 162 | 127 | 146 |
Interest Expense | 103 | 111 | 122 |
Baltimore Gas and Electric Company [Member] | ' | ' | ' |
Depreciation and amortization | 348 | 298 | 274 |
Operating and maintenance | 551 | 622 | 530 |
Capital expenditures | 587 | 582 | 592 |
Income Tax Expense (Benefit) | 134 | 7 | 75 |
Interest Expense | 106 | 128 | 113 |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | ' | ' | ' |
Operating and maintenance | 3 | ' | ' |
Interest Expense | 5 | ' | ' |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | Regulatory Assets [Member] | ' | ' | ' |
Depreciation and amortization | 2 | ' | ' |
Income Tax Expense (Benefit) | 4 | ' | ' |
Baltimore Gas and Electric Company [Member] | Scenario Adjustment [Member] | Other Postretirement Benefits [Member] | ' | ' | ' |
Income Tax Expense (Benefit) | $4 | ' | ' |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Current Assets | $484,000,000 | $550,000,000 | ' | ||
Non Current Assets | 1,905,000,000 | 1,719,000,000 | ' | ||
Total Assets | 2,389,000,000 | [1] | 2,269,000,000 | [1],[2] | ' |
Current Liabilities | 566,000,000 | 684,000,000 | ' | ||
Non Current Liabilites | 774,000,000 | 775,000,000 | ' | ||
Total Liabilities | 1,340,000,000 | [1] | 1,459,000,000 | [1],[2] | ' |
Deferred tax assets | 0 | 58,000,000 | ' | ||
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | ' | ' | ' | ||
Number of Variable Interest Entities not consolidated by equity holders | 8 | 9 | ' | ||
Number Of Variable Interest Entities Consolidated | 4 | 5 | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Total assets | 460,000,000 | [3] | 740,000,000 | [3] | ' |
Total liabilities | 140,000,000 | [3] | 333,000,000 | [3] | ' |
Our ownership interest | 86,000,000 | [3] | 97,000,000 | [3] | ' |
Other ownership interests | 234,000,000 | [3] | 310,000,000 | [3] | ' |
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract] | ' | ' | ' | ||
Gross pledged assets | 614,000,000 | 734,000,000 | ' | ||
Pledged assets liabilities offset | 414,000,000 | 564,000,000 | ' | ||
Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Total assets | 128,000,000 | [3] | 386,000,000 | [3] | ' |
Total liabilities | 17,000,000 | [3] | 219,000,000 | [3] | ' |
Our ownership interest | 0 | [3] | 0 | [3] | ' |
Other ownership interests | 111,000,000 | [3] | 167,000,000 | [3] | ' |
Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Total assets | 332,000,000 | [3] | 354,000,000 | [3] | ' |
Total liabilities | 123,000,000 | [3] | 114,000,000 | [3] | ' |
Our ownership interest | 86,000,000 | [3] | 97,000,000 | [3] | ' |
Other ownership interests | 123,000,000 | [3] | 143,000,000 | [3] | ' |
Letter of Credit [Member] | Maximum [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 5,000,000 | ' | ||
Letter of Credit [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 5,000,000 | ' | ||
Letter of Credit [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 0 | ' | ||
Investments [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 74,000,000 | ' | ' | ||
Investments [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 7,000,000 | ' | ' | ||
Investments [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 67,000,000 | ' | ' | ||
Investments [Member] | Maximum [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 77,000,000 | ' | ||
Investments [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 0 | ' | ||
Investments [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 77,000,000 | ' | ||
Contract Intangible Asset [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 9,000,000 | ' | ' | ||
Contract Intangible Asset [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 9,000,000 | ' | ' | ||
Contract Intangible Asset [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 0 | ' | ' | ||
Contract Intangible Asset [Member] | Maximum [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 8,000,000 | ' | ||
Contract Intangible Asset [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 8,000,000 | ' | ||
Contract Intangible Asset [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 0 | ' | ||
Payment Guarantee [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 5,000,000 | ' | ' | ||
Payment Guarantee [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 0 | ' | ' | ||
Payment Guarantee [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Other ownership interests | 5,000,000 | ' | ' | ||
Payment Guarantee [Member] | Maximum [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 5,000,000 | ' | ||
Payment Guarantee [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 0 | ' | ||
Payment Guarantee [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 5,000,000 | ' | ||
Net assets pledged for Zion Station decommissioning | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | 44,000,000 | [4] | ' | ' | |
Net assets pledged for Zion Station decommissioning | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | 44,000,000 | [4] | ' | ' | |
Net assets pledged for Zion Station decommissioning | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | 0 | [4] | ' | ' | |
Net assets pledged for Zion Station decommissioning | Maximum [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 50,000,000 | [4] | ' | |
Net assets pledged for Zion Station decommissioning | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 50,000,000 | [4] | ' | |
Net assets pledged for Zion Station decommissioning | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Our maximum exposure to loss | ' | 0 | [4] | ' | |
Retail Gas Customer Supply Operation [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract] | ' | ' | ' | ||
Total assets | ' | 146,000,000 | ' | ||
Total liabilities | ' | 42,000,000 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Current Assets | 446,000,000 | 519,000,000 | ' | ||
Non Current Assets | 1,884,000,000 | 1,680,000,000 | ' | ||
Total Assets | 2,330,000,000 | 2,199,000,000 | [2] | ' | |
Current Liabilities | 481,000,000 | 612,000,000 | ' | ||
Non Current Liabilites | 562,000,000 | 470,000,000 | ' | ||
Total Liabilities | 1,043,000,000 | 1,082,000,000 | [2] | ' | |
Projects with significant economic power | 9 | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract] | ' | ' | ' | ||
Gross pledged assets | 458,000,000 | 614,000,000 | ' | ||
Pledged assets liabilities offset | 414,000,000 | 564,000,000 | ' | ||
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Minority Interest Ownership Percentage By Noncontrolling Owners | 1.00% | ' | ' | ||
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Minority Interest Ownership Percentage By Noncontrolling Owners | 6.00% | ' | ' | ||
Exelon Generation Co L L C [Member] | Retail Gas Customer Supply Operation [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Ownership percentage, consolidated variable interest entity (as a percent) | 100.00% | ' | ' | ||
Parental guarantee provided | 75,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Ownership percentage, consolidated variable interest entity (as a percent) | 100.00% | ' | ' | ||
Business Acquisitions, Megawatts Acquired | 230 | ' | ' | ||
Aggregate amount of debt with third parties | 536,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Ownership percentage, consolidated variable interest entity (as a percent) | 100.00% | ' | ' | ||
Projects with significant economic power | 10 | ' | ' | ||
Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member] | Minimum [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Minority Interest Ownership Percentage By Noncontrolling Owners | 99.00% | ' | ' | ||
Exelon Generation Co L L C [Member] | Wind Project Limited Liability Companies [Member] | Maximum [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Minority Interest Ownership Percentage By Noncontrolling Owners | 94.00% | ' | ' | ||
PECO Energy Co [Member] | ' | ' | ' | ||
Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract] | ' | ' | ' | ||
Amount of PECO's stranded costs authorized to be recovered by the PAPUC | 5,000,000,000 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Consolidated Variable Interest Entities Disclosure [Abstract] | ' | ' | ' | ||
Current Assets | 28,000,000 | 30,000,000 | ' | ||
Non Current Assets | 3,000,000 | ' | ' | ||
Total Assets | 31,000,000 | 30,000,000 | ' | ||
Current Liabilities | 74,000,000 | 71,000,000 | ' | ||
Non Current Liabilites | 195,000,000 | 265,000,000 | ' | ||
Total Liabilities | 269,000,000 | 336,000,000 | ' | ||
Deferred tax assets | 0 | ' | ' | ||
Remittance of payments received from customers for rate stabilization to BondCo. | $83,000,000 | $85,000,000 | $92,000,000 | ||
[1] | ________________ Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | ||||
[2] | Includes total assets of $146 million and total liabilities of $42 million as of December 31, 2012 related to a retail supply company that is not a consolidated VIE as of December 31, 2013. See additional information below. | ||||
[3] | These items represent amounts on the unconsolidated VIE balance sheets, not on Exelonbs or Generationbs Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. | ||||
[4] | These items represent amounts on Exelonbs and Generationbs Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $458 million and $614 million as of December 31, 2013 and December 31, 2012, respectively; offset by payables to ZionSolutions LLC of $414 million and $564 million as of December 31, 2013 and December 31, 2012, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 15 b Asset Retirement Obligations for further discussion. |
Regulatory_Matters_Details
Regulatory Matters (Details) (USD $) | 0 Months Ended | 1 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 6 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 19, 2013 | Sep. 30, 2008 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 19, 2013 | Dec. 19, 2012 | Sep. 30, 2008 | Jun. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 16, 2010 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 01, 2013 | Jul. 27, 2012 | Sep. 30, 2013 | Jun. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 16, 2010 | Dec. 31, 2006 | |||||||||
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Regulatory Asset [Member] | Electric Generation Related Regulatory Asset [Member] | Rate Stabilization Deferral [Member] | Rate Stabilization Deferral [Member] | Energy Efficiency And Demand Response Programs [Member] | Energy Efficiency And Demand Response Programs [Member] | Capitalization OfElectric Transmission Costs [Member] | Merger Integration Costs [Member] | Regulatory Assets [Member] | Regulatory Assets [Member] | Regional Transmission Expansion Plan | MGP Remediation Costs [Member] | MGP Remediation Costs [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Salem [Member] | SmartMeters | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operating And Maintenance For Regulatory Required Programs [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total operating and maintenance for regulatory required programs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Purchase Of Receivables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
POR gross receivables | ' | ' | 263,000,000 | [1] | 191,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,000,000 | [1] | 55,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 72,000,000 | [1] | 65,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 86,000,000 | [1] | 71,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
POR Allowance for uncollectible accounts | ' | ' | -30,000,000 | [2] | -21,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -16,000,000 | [2] | -9,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,000,000 | [2] | -6,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7,000,000 | [2] | -6,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
POR net receivables | ' | ' | 233,000,000 | 170,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 89,000,000 | 46,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 65,000,000 | 59,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 79,000,000 | 65,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Energy Infrastructure Modernization Act [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Additional investment to modernize system and implement smart grid technology. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual contribution to fund customer assistance programs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Contribution to a science and technology innovation trust | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Subsequent annual contributions to the trust | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Current length of state legislation enacted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Planned capital spend by a utility under state enacted legislation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 233,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement reduction | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | 168,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement reduction incremental to proposal | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 110,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement incremental reduction attributable to alternative recovery | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement incremental reduction attributable to pensions | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement incremental reduction attributable to incentives | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual revenue requirement incremental reduction attributable to other adjustments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory asset reduction due to final order | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over or Under recovered distribution service costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 125,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 377,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Under recovered distribution service costs related to one time events | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 84,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 86,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferral of AMI plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferral of additional capital investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory asset for the accelerated depreciation of non-AMI meters | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Increased revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 341,000,000 | 73,000,000 | ' | 353,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected revenue adjustment in subsequent quarter | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected revenue adjustment for prior year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,000,000 | 181,000,000 | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected revenue adjustment for current year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 160,000,000 | 80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory assets due to deferred storm costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 58,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 58,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory assets due to merger and integration-related costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Other regulatory assets due to merger and integration-related costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Revenue reduction impact by ICC issued final order | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Illinois Settlement Agreement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Overall rate relief contribution | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 747,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate relief to ComEd customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 435,000,000 | ' | ' | ' | ' | ' | ' | ' | 64,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate relief to other Illinois Utilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 308,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Contribution to IPA | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual energy savings requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Demand response peak demand reduction | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Renewable energy procurement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Distribution Rate Case [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Requested increase in electric revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 396,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 81,000,000 | ' | 101,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Adjustment to Requested increase in electric revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 343,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Recovery request for Operating and Maintenance expenses of AMI Pilot Program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Requested increase in gas revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Requested rate of return on common equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.75% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate of return on common equity electric distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.30% | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate of return on common equity gas distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Increase in electric delivery service revenue resulting from rate case settlement or order. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 143,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 225,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Increase in gas delivery service revenue resulting from rate case settlement or order. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Assets Transfer Changes | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Assets Prior Period Transfer Changes | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Severance Recovered Through Distribution Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
ComEd's proposed increase to net distribution revenue requirement related to uncollectable account expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Electric Distribution Tax Repairs Refund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 171,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Requested Rate Of Return Common Equity Electric Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83 | 10.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Requested Rate Of Return Common Equity Gas Distribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24 | 10.35 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Increase in electric delivery service revenue requirement resulting from regulatory order in rate case | ' | 274,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Estimated Refund Obligation To Customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Utility Consolidated Billing and Purchase of Receivables [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Purchased AR associated with PORCB | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 105,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Illinois Procurement Proceedings [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Near zero emissions coal-fueled generation plant | ' | ' | 166 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Illinois Legislation for Recovery of Uncollectible Accounts [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Under-collected uncollectible accounts regulatory asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
One-time operating and maintenance expense charge | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Annual Transmission Formula Rate Update [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Gross transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 488,000,000 | 450,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 158,000,000 | 156,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Transmission revenue true up | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Net transmission revenue requirement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 513,000,000 | 445,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 157,000,000 | 158,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
PJM Transmission Rate Design And Operating Agreements Abstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total construction commitments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -486,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -133,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -400,000,000 | ' | ' | ||||||||
Construction commitments due in next twelve months | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -134,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -42,000,000 | ' | ' | ||||||||
Construction commitments due in second year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -173,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -83,000,000 | ' | ' | ||||||||
Construction commitments due in third year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -177,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -95,000,000 | ' | ' | ||||||||
Construction commitments due in fourth year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -87,000,000 | ' | ' | ||||||||
Construction commitments due in five year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -93,000,000 | ' | ' | ||||||||
Smart Meter and Smart Grid Investments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Estimated number of smart meters to be installed | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Expected number of smart meters to be deployed during the first phase of Smart Meter Installment Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,600,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Revised spend on its Smart Meter Procurement and Installation Plan | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 595,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Spend on smart grid investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 120,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Smart meter spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 423,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Smart grid infrastructure spend to date | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 116,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total smart grid and smart meter investment grant amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Smart meter investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Smart grid investment grant awarded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Reimbursements received from the DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 190,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Outstanding reimbursable DOE Smart Grid Investment Grant expenditures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory assets for original smart meters purchased | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Carrying value of originally installed Smart Meters, net of reimbursements from DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
VendorRefund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Amount of reimbursements received from the DOE applied to the originally installed Smart Meters. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total Projected smart meter smart grid spend | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 480,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Current Year AMI Events Balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Depreciation Related To Original Meters | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Smart Grid Incremental Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 66,000,000 | 31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Energy Efficiency Program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Maximum civil penalty under Act 129 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Cumulative Consumption Reduction Targets | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1125852.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Consumption reduction target (as a percentage) mandated by the Energy Efficiency Program - Phase II Implemtation Order for programs directed towards the Utility's low income sector. | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.10% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Consumption reduction targets for public sector under Act 129 Phase II Implementation Order | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total approved amount under phase II of Act 129 as percent of total annual revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Renewable energy resources that will cumulatively increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.00% | 25.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Advanced metering infrastructure pilot program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Collections Under Rider Amp | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
RegulatoryAssetsUnderRiderAmp | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Alternative Energy Portfolio Standards [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Percentage Tier I alternative energy resources | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.50% | 8.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Percentage Tier II alternative energy resources | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.20% | 10.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total alternative energy credits purchased annually | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 452,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Solar tier 1 alternative energy credits purchased annually | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Natural Gas Distribution Rate Case [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Gas Distribution Tax Repairs Refund | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 54,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Authorized Return On Rate Base [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Weighted Average Debt And Equity Return | 0.07% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.08% | ' | ' | 8.70% | 8.91% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.35% | 8.43% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate Of Return On Common Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.09% | 0.10% | ' | ' | 11.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.30% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate Of Return On Common Equity in FERC Complaint | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.70% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Common Equity Component Cap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Base Rate Of Return On Common Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.80% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
ReductionInRevenuefromProposedRate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Basis Points On Rate Of Return For PJM Membership | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Assets And Liabilities Other Disclosures [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Pension and other postretirement benefit regulatory asset held at parent company | ' | ' | 3,015,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over under recovered transmission costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over under recovered electric supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | 47,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | -19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over under recovered gas supply costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,000,000 | -9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Amortization of rate stabilization deferral | ' | ' | 66,000,000 | 57,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 66,000,000 | 67,000,000 | 57,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Total cost of smart grid pilot program | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate relief for clean-up costs and received | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 5,000,000 | ||||||||
Portion of electric generation-related regulatory asset representing income taxes recoverable that do not earn a regulated rate of return | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 37,000,000 | 47,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Rate cap for BGE residential electric customers from July 1, 2006 until May 31, 2007 (as a percent) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferred expense related to electricity purchased for resale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 306,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Recovered portion of regulatory assets | ' | ' | 212,000,000 | 129,000,000 | 63,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | ' | ' | ' | ' | ' | 119,000,000 | 80,000,000 | 52,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 10,000,000 | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 84,000,000 | 53,000,000 | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Equity Ratio Minimum After Dividend Payments | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 48.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferred Merger Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over Under Gas Decoupling Regulatory Asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Over Under Electric Decoupling Regulatory Asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Maryland Electric And Natural Gas Distribution Rate Cases [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferral of total costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Deferral of storm costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | -16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
License Renewals [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Ownership interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42.59% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Minimum Purchase Obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Maximum Purchase Obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Asset [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Noncurrent regulatory assets | ' | ' | 5,910,000,000 | 6,497,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,794,000,000 | 3,673,000,000 | 1,459,000,000 | 1,382,000,000 | 159,000,000 | 70,000,000 | 5,000,000 | 17,000,000 | 285,000,000 | 191,000,000 | 56,000,000 | 68,000,000 | 219,000,000 | 256,000,000 | 0 | 12,000,000 | 12,000,000 | 28,000,000 | 102,000,000 | 90,000,000 | 212,000,000 | 232,000,000 | 0 | 2,000,000 | 0 | 48,000,000 | 0 | 176,000,000 | 49,000,000 | 0 | 0 | 3,000,000 | 2,000,000 | 3,000,000 | 6,000,000 | 30,000,000 | 40,000,000 | 154,000,000 | 225,000,000 | 148,000,000 | 126,000,000 | 0 | 9,000,000 | 39,000,000 | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 933,000,000 | 666,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 65,000,000 | 62,000,000 | 35,000,000 | 10,000,000 | 0 | 0 | 285,000,000 | 191,000,000 | 53,000,000 | 62,000,000 | 0 | 0 | 0 | 0 | 0 | 12,000,000 | 67,000,000 | 65,000,000 | 178,000,000 | 197,000,000 | 0 | 2,000,000 | 0 | 48,000,000 | 0 | 176,000,000 | 49,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | 26,000,000 | 16,000,000 | ' | ' | ' | ' | ' | 1,448,000,000 | 1,378,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 1,317,000,000 | 1,255,000,000 | 58,000,000 | 29,000,000 | 5,000,000 | 17,000,000 | 0 | 0 | 3,000,000 | 6,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 25,000,000 | 25,000,000 | 33,000,000 | 33,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 3,000,000 | 2,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 7,000,000 | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 524,000,000 | 522,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 77,000,000 | 65,000,000 | 66,000,000 | 31,000,000 | 0 | 0 | 0 | 0 | 8,000,000 | 9,000,000 | 0 | 0 | 0 | 0 | 12,000,000 | 16,000,000 | 10,000,000 | 0 | 1,000,000 | 2,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 3,000,000 | 6,000,000 | 30,000,000 | 40,000,000 | 154,000,000 | 225,000,000 | 148,000,000 | 126,000,000 | 0 | 9,000,000 | 6,000,000 | 2,000,000 | ' | ' | ' | ||||||||
Current regulatory assets | ' | ' | 760,000,000 | 764,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 221,000,000 | 304,000,000 | 10,000,000 | 14,000,000 | 5,000,000 | 3,000,000 | 0 | 0 | 178,000,000 | 18,000,000 | 12,000,000 | 14,000,000 | 0 | 0 | 12,000,000 | 77,000,000 | 16,000,000 | 29,000,000 | 1,000,000 | 0 | 40,000,000 | 58,000,000 | 2,000,000 | 3,000,000 | 11,000,000 | 0 | 0 | 17,000,000 | 18,000,000 | 53,000,000 | 43,000,000 | 1,000,000 | 1,000,000 | 3,000,000 | 3,000,000 | 13,000,000 | 16,000,000 | 71,000,000 | 67,000,000 | 73,000,000 | 56,000,000 | 5,000,000 | 2,000,000 | 31,000,000 | 23,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 329,000,000 | 388,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 2,000,000 | 5,000,000 | 5,000,000 | 3,000,000 | 0 | 0 | 178,000,000 | 18,000,000 | 9,000,000 | 11,000,000 | 0 | 0 | 0 | 0 | 12,000,000 | 25,000,000 | 1,000,000 | 0 | 33,000,000 | 51,000,000 | 2,000,000 | 3,000,000 | 0 | 0 | 226,000,000 | 17,000,000 | 18,000,000 | 52,000,000 | 14,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | 18,000,000 | 14,000,000 | ' | ' | ' | ' | ' | 17,000,000 | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 3,000,000 | 3,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 6,000,000 | 6,000,000 | 0 | 0 | 11,000,000 | 0 | 0 | 0 | 0 | 0 | 1,000,000 | 1,000,000 | 1,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 8,000,000 | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 181,000,000 | 190,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 8,000,000 | 9,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 1,000,000 | 1,000,000 | 0 | 0 | 0 | 0 | 4,000,000 | 4,000,000 | 0 | 0 | 1,000,000 | 1,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 1,000,000 | 28,000,000 | 0 | 0 | 3,000,000 | 3,000,000 | 13,000,000 | 16,000,000 | 71,000,000 | 67,000,000 | 73,000,000 | 56,000,000 | 5,000,000 | 2,000,000 | 4,000,000 | 0 | ' | ' | ' | ||||||||
Net regulatory asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 463,000,000 | 209,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Liabilities [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Regulatory Liability Current | ' | ' | 327,000,000 | 368,000,000 | ' | 0 | 0 | 99,000,000 | 97,000,000 | 53,000,000 | 131,000,000 | 20,000,000 | 20,000,000 | 0 | 0 | 6,000,000 | 78,000,000 | 54,000,000 | 8,000,000 | 3,000,000 | 2,000,000 | 38,000,000 | 40,000,000 | 16,000,000 | 7,000,000 | 8,000,000 | 8,000,000 | 4,000,000 | 0 | 1,000,000 | 0 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 170,000,000 | 170,000,000 | ' | 0 | 0 | 78,000,000 | 75,000,000 | 45,000,000 | 43,000,000 | 0 | 0 | 0 | 0 | 6,000,000 | 9,000,000 | 6,000,000 | 0 | 0 | 0 | 38,000,000 | 40,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 106,000,000 | 169,000,000 | ' | ' | 0 | 0 | 0 | 0 | 8,000,000 | 88,000,000 | 20,000,000 | 20,000,000 | 0 | 0 | 0 | 58,000,000 | 48,000,000 | 8,000,000 | 3,000,000 | 2,000,000 | 0 | 0 | 0 | 0 | 8,000,000 | 8,000,000 | 3,000,000 | 0 | 1,000,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 48,000,000 | 29,000,000 | ' | 0 | 0 | 21,000,000 | 22,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | 11,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 16,000,000 | 7,000,000 | 0 | 0 | 0 | 0 | 0 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Noncurrent regulatory liabilities | ' | ' | $4,388,000,000 | $3,981,000,000 | ' | $2,740,000,000 | $2,397,000,000 | $1,423,000,000 | $1,406,000,000 | $0 | $0 | $114,000,000 | $132,000,000 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $37,000,000 | $46,000,000 | $0 | $0 | $10,000,000 | $21,000,000 | $43,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $3,512,000,000 | $3,229,000,000 | ' | $2,293,000,000 | $2,037,000,000 | $1,219,000,000 | $1,192,000,000 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $629,000,000 | $538,000,000 | ' | ' | $447,000,000 | $360,000,000 | $0 | $0 | $0 | $0 | $114,000,000 | $132,000,000 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $37,000,000 | $46,000,000 | $0 | $0 | $10,000,000 | $21,000,000 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $204,000,000 | $214,000,000 | ' | $0 | $0 | $204,000,000 | $214,000,000 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | $0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
[1] | PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff. |
Merger_and_Acquisitions_Detail
Merger and Acquisitions (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Nov. 30, 2012 | Nov. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||
Severance [Member] | Severance [Member] | One-time Termination Benefits [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Minimum [Member] | Maximum [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Wolf Hollow Acquisition [Member] | Wolf Hollow Acquisition [Member] | Antelope Valley Solar Ranch One Acquisition [Member] | Antelope Valley Solar Ranch One Acquisition [Member] | Antelope Valley Solar Ranch One Acquisition [Member] | Antelope Valley Solar Ranch One Acquisition [Member] | Customer Relationships [Member] | Trade Names [Member] | Trade Names [Member] | Power Supply Contracts [Member] | Power Supply Contracts [Member] | Power Supply Contracts [Member] | |||||||||||||||||||||||||
MW | MW | Severance [Member] | Severance [Member] | One-time Termination Benefits [Member] | Stock Compensation Plan [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Severance [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Severance [Member] | Severance [Member] | Other Severance Charges [Member] | Other Severance Charges [Member] | Operating Revenues [Member] | MW | Common Stock [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | Constellation Energy Group Acquisition [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
MW | NumberOfHomes | MW | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
SolarPanels | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquired Finite-Lived Intangible Assets [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Acquired Finite Lived Intangible Asset Weighted Average Useful Life | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '12 years 4 months 26 days | '10 years | ' | ' | '1 year 6 months 3 days | [1] | ' | ||||||||||||
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Finite lived intangible assets gross | $576,000,000 | ' | ' | ' | ' | ' | ' | ' | $576,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $1,956,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $214,000,000 | $243,000,000 | ' | ' | $1,499,000,000 | [1] | ' | ||||||||||||
Finite lived intangible assets accumulated amortization | -159,000,000 | ' | ' | ' | ' | ' | ' | ' | -159,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,460,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -36,000,000 | -46,000,000 | ' | ' | -1,378,000,000 | [1] | ' | ||||||||||||
Finite lived intangible assets net | 417,000,000 | ' | ' | ' | ' | ' | ' | ' | 417,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 496,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 178,000,000 | 197,000,000 | ' | ' | 121,000,000 | [1] | ' | ||||||||||||
Amortization Of Contracts | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 470,000,000 | 1,101,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26,000,000 | 20,000,000 | ' | 21,000,000 | 15,000,000 | |||||||||||||
Amortization of Regulatory Asset | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 77,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 116,000,000 | 12,000,000 | ' | |||||||||||||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Future amortization expense within the next twelve months | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 118,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 24,000,000 | ' | ' | 75,000,000 | [1] | ' | ||||||||||||
Future amortization expense in year two | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | 24,000,000 | ' | ' | 18,000,000 | [1] | ' | ||||||||||||
Future amortizationExpense in year three | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | 24,000,000 | ' | ' | -31,000,000 | [1] | ' | ||||||||||||
Future amortization expense in year four | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | 24,000,000 | ' | ' | -21,000,000 | [1] | ' | ||||||||||||
Future amortization expense in year five | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | 24,000,000 | ' | ' | 11,000,000 | [1] | ' | ||||||||||||
Future amortization expense in year six and thereafter | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 233,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 87,000,000 | 77,000,000 | ' | ' | 69,000,000 | [1] | ' | ||||||||||||
Procurement Construction Contract [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Capital Expenditures | ' | ' | ' | ' | ' | ' | ' | ' | -38,000,000 | 160,000,000 | 96,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -107,000,000 | [2] | 103,000,000 | [3] | 125,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8,000,000 | 15,000,000 | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | 26,000,000 | -35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -48,000,000 | -4,000,000 | -7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Business Combination, Description [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisitions, Megawatts Acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 720 | ' | ' | 230 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Payments to Acquire Businesses and Interest in Affiliates [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination, Integration Related Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 142,000,000 | 804,000,000 | ' | ' | 106,000,000 | 340,000,000 | 16,000,000 | 41,000,000 | 9,000,000 | 17,000,000 | 6,000,000 | 182,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Payments To Acquire Businesses Net Of Cash Acquired [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Payments To Acquire Businesses Gross | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | 387,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 21,000,000 | 387,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 305,000,000 | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Total fair value of consideration recorded | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 311,000,000 | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
BusinessAcquisitionPreexistingRelationshipGainLossRecognized | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Property Plant And Equipment | ' | ' | ' | ' | 9,342,000,000 | ' | ' | ' | ' | 9,342,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,054,000,000 | ' | ' | ' | ' | 4,054,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 347,000,000 | ' | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Intangibles | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 190,000,000 | [4] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Asset Retirment Obligations | ' | ' | ' | ' | 740,000,000 | ' | ' | ' | ' | 740,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -5,000,000 | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Expected Investment In Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
DOE loan guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 646,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 646,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Amount of solar panels | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,800,000 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Amount of homes powered by electricity generated | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000 | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Purchased Power agreement time | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '25 years | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Footnotes To Business Combination Recognized Identifiable Assets Acquired Liabilities Assumed Net [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
First Solar Corporation Payable | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 87,000,000 | ' | 135,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||
Current Assets | ' | ' | ' | ' | 4,936,000,000 | ' | ' | ' | ' | 4,936,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,638,000,000 | ' | ' | ' | ' | 3,638,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Unamortized Energy Contracts | ' | ' | ' | ' | 3,218,000,000 | ' | ' | ' | ' | 3,218,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,218,000,000 | ' | ' | ' | ' | 3,218,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Other intangibles, trade name and retail relationships | ' | ' | ' | ' | 457,000,000 | ' | ' | ' | ' | 457,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 457,000,000 | ' | ' | ' | ' | 457,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Investment in affiliates | ' | ' | ' | ' | 1,942,000,000 | ' | ' | ' | ' | 1,942,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,942,000,000 | ' | ' | ' | ' | 1,942,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Other assets | ' | ' | ' | ' | 2,265,000,000 | ' | ' | ' | ' | 2,265,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,266,000,000 | ' | ' | ' | ' | 1,266,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Total assets | ' | ' | ' | ' | 22,900,000,000 | ' | ' | ' | ' | 22,900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,575,000,000 | ' | ' | ' | ' | 14,575,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedLiabilitiesAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Current liabilities | ' | ' | ' | ' | 3,408,000,000 | ' | ' | ' | ' | 3,408,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,804,000,000 | ' | ' | ' | ' | 2,804,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Unamortized energy contracts | ' | ' | ' | ' | 1,722,000,000 | ' | ' | ' | ' | 1,722,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,512,000,000 | ' | ' | ' | ' | 1,512,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -135,000,000 | [5] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Long-term debt, including current maturities | ' | ' | ' | ' | 5,632,000,000 | ' | ' | ' | ' | 5,632,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,972,000,000 | ' | ' | ' | ' | 2,972,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination Aquisition Of Less than 100 Percent Noncontrolling Interest Fair Value | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Deferred credits and other liabilities and preferred securities | ' | ' | ' | ' | 4,683,000,000 | ' | ' | ' | ' | 4,683,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,933,000,000 | ' | ' | ' | ' | 1,933,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Total liabilities,preferred securities and noncontrolling Interest | ' | ' | ' | ' | 15,535,000,000 | ' | ' | ' | ' | 15,535,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,311,000,000 | ' | ' | ' | ' | 9,311,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Total purchase price | ' | ' | ' | ' | 7,365,000,000 | ' | ' | ' | ' | 7,365,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,264,000,000 | ' | ' | ' | ' | 5,264,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 347,000,000 | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination, Bargain Purchase [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Combination, Bargain Purchase, Gain Recognized, Amount | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Impact Of Merger [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Revenues | 6,163,000,000 | 6,502,000,000 | 6,141,000,000 | 6,082,000,000 | 6,254,000,000 | 6,579,000,000 | 5,966,000,000 | 4,690,000,000 | 24,888,000,000 | 23,489,000,000 | 19,063,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 3,772,000,000 | 4,255,000,000 | 4,070,000,000 | 3,533,000,000 | 3,898,000,000 | 4,031,000,000 | 3,765,000,000 | 2,743,000,000 | 15,630,000,000 | 14,437,000,000 | 10,447,000,000 | ' | ' | ' | ' | ' | ' | ' | 1,068,000,000 | 1,156,000,000 | 1,080,000,000 | 1,160,000,000 | 1,290,000,000 | 1,484,000,000 | 1,281,000,000 | 1,388,000,000 | 4,464,000,000 | 5,443,000,000 | 6,056,000,000 | ' | ' | ' | 805,000,000 | 728,000,000 | 672,000,000 | 895,000,000 | 790,000,000 | 806,000,000 | 715,000,000 | 875,000,000 | 3,100,000,000 | 3,186,000,000 | 3,720,000,000 | ' | 794,000,000 | 737,000,000 | 653,000,000 | 880,000,000 | 703,000,000 | 720,000,000 | 616,000,000 | 697,000,000 | 3,065,000,000 | 2,735,000,000 | 3,068,000,000 | ' | ' | ' | ' | 2,091,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Revenues Impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Net Income Loss Impact | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -31,000,000 | -31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Net income | 495,000,000 | 738,000,000 | 490,000,000 | -4,000,000 | 378,000,000 | 296,000,000 | 286,000,000 | 200,000,000 | 1,729,000,000 | 1,171,000,000 | 2,499,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 269,000,000 | 490,000,000 | 330,000,000 | -18,000,000 | 137,000,000 | 91,000,000 | 166,000,000 | 168,000,000 | 1,060,000,000 | 558,000,000 | 1,771,000,000 | ' | ' | ' | ' | ' | ' | ' | 109,000,000 | 126,000,000 | 96,000,000 | -81,000,000 | 160,000,000 | 90,000,000 | 42,000,000 | 87,000,000 | 249,000,000 | 379,000,000 | 416,000,000 | ' | ' | ' | 102,000,000 | 92,000,000 | 72,000,000 | 121,000,000 | 79,000,000 | 122,000,000 | 79,000,000 | 96,000,000 | 395,000,000 | 381,000,000 | 389,000,000 | ' | 47,000,000 | 50,000,000 | 22,000,000 | 77,000,000 | 15,000,000 | -4,000,000 | 13,000,000 | -33,000,000 | 210,000,000 | 4,000,000 | 136,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Regulatory Assets Transfer Changes | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | 6,000,000 | 6,000,000 | ' | ' | ' | ' | 58,000,000 | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | ' | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Pro Forma Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Pro Forma Revenue | ' | ' | ' | ' | ' | ' | ' | ' | 26,700,000,000 | 30,712,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,013,000,000 | 19,494,000,000 | [7] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Business Acquisition, Pro Forma Net Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 2,092,000,000 | 974,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,205,000,000 | 324,000,000 | [7] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Business Acquisition, Pro Forma Earnings Per Share, Basic | ' | ' | ' | ' | ' | ' | ' | ' | $2.56 | $1.15 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | ' | ' | ' | ' | ' | ' | ' | ' | $2.55 | $1.14 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Business Acquisition, Pro Forma Nonrecurring Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 236,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 203,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Regulatory Matters [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Construction Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95,000,000 | 120,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Construction Time Frame | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '1 year | '2 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Development Of New Generation Cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 650,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Expected New Generation Mwh | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 285 | 300 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Expected New Generation Development Time Frame | ' | ' | ' | ' | ' | ' | ' | ' | '10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Divesture Wattage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,648 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Divesture Sales Days | ' | ' | ' | ' | ' | ' | ' | ' | '150 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Divesture Sales Days Extension | ' | ' | ' | ' | ' | ' | ' | ' | '30 days | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Proceeds Assets Held For Sale | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 371,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition Potential Cash Payment | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Restructuring Reserve, Period Start | ' | ' | ' | 111,000,000 | ' | ' | ' | ' | 111,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,000,000 | ' | ' | ' | ' | 33,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Severance Charges | ' | ' | ' | ' | ' | ' | ' | ' | ' | 124,000,000 | [8] | ' | 5,000,000 | 124,000,000 | ' | 18,000,000 | 19,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 80,000,000 | [8] | ' | 1,000,000 | 38,000,000 | ' | ' | 16,000,000 | 14,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | [8],[9] | ' | 2,000,000 | 2,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | [8] | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 17,000,000 | [8],[9] | ' | ' | 11,000,000 | 3,000,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Non-Merger Severance Costs | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 99,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Stock Compensation Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | [8] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | [8] | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Other Expense Charges | ' | ' | ' | ' | 7,000,000 | [8] | ' | ' | ' | ' | 7,000,000 | [8] | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | [8] | ' | ' | ' | ' | 4,000,000 | [8] | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | ' | 1,000,000 | [8],[9] | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Total Severance Benefits | ' | ' | ' | ' | 138,000,000 | [8] | ' | ' | ' | ' | 138,000,000 | [8] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 88,000,000 | [8] | ' | ' | ' | ' | 88,000,000 | [8] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | [8],[9] | ' | ' | ' | ' | 16,000,000 | [8],[9] | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | [8] | ' | ' | ' | ' | 7,000,000 | [8] | ' | ' | ' | ' | ' | ' | 19,000,000 | [8],[9] | ' | ' | ' | ' | 19,000,000 | [8],[9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Restructuring Reserve, Period Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Payments | ' | ' | ' | ' | ' | ' | ' | ' | 64,000,000 | 27,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 24,000,000 | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Restructuring Reserve, Intercompany Allocation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Restructuring Reserve, Period End | 53,000,000 | ' | ' | ' | 111,000,000 | ' | ' | ' | 53,000,000 | 111,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | 33,000,000 | ' | ' | ' | 10,000,000 | 33,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 1,000,000 | ' | ' | ' | 0 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | 11,000,000 | ' | ' | ' | 6,000,000 | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
BGE rate credit of $100 per residential customer | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,000,000 | [10] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,000,000 | [10] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Charitable contributions at $7 million per year for 10 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
State funding for offshore wind development projects | ' | ' | ' | ' | ' | ' | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Miscellaneous tax benefits | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Total | ' | ' | ' | ' | ' | ' | ' | ' | ' | $328,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $139,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Equity Interests Issued or Issuable [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
Business Acquisition, Equity Interest Issued Or Issuable, Stock Withheld | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.7 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||
[1] | Includes the fair value of BGE's power and gas supply contracts of $12 million for which an offsetting Exelon Corporate regulatory asset was also recorded. (b) Weighted average amortization period was calculated as of the date of acquisition. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | See Note 10 - Intangible Assets for additional information. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | Generation concluded that the remaining, yet-to-be paid $135 million in consideration was embedded in the amounts payable under the Engineering, Procurement, Construction (EPC) agreement for First Solar, Inc. to construct the solar facility. For accounting purposes, this aspect of the transaction is considered to be akin to a "seller financing" arrangement. As such, Generation recorded a liability of $135 million associated with the portion of the future payments to First Solar, Inc. under the EPC agreement to reflect Generation's implicit amounts due First Solar, Inc. for the remainder of the value of the net assets acquired. The $135 million payable to First Solar, Inc. will be relieved as Generation makes payments for costs incurred over the project construction period. At December 31, 2012, $87 million remained payable to First Solar, Inc. During 2013, a subsidiary of Generation paid off the remaining balance of the payable to First Solar, Inc. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. |
Investment_in_Constellation_En2
Investment in Constellation Energy Nuclear Group, LLC (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
CENG | $123 | $73 | ' |
Amortization of basis difference in CENG | -114 | -172 | ' |
Total equity investment earnings (losses) - CENG | 9 | -99 | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent) | 85.00% | ' | ' |
Purchase of nuclear output of CENG (as a percent) | 50.01% | ' | ' |
Purchase of nuclear output by EDF (as a percent) | 49.99% | ' | ' |
Impact Of Transactions Under Agreements [Abstract] | ' | ' | ' |
Increase (Decrease) in earnings | ' | 48 | 9 |
Amortization of energy contract assets and liabilities | 430 | 1,110 | ' |
Distribution From Affiliates | 115 | ' | ' |
Minimum [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Percentage of ownership interest in CENG (as a percent) | 20.00% | ' | ' |
Maximum [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Percentage of ownership interest in CENG (as a percent) | 50.00% | ' | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Schedule of Equity Method Investments [Line Items] | ' | ' | ' |
Percentage of ownership interest in CENG (as a percent) | 50.01% | ' | ' |
Basis difference in investment in CENG | 204 | ' | ' |
Related Party Transaction [Line Items] | ' | ' | ' |
Purchase of nuclear output by EDF (as a percent) | 49.99% | ' | ' |
Impact Of Transactions Under Agreements [Abstract] | ' | ' | ' |
Increase (Decrease) in earnings | 1,423 | 1,702 | 1,161 |
Amortization of energy contract assets and liabilities | 507 | 1,110 | ' |
Loan to CENG/Distribution to EDF/ Repayment to Generation | 400 | ' | ' |
Interest rate on loan to CENG | 5.25% | ' | ' |
Return on distributions (CENG) | 8.50% | ' | ' |
Distribution From Affiliates | $115 | ' | ' |
Recovered_Sheet2
Impairment of Long-Lived Assets (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | |||
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property | $1,465 | $1,492 | ' | |||
Less: unearned income | -767 | -807 | ' | |||
Net investment in long-term leases | 698 | 685 | ' | |||
Tangible Asset Impairment Charges | 43 | ' | ' | |||
CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived | 1,200 | ' | ' | |||
Utilities Operating Expense Maintenance And Operations [Abstract] | ' | ' | ' | |||
Utilities Operating Expense, Impairments | 111 | ' | ' | |||
Interest Costs Incurred [Abstract] | ' | ' | ' | |||
Interest Costs Incurred | ' | 1,003 | [1] | 783 | [1] | |
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | |||
Net investment in long-term leases | 693 | ' | ' | |||
Interest Costs Incurred [Abstract] | ' | ' | ' | |||
Interest Costs Incurred | 411 | [1] | 368 | [1] | 219 | [1] |
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Interest Costs Incurred [Abstract] | ' | ' | ' | |||
Interest Costs Incurred | 584 | [1] | 310 | [1] | 349 | [1] |
PECO Energy Co [Member] | ' | ' | ' | |||
Interest Costs Incurred [Abstract] | ' | ' | ' | |||
Interest Costs Incurred | 117 | [1] | 125 | [1] | 138 | [1] |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Interest Costs Incurred [Abstract] | ' | ' | ' | |||
Interest Costs Incurred | $129 | [1] | $149 | [1] | $136 | [1] |
[1] | Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 b December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012 b December 31, 2012. BGE activity represents the activity for the years ended December 31, 2012, 2011 and 2010. (b)B B B B B B B B Includes interest expense to affiliates. |
Goodwill_Details
Goodwill (Details) (USD $) | 6 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Jun. 30, 2013 | Dec. 31, 2013 | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill, beginning balance | $2,625 | $2,625 | |
Goodwill Impairment Loss | ' | 0 | |
Goodwill, ending balance | ' | 2,625 | |
Goodwill Gross [Member] | ' | ' | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill Impairment Loss | ' | 0 | [1] |
Goodwill, ending balance | ' | 4,608 | [1] |
Goodwill Accumulated Impairment Losses [Member] | ' | ' | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill Impairment Loss | ' | 0 | |
Goodwill, ending balance | ' | 1,983 | |
Commonwealth Edison Co [Member] | ' | ' | |
Goodwill, Impaired [Abstract] | ' | ' | |
Annual revenue requirement reduction | 14 | 168 | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill, beginning balance | 2,625 | 2,625 | |
Goodwill Impairment Loss | ' | 0 | |
Goodwill, ending balance | ' | 2,625 | |
Commonwealth Edison Co [Member] | Goodwill Gross [Member] | ' | ' | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill, beginning balance | 4,608 | 4,608 | |
Goodwill Impairment Loss | ' | 0 | [1] |
Goodwill, ending balance | ' | 4,608 | [1] |
Commonwealth Edison Co [Member] | Goodwill Accumulated Impairment Losses [Member] | ' | ' | |
Goodwill [Roll Forward] | ' | ' | |
Goodwill, beginning balance | 1,983 | 1,983 | |
Goodwill Impairment Loss | ' | 0 | |
Goodwill, ending balance | ' | $1,983 | |
[1] | Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance. |
Accounts_Receivable_Details
Accounts Receivable (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' | ||
Unbilled revenues | $1,151 | $1,094 | ||
Allowance for uncollectible accounts | -272 | -293 | ||
Accounts Receivable Additional Disclosures [Abstract] | ' | ' | ||
Gross Accounts Receivable Pledged as Collateral | 0 | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ||
Installment plan receivables | 19 | 18 | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' | ||
Unbilled revenues | 584 | [1] | 535 | [1] |
Allowance for uncollectible accounts | -57 | -84 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' | ||
Unbilled revenues | 201 | 213 | ||
Allowance for uncollectible accounts | -62 | -70 | ||
PECO Energy Co [Member] | ' | ' | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' | ||
Unbilled revenues | 161 | 164 | ||
Allowance for uncollectible accounts | -107 | -99 | ||
Accounts Notes And Loans Receivable Net Current Footnotes [Abstract] | ' | ' | ||
Current financing receivable allowance for credit losses | 8 | 7 | ||
Accounts Receivable Additional Disclosures [Abstract] | ' | ' | ||
Accounts receivable, pledged under accounts receivable agreement | ' | 210 | ||
Gross Accounts Receivable Pledged as Collateral | 0 | 289 | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | -18 | -15 | ||
PECO Energy Co [Member] | Low Risk [Member] | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | -1 | -1 | ||
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ||
Installment plan receivables | 4 | 3 | ||
PECO Energy Co [Member] | High Risk [Member] | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ||
Installment plan receivables | 13 | 11 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Accounts Notes And Loans Receivable Net Current [Abstract] | ' | ' | ||
Unbilled revenues | 205 | 182 | ||
Allowance for uncollectible accounts | ($46) | ($40) | ||
[1] | Represents unbilled portion of retail receivables estimated under Exelonbs unbilled critical accounting policy |
Property_Plant_and_Equipment_D
Property, Plant and Equipment (Details) (USD $) | 12 Months Ended | 37 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | ||||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | $61,043,000,000 | $57,370,000,000 | ' | $57,370,000,000 | |||
Less: accumulated depreciation | -13,713,000,000 | [1] | -12,184,000,000 | [1] | ' | -12,184,000,000 | [1] |
Property, plant and equipment, net | 47,330,000,000 | 45,186,000,000 | ' | 45,186,000,000 | |||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ' | ' | |||
Accumulated amortization of nuclear fuel | 2,371,000,000 | ' | ' | ' | |||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | |||
Inventory write down related to plant retirements | 9,000,000 | ' | ' | ' | |||
Electric Transmission And Distribution [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 28,123,000,000 | 26,576,000,000 | ' | 26,576,000,000 | |||
Electric Generation Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 20,420,000,000 | 19,004,000,000 | ' | 19,004,000,000 | |||
Gas Distribution Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 3,296,000,000 | 3,108,000,000 | ' | 3,108,000,000 | |||
Common Electric And Gas T And D Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,101,000,000 | 1,029,000,000 | ' | 1,029,000,000 | |||
Nuclear Fuel [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 5,196,000,000 | [2] | 4,815,000,000 | [2] | ' | 4,815,000,000 | [2] |
Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,890,000,000 | 1,926,000,000 | ' | 1,926,000,000 | |||
Other Capitalized Property Plant And Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,017,000,000 | [3] | 912,000,000 | [3] | ' | 912,000,000 | [3] |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 3.35% | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 27,145,000,000 | 25,545,000,000 | ' | 25,545,000,000 | |||
Less: accumulated depreciation | -7,034,000,000 | [4] | -6,014,000,000 | [4] | ' | -6,014,000,000 | [4] |
Property, plant and equipment, net | 20,111,000,000 | 19,531,000,000 | ' | 19,531,000,000 | |||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ' | ' | |||
Nuclear fuel - work in progress | 947,000,000 | 894,000,000 | ' | 894,000,000 | |||
Buildings under capital lease | 23,000,000 | 20,000,000 | ' | 20,000,000 | |||
Original cost basis for buildings | 59,000,000 | ' | ' | ' | |||
Accumulated depreciation for buildings | 36,000,000 | 33,000,000 | ' | 33,000,000 | |||
Accumulated amortization of nuclear fuel | ' | 2,078,000,000 | ' | 2,078,000,000 | |||
Plant Retirements Details [Abstract] | ' | ' | ' | ' | |||
Plant Retirement Cash Payments | 2,000,000 | 4,000,000 | 4,000,000 | ' | |||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | |||
Plant retirement costs incurred | ' | ' | ' | 46,000,000 | |||
Severance benefits expense related to plant retirements | 1,000,000 | ' | 4,000,000 | 14,000,000 | |||
Inventory write down related to plant retirements | 9,000,000 | 6,000,000 | ' | 18,000,000 | |||
Plant shut-down costs | 1,000,000 | 11,000,000 | 2,000,000 | 14,000,000 | |||
Exelon Generation Co L L C [Member] | Eddystone Generating Station [Member] | ' | ' | ' | ' | |||
Plant Retirements Reliability Must Run Revenue [Abstract] | ' | ' | ' | ' | |||
PlantMonthlyRevenueDuringReliabilityMustRunPeriod | 6,000,000 | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Schuylkill Station Unit One [Member] | ' | ' | ' | ' | |||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | |||
Oil/gas-fired generation unit to be retired | 166 | 166 | ' | 166 | |||
Exelon Generation Co L L C [Member] | Riverside Station Unit Six [Member] | ' | ' | ' | ' | |||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | |||
Oil/gas-fired generation unit to be retired | 115 | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Riverside Station Unit Four[Member] | ' | ' | ' | ' | |||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | |||
Oil/gas-fired generation unit to be retired | 74 | 115 | ' | 115 | |||
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 20,420,000,000 | 19,004,000,000 | ' | 19,004,000,000 | |||
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '1 year | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '52 years | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 5,196,000,000 | [5] | 4,815,000,000 | [5] | ' | 4,815,000,000 | [5] |
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '1 year | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '8 years | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,129,000,000 | 1,352,000,000 | ' | 1,352,000,000 | |||
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant And Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 400,000,000 | [6] | 374,000,000 | [6] | ' | 374,000,000 | [6] |
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant And Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '1 year | ' | ' | ' | |||
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant And Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '51 years | ' | ' | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 17,850,000,000 | 16,824,000,000 | ' | 16,824,000,000 | |||
Less: accumulated depreciation | -3,184,000,000 | -2,998,000,000 | ' | -2,998,000,000 | |||
Property, plant and equipment, net | 14,666,000,000 | 13,826,000,000 | ' | 13,826,000,000 | |||
Property Plant And Equipment Footnotes [Abstract] | ' | ' | ' | ' | |||
Buildings under capital lease | 8,000,000 | ' | ' | ' | |||
Original cost basis for buildings | 8,000,000 | ' | ' | ' | |||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | |||
Inventory write down related to plant retirements | 0 | 1,000,000 | ' | ' | |||
Commonwealth Edison Co [Member] | Electric Transmission And Distribution [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 17,334,000,000 | 16,480,000,000 | ' | 16,480,000,000 | |||
Commonwealth Edison Co [Member] | Electric Transmission And Distribution [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
Commonwealth Edison Co [Member] | Electric Transmission And Distribution [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '75 years | ' | ' | ' | |||
Commonwealth Edison Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 456,000,000 | 294,000,000 | ' | 294,000,000 | |||
Commonwealth Edison Co [Member] | Other Capitalized Property Plant And Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 60,000,000 | [7] | 50,000,000 | [7] | ' | 50,000,000 | [7] |
Property, plant and equipment, useful life | '50 years | ' | ' | ' | |||
PECO Energy Co [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 9,319,000,000 | 8,875,000,000 | ' | 8,875,000,000 | |||
Less: accumulated depreciation | -2,935,000,000 | -2,797,000,000 | ' | -2,797,000,000 | |||
Property, plant and equipment, net | 6,384,000,000 | 6,078,000,000 | ' | 6,078,000,000 | |||
PECO Energy Co [Member] | Electric Transmission And Distribution [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 6,669,000,000 | 6,355,000,000 | ' | 6,355,000,000 | |||
PECO Energy Co [Member] | Electric Transmission And Distribution [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
PECO Energy Co [Member] | Electric Transmission And Distribution [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '65 years | ' | ' | ' | |||
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,932,000,000 | 1,859,000,000 | ' | 1,859,000,000 | |||
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '70 years | ' | ' | ' | |||
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 600,000,000 | 568,000,000 | ' | 568,000,000 | |||
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '50 years | ' | ' | ' | |||
PECO Energy Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 101,000,000 | 76,000,000 | ' | 76,000,000 | |||
PECO Energy Co [Member] | Other Capitalized Property Plant And Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 17,000,000 | [8] | 17,000,000 | [8] | ' | 17,000,000 | [8] |
PECO Energy Co [Member] | Other Capitalized Property Plant And Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '50 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 8,566,000,000 | 8,093,000,000 | ' | 8,093,000,000 | |||
Less: accumulated depreciation | -2,702,000,000 | -2,595,000,000 | ' | -2,595,000,000 | |||
Property, plant and equipment, net | 5,864,000,000 | 5,498,000,000 | ' | 5,498,000,000 | |||
Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 6,100,000,000 | 5,767,000,000 | ' | 5,767,000,000 | |||
Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '90 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 1,660,000,000 | 1,548,000,000 | ' | 1,548,000,000 | |||
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '90 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 578,000,000 | 554,000,000 | ' | 554,000,000 | |||
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '5 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Property, plant and equipment, useful life | '50 years | ' | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | 196,000,000 | 193,000,000 | ' | 193,000,000 | |||
Baltimore Gas and Electric Company [Member] | Other Capitalized Property Plant And Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment [Line Items] | ' | ' | ' | ' | |||
Total property, plant and equipment | $32,000,000 | $31,000,000 | ' | $31,000,000 | |||
Property, plant and equipment, useful life | '20 years | ' | ' | ' | |||
Electric Transmission And Distribution [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 2.91% | 2.76% | 2.59% | 2.76% | |||
Electric Transmission And Distribution [Member] | PECO Energy Co [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 2.73% | 2.51% | 2.33% | 2.51% | |||
Electric Transmission And Distribution [Member] | Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 2.91% | 2.92% | 2.89% | 2.92% | |||
Electric Generation Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 3.35% | 3.15% | 3.12% | 3.15% | |||
Electric Generation Equipment [Member] | Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | ' | 3.15% | 3.12% | 3.15% | |||
Gas Distribution Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 2.06% | 2.03% | 1.73% | 2.03% | |||
Gas Distribution Equipment [Member] | PECO Energy Co [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 1.79% | 1.77% | 1.73% | 1.77% | |||
Gas Distribution Equipment [Member] | Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 2.36% | 2.33% | 2.41% | 2.33% | |||
Common Electric And Gas T And D Equipment [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 7.53% | 7.61% | 8.05% | 7.61% | |||
Common Electric And Gas T And D Equipment [Member] | PECO Energy Co [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 6.65% | 7.54% | 8.05% | 7.54% | |||
Common Electric And Gas T And D Equipment [Member] | Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Property Plant And Equipment Average Service Life Percentage By Asset Category [Line Items] | ' | ' | ' | ' | |||
Annual depreciation rate | 8.45% | 7.68% | 8.40% | 7.68% | |||
[1] | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | ||||||
[2] | ) Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | ||||||
[3] | Includes Generation's buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. Also includes ComEdbs buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. Includes land held for future use and non utility property at PECO and BGE. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities at Generation. | ||||||
[4] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | ||||||
[5] | Includes nuclear fuel that is in the fabrication and installation phase of $947 million and $894 million at December 31, 2013 and 2012, respectively. | ||||||
[6] | Includes buildings under capital lease with a net carrying value of $23 million and $20 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $59 million and total accumulated amortization was $36 million and $33 million as of December 31, 2013 and 2012, respectively. These balances also include capitalized acquisition, development and exploration costs related to oil and gas production activities. | ||||||
[7] | Includes buildings under capital lease with a net carrying value of $8 million and $0 million at December 31, 2013 and 2012, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $0 million and $0 million as of December 31, 2013 and 2012, respectively. | ||||||
[8] | Represents land held for future use and non utility property. |
Jointly_Owned_Electric_Utility2
Jointly Owned Electric Utility Plant (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | ||
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Quad Cities [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'Generation | ' | ||
Plant | $941 | [1] | $874 | [1] |
Accumulated depreciation | 226 | [1] | 187 | [1] |
Construction work in progress | 27 | 44 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 941 | [1] | 874 | [1] |
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Peach Bottom [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'Generation | ' | ||
Plant | 883 | [1] | 796 | [1] |
Accumulated depreciation | 326 | [1] | 302 | [1] |
Construction work in progress | 174 | 115 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 883 | [1] | 796 | [1] |
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Salem [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'PSEG Nuclear | [2] | ' | |
Ownership interest | 42.59% | ' | ||
Plant | 501 | [1],[2] | 494 | [1],[2] |
Accumulated depreciation | 134 | [1],[2] | 119 | [1],[2] |
Construction work in progress | 24 | [2] | 11 | [2] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Ownership interest | 42.59% | ' | ||
Plant | 501 | [1],[2] | 494 | [1],[2] |
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Salem [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Plant | 3 | 3 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 3 | 3 | ||
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Keystone [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'GenOn | [3] | ' | |
Plant | 725 | [1],[3] | 624 | [1],[3] |
Accumulated depreciation | 268 | [1],[3] | 153 | [1],[3] |
Construction work in progress | 6 | [3] | 10 | [3] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 725 | [1],[3] | 624 | [1],[3] |
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Conemaugh [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'GenOn | [3] | ' | |
Plant | 399 | [1],[3] | 322 | [1],[3] |
Accumulated depreciation | 220 | [1],[3] | 158 | [1],[3] |
Construction work in progress | 121 | [3] | 57 | [3] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 399 | [1],[3] | 322 | [1],[3] |
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Wyman [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'FP&L | ' | ||
Plant | 3 | [1] | 3 | [1] |
Accumulated depreciation | 3 | [1] | 3 | [1] |
Construction work in progress | 0 | 0 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 3 | [1] | 3 | [1] |
Exelon Generation Co L L C [Member] | Other Service [Member] | Other Locations [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | ' | [4] | ' | |
Plant | 2 | [1],[4] | 1 | [1],[4] |
Accumulated depreciation | 1 | [1],[4] | 0 | [1],[4] |
Construction work in progress | 0 | [4] | 0 | [4] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 2 | [1],[4] | 1 | [1],[4] |
PECO Energy Co [Member] | Electric Transmission [Member] | Pennsylvania [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'First Energy | [5] | ' | |
Plant | 14 | [1],[5] | 13 | [1],[5] |
Accumulated depreciation | 7 | [1],[5] | 7 | [1],[5] |
Construction work in progress | 0 | [5] | 1 | [5] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | 14 | [1],[5] | 13 | [1],[5] |
Miles of transmission voltage lines | 127 | ' | ||
Transmission line capacity | 500 | ' | ||
PECO Energy Co [Member] | Electric Transmission [Member] | Delaware And New Jersey [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Operator | 'PSEG | [6] | ' | |
Plant | 64 | [1],[6] | 65 | [1],[6] |
Accumulated depreciation | 34 | [1],[6] | 33 | [1],[6] |
Construction work in progress | 0 | [6] | 0 | [6] |
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Plant | $64 | [1],[6] | $65 | [1],[6] |
Miles of transmission voltage lines | 131 | ' | ||
Transmission line capacity | 500 | ' | ||
PECO Energy Co [Member] | Electric Transmission [Member] | PA Transmission Lines [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Ownership interest | 22.00% | ' | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Ownership interest | 22.00% | ' | ||
PECO Energy Co [Member] | Electric Transmission [Member] | Conemaugh Substation [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Ownership interest | 20.70% | ' | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Ownership interest | 20.70% | ' | ||
Transmission line capacity | 500 | ' | ||
Substation capacity | 500 | ' | ||
Baltimore Gas and Electric Company [Member] | Conemaugh Substation [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Ownership interest | 10.56% | ' | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Ownership interest | 10.56% | ' | ||
Baltimore Gas and Electric Company [Member] | Electric Transmission [Member] | Pennsylvania [Member] | ' | ' | ||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ' | ' | ||
Ownership interest | 7.00% | ' | ||
Jointly Owned Utility Plant Footnote [Abstract] | ' | ' | ||
Ownership interest | 7.00% | ' | ||
[1] | Excludes asset retirement costs. | |||
[2] | B B B B B B B B Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2013 and 2012. | |||
[3] | Generationbs ownership interest in Keystone and Conemaugh has increased as a result of Exelonbs merger with Constellation in 2012. See Note 4 b Merger and Acquisitions for additional information. | |||
[4] | Generation has a 44.24% ownership interest in Merrill Creek Reservoir located in New Jersey. | |||
[5] | PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500 kV lines including, but not limited to, the lines noted above. | |||
[6] | PECO owns a 42.55% share in 131 miles of 500 kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above. |
Intangible_Assets_Details
Intangible Assets (Details) (USD $) | 1 Months Ended | 12 Months Ended | |||
Feb. 28, 2003 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | |
Future amortization expense within the next twelve months | ' | $29,000,000 | ' | ' | |
Future amortization expense in year two | ' | 29,000,000 | ' | ' | |
Future amortizationExpense in year three | ' | 29,000,000 | ' | ' | |
Future amortization expense in year four | ' | 29,000,000 | ' | ' | |
Future amortization expense in year five | ' | 29,000,000 | ' | ' | |
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | |
Finite lived intangible assets gross | ' | 576,000,000 | ' | ' | |
Finite lived intangible assets accumulated amortization | ' | -159,000,000 | ' | ' | |
Finite lived intangible assets net | ' | 417,000,000 | ' | ' | |
Finite Lived Intangible Assets Footnotes [Abstract] | ' | ' | ' | ' | |
OtherMiscUnamortizedEnergyContracts | ' | 67,000,000 | ' | ' | |
Finite Lived Intangible Assets Amortization Expense [Abstract] | ' | ' | ' | ' | |
Intangible asset amortization expense | ' | 27,000,000 | 20,000,000 | 19,000,000 | |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Amortization Expense [Abstract] | ' | ' | ' | ' | |
Intangible asset amortization expense | ' | 20,000,000 | 13,000,000 | 12,000,000 | |
Renewable Energy Credits And Alternative Energy Credits [Abstract] | ' | ' | ' | ' | |
Current alternative or renewable energy credits | ' | 158,000,000 | 61,000,000 | ' | |
Noncurrent alternative or renewable energy credits | ' | 0 | 45,000,000 | ' | |
Exelon Generation Co L L C [Member] | Exelon Wind Acquisition [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | |
Future amortization expense within the next twelve months | ' | 14,000,000 | ' | ' | |
Future amortization expense in year two | ' | 14,000,000 | ' | ' | |
Future amortizationExpense in year three | ' | 14,000,000 | ' | ' | |
Future amortization expense in year four | ' | 14,000,000 | ' | ' | |
Future amortization expense in year five | ' | 14,000,000 | ' | ' | |
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | |
Finite lived intangible assets gross | ' | 224,000,000 | ' | ' | |
Finite lived intangible assets accumulated amortization | ' | -41,000,000 | ' | ' | |
Finite lived intangible assets net | ' | 183,000,000 | ' | ' | |
Exelon Generation Co L L C [Member] | Antelope Valley Acquisition [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | |
Future amortization expense within the next twelve months | ' | 8,000,000 | [1] | ' | ' |
Future amortization expense in year two | ' | 8,000,000 | [1] | ' | ' |
Future amortizationExpense in year three | ' | 8,000,000 | [1] | ' | ' |
Future amortization expense in year four | ' | 8,000,000 | [1] | ' | ' |
Future amortization expense in year five | ' | 8,000,000 | [1] | ' | ' |
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | |
Finite lived intangible assets gross | ' | 190,000,000 | [1] | ' | ' |
Finite lived intangible assets accumulated amortization | ' | -4,000,000 | [1] | ' | ' |
Finite lived intangible assets net | ' | 186,000,000 | [1] | ' | ' |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Footnotes [Abstract] | ' | ' | ' | ' | |
2003 City of Chicago payment made to 3rd party | -2,000,000 | ' | ' | ' | |
2003 City of Chicago payment received | 32,000,000 | ' | ' | ' | |
2003 City of Chicago payment made to city | -60,000,000 | ' | ' | ' | |
Reduction of amortization expense | -2,000,000 | ' | ' | ' | |
Finite Lived Intangible Assets Amortization Expense [Abstract] | ' | ' | ' | ' | |
Intangible asset amortization expense | ' | 7,000,000 | 7,000,000 | 7,000,000 | |
Renewable Energy Credits And Alternative Energy Credits [Abstract] | ' | ' | ' | ' | |
Current alternative or renewable energy credits | ' | 3,000,000 | 4,000,000 | ' | |
Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | |
Future amortization expense within the next twelve months | ' | 3,000,000 | [2] | ' | ' |
Future amortization expense in year two | ' | 3,000,000 | [2] | ' | ' |
Future amortizationExpense in year three | ' | 3,000,000 | [2] | ' | ' |
Future amortization expense in year four | ' | 4,000,000 | [2] | ' | ' |
Future amortization expense in year five | ' | 4,000,000 | [2] | ' | ' |
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | |
Finite lived intangible assets gross | ' | 100,000,000 | [2] | ' | ' |
Finite lived intangible assets accumulated amortization | ' | -76,000,000 | [2] | ' | ' |
Finite lived intangible assets net | ' | 24,000,000 | [2] | ' | ' |
Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member] | ' | ' | ' | ' | |
Finite Lived Intangible Assets Future Amortization Expense [Abstract] | ' | ' | ' | ' | |
Future amortization expense within the next twelve months | ' | 4,000,000 | [3] | ' | ' |
Future amortization expense in year two | ' | 4,000,000 | [3] | ' | ' |
Future amortizationExpense in year three | ' | 4,000,000 | [3] | ' | ' |
Future amortization expense in year four | ' | 3,000,000 | [3] | ' | ' |
Future amortization expense in year five | ' | 3,000,000 | [3] | ' | ' |
Finite Lived Intangible Assets Net [Abstract] | ' | ' | ' | ' | |
Finite lived intangible assets gross | ' | 62,000,000 | [3] | ' | ' |
Finite lived intangible assets accumulated amortization | ' | -38,000,000 | [3] | ' | ' |
Finite lived intangible assets net | ' | 24,000,000 | [3] | ' | ' |
PECO Energy Co [Member] | ' | ' | ' | ' | |
Renewable Energy Credits And Alternative Energy Credits [Abstract] | ' | ' | ' | ' | |
Current alternative or renewable energy credits | ' | 19,000,000 | 17,000,000 | ' | |
Noncurrent alternative or renewable energy credits | ' | $5,000,000 | $9,000,000 | ' | |
[1] | Refer to Note 4 b Merger and Acquisitions for additional information regarding Antelope Valley. | ||||
[2] | In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd's franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020. | ||||
[3] | In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago's behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation's obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in other long-term liabilities, are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement. (e) B B B B B B B B Weighted-average amortization period was calculated at the date of acquisition for acquired assets or settlement agreement. (f)B B B B B B B B Excludes $67 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities (Fair Value By Balance Sheet Grouping) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 |
In Millions, unless otherwise specified | ||
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | $648 | $648 |
Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 344 | 214 |
Long-term debt (including amounts due within one year) | 19,132 | 18,745 |
Long-term debt to financing trusts | 648 | 648 |
Spent nuclear fuel obligation | 1,021 | 1,020 |
Preferred securities of subsidiary | ' | 87 |
Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | ' | 214 |
Long-term debt (including amounts due within one year) | ' | 20,520 |
Long-term debt to financing trusts | ' | 664 |
Spent nuclear fuel obligation | ' | 763 |
Preferred securities of subsidiary | 0 | 82 |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 1 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 3 | ' |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 341 | ' |
Long-term debt (including amounts due within one year) | 18,672 | ' |
Spent nuclear fuel obligation | 790 | ' |
Preferred securities of subsidiary | 0 | ' |
Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,079 | ' |
Long-term debt to financing trusts | 631 | ' |
Exelon Generation Co L L C [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 22 | 0 |
Long-term debt (including amounts due within one year) | 7,729 | 7,483 |
Spent nuclear fuel obligation | 1,021 | 1,020 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | ' | 0 |
Long-term debt (including amounts due within one year) | ' | 7,849 |
Spent nuclear fuel obligation | ' | 763 |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 22 | ' |
Long-term debt (including amounts due within one year) | 6,586 | ' |
Spent nuclear fuel obligation | 790 | ' |
Exelon Generation Co L L C [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 1,062 | ' |
Commonwealth Edison Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 184 | ' |
Long-term debt (including amounts due within one year) | 5,675 | 5,567 |
Long-term debt to financing trusts | 206 | 206 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | ' | 6,548 |
Long-term debt to financing trusts | ' | 212 |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 184 | ' |
Long-term debt (including amounts due within one year) | 6,238 | ' |
Commonwealth Edison Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | 17 | ' |
Long-term debt to financing trusts | 202 | ' |
PECO Energy Co [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | 184 | 184 |
PECO Energy Co [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | 210 |
Long-term debt (including amounts due within one year) | 2,197 | 1,947 |
Long-term debt to financing trusts | 184 | 184 |
Preferred securities of subsidiary | 0 | 87 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | ' | 210 |
Long-term debt (including amounts due within one year) | ' | 2,264 |
Long-term debt to financing trusts | ' | 188 |
Preferred securities of subsidiary | ' | 82 |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 0 | ' |
Long-term debt (including amounts due within one year) | 2,358 | ' |
Preferred securities of subsidiary | 0 | ' |
PECO Energy Co [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | 180 | ' |
Baltimore Gas and Electric Company [Member] | Carrying Reported Amount Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 138 | ' |
Long-term debt (including amounts due within one year) | 2,011 | 2,178 |
Long-term debt to financing trusts | 258 | 258 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt (including amounts due within one year) | ' | 2,468 |
Long-term debt to financing trusts | ' | 263 |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 1 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 3 | ' |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 2 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Short-term liabilities | 135 | ' |
Long-term debt (including amounts due within one year) | 2,148 | ' |
Baltimore Gas and Electric Company [Member] | Estimate Of Fair Value Fair Value Disclosure [Member] | Fair Value Inputs Level 3 [Member] | ' | ' |
Financial Instruments Financial Liabilities Balance Sheet Groupings [Abstract] | ' | ' |
Long-term debt to financing trusts | $249 | ' |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | $1,230 | [1] | $995 | [1] |
Fixed income [Abstract] | ' | ' | ||
Proprietary trading | -328 | ' | ||
Interest rate mark-to-market Subtotal | ' | 50 | ||
Other investments | 15 | ' | ||
Deferred compensation | -114 | ' | ||
Total assets | 11,162 | 10,785 | ||
Total liabilities | -573 | ' | ||
Total net assets | 10,589 | 10,050 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 114 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 159 | 352 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 300 | 281 | ||
Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 459 | 245 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 1,776 | 1,480 | ||
Exchange traded funds | 115 | ' | ||
Commingled funds | 2,271 | 1,933 | ||
Equity securities subtotal | 4,162 | 3,413 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 882 | 1,057 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 294 | 321 | ||
Debt securities issued by foreign governments | 87 | 93 | ||
Corporate debt securities | 1,784 | 1,788 | ||
Federal agency mortgage-backed securities | 10 | 24 | ||
Commercial mortgage-backed securities (non-agency) | 40 | 45 | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ||
Mutual funds fixed income | 18 | 23 | ||
Fixed income subtotal | 3,122 | 3,362 | ||
Private equity | 5 | ' | ||
Direct lending securities | 314 | 183 | ||
Other debt obligations | 14 | 15 | ||
Nuclear decommissioning trust fund investments subtotal | 8,076 | [2] | 7,218 | [2] |
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | -5 | 30 | ||
Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 26 | 23 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 16 | 14 | ||
Commingled funds | ' | 9 | ||
Equity securities subtotal | 16 | 23 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 49 | 130 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 20 | 37 | ||
Corporate debt securities | 227 | 249 | ||
Federal agency mortgage-backed securities | ' | 49 | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ||
Fixed income subtotal | 296 | 471 | ||
Direct lending securities | 112 | 89 | ||
Other debt obligations | ' | 1 | ||
Pledged assets for Zion Station decommissioning subtotal | 451 | [3] | 607 | [3] |
Rabbi trust investments subtotal | ' | 71 | ||
Other derivatives | 1 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Net assets (liabilities) excluded from pledged assets | 7 | 7 | ||
Rabbi Trust Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 2 | 2 | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | 54 | [4] | 69 | [4] |
Rabbi trust investments subtotal | 56 | ' | ||
Deferred compensation | -53 | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 53 | ' | ||
Supplemental executive retirement plan fair value | 1 | ' | ||
Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other investments | ' | 19 | ||
Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | ' | -102 | ||
Total liabilities | ' | -735 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | ' | 102 | ||
Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | 3,960 | 4,675 | ||
Proprietary trading | 1,761 | 3,193 | ||
Effect of netting and allocation of collateral received/(paid) | -4,424 | [5] | -6,056 | [5] |
Mark-to-market subtotal | 1,297 | [6] | 1,812 | [6] |
Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | -3,020 | -3,566 | ||
Proprietary trading | -1,703 | -3,121 | ||
Effect of netting and allocation of collateral received/(paid) | 4,280 | [7] | 6,087 | [5] |
Mark-to-market subtotal | -443 | [6] | -600 | [6] |
Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 32 | 51 | ||
Interest rate mark to market | 69 | 114 | ||
Interest rate mark-to-market Subtotal | 37 | 63 | ||
Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -32 | -51 | ||
Interest rate mark to market | -48 | -84 | ||
Interest rate mark-to-market Subtotal | -16 | -33 | ||
Fair Value Inputs Level 1 [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 1,230 | [1] | ' | |
Fixed income [Abstract] | ' | ' | ||
Total liabilities | 1 | ' | ||
Total net assets | 4,534 | 3,979 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | 6 | ' | ||
Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 459 | 245 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 1,776 | 1,480 | ||
Exchange traded funds | 115 | ' | ||
Equity securities subtotal | 1,891 | 1,480 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 882 | 1,057 | ||
Fixed income subtotal | 882 | 1,057 | ||
Nuclear decommissioning trust fund investments subtotal | 3,232 | [2] | 2,782 | [2] |
Pledged assets for Zion Station decommissioning subtotal | ' | 132 | [3] | |
Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 16 | 14 | ||
Equity securities subtotal | 16 | 14 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 45 | 118 | ||
Fixed income subtotal | 45 | 118 | ||
Pledged assets for Zion Station decommissioning subtotal | 61 | [3] | ' | |
Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 2 | 2 | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | 54 | [4] | 69 | [4] |
Rabbi trust investments subtotal | 56 | 71 | ||
Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | ' | 995 | [1] | |
Fixed income [Abstract] | ' | ' | ||
Other investments | 0 | 2 | ||
Total assets | 4,533 | 4,062 | ||
Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total liabilities | ' | -83 | ||
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | 493 | ' | ||
Proprietary trading | 324 | 1,042 | ||
Effect of netting and allocation of collateral received/(paid) | -863 | [5] | -1,823 | [5] |
Mark-to-market subtotal | -46 | [6] | 80 | [6] |
Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | -540 | -1,041 | ||
Proprietary trading | -328 | -1,084 | ||
Effect of netting and allocation of collateral received/(paid) | 869 | [7] | 2,042 | [5] |
Mark-to-market subtotal | 1 | [6] | -83 | [6] |
Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 30 | ' | ||
Interest rate mark to market | 30 | ' | ||
Interest rate mark-to-market Subtotal | 0 | ' | ||
Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -31 | ' | ||
Interest rate mark to market | -31 | ' | ||
Fair Value Inputs Level 2 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total assets | 5,575 | ' | ||
Total liabilities | -269 | ' | ||
Total net assets | 5,306 | 5,415 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | -124 | -155 | ||
Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | 2,271 | 1,933 | ||
Equity securities subtotal | 2,271 | 1,933 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 294 | 321 | ||
Debt securities issued by foreign governments | 87 | 93 | ||
Corporate debt securities | 1,753 | 1,788 | ||
Federal agency mortgage-backed securities | 10 | 24 | ||
Commercial mortgage-backed securities (non-agency) | 40 | 45 | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ||
Mutual funds fixed income | 18 | 23 | ||
Fixed income subtotal | 2,209 | 2,305 | ||
Other debt obligations | 14 | 15 | ||
Nuclear decommissioning trust fund investments subtotal | 4,494 | [2] | 4,253 | [2] |
Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 26 | 23 | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | ' | 9 | ||
Equity securities subtotal | ' | 9 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 4 | 12 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 20 | 37 | ||
Corporate debt securities | 227 | 249 | ||
Federal agency mortgage-backed securities | ' | 49 | ||
Commercial mortgage-backed securities (non-agency) | ' | 6 | ||
Fixed income subtotal | 251 | 353 | ||
Other debt obligations | 1 | 1 | ||
Pledged assets for Zion Station decommissioning subtotal | 278 | [3] | 386 | [3] |
Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total assets | ' | 5,778 | ||
Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -114 | -102 | ||
Total liabilities | ' | -363 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 114 | 102 | ||
Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | 2,582 | 3,173 | ||
Proprietary trading | 1,315 | 2,078 | ||
Effect of netting and allocation of collateral received/(paid) | -3,131 | [5] | -4,175 | [5] |
Mark-to-market subtotal | 766 | [6] | 1,076 | [6] |
Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | -1,890 | -2,289 | ||
Proprietary trading | -1,256 | -1,959 | ||
Effect of netting and allocation of collateral received/(paid) | 3,007 | [7] | 4,020 | [5] |
Mark-to-market subtotal | -139 | [6] | -228 | [6] |
Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 2 | 51 | ||
Interest rate mark to market | 39 | 114 | ||
Interest rate mark-to-market Subtotal | 37 | 63 | ||
Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -1 | -51 | ||
Interest rate mark to market | -17 | -84 | ||
Interest rate mark-to-market Subtotal | -16 | -33 | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total liabilities | -305 | ' | ||
Total net assets | 749 | 656 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Collateral received from counterparties, net of collateral paid to counterparties | -26 | -33 | ||
Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Corporate debt securities | 31 | ' | ||
Private equity | 5 | ' | ||
Direct lending securities | 314 | 183 | ||
Nuclear decommissioning trust fund investments subtotal | 350 | [2] | 183 | [2] |
Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Fixed income subtotal | 0 | ' | ||
Direct lending securities | 112 | 89 | ||
Pledged assets for Zion Station decommissioning subtotal | 112 | [3] | 89 | [3] |
Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other investments | 15 | 17 | ||
Total assets | 1,054 | 945 | ||
Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total liabilities | ' | -289 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Fair value of energy swap contract current liability | 17 | 18 | ||
Fair value of energy swap contract noncurrent liability | 176 | 49 | ||
Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | 885 | 641 | ||
Proprietary trading | 122 | 73 | ||
Effect of netting and allocation of collateral received/(paid) | -430 | [5] | -58 | [5] |
Mark-to-market subtotal | 577 | [6] | 656 | [6] |
Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other derivatives | -590 | -236 | ||
Proprietary trading | -119 | -78 | ||
Effect of netting and allocation of collateral received/(paid) | 404 | [7] | 25 | [5] |
Mark-to-market subtotal | -305 | [6] | -289 | [6] |
Exelon Generation Co L L C [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 1,006 | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other investments | 15 | ' | ||
Total assets | 10,888 | ' | ||
Total net assets | 10,597 | 9,839 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 142 | 334 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 120 | 232 | ||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 459 | 245 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 1,776 | 1,480 | ||
Exchange traded funds | 115 | ' | ||
Commingled funds | 2,271 | 1,933 | ||
Equity securities subtotal | 4,162 | 3,413 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 882 | 1,057 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 294 | 321 | ||
Debt securities issued by foreign governments | 87 | 93 | ||
Corporate debt securities | 1,784 | 1,788 | ||
Federal agency mortgage-backed securities | 10 | 24 | ||
Commercial mortgage-backed securities (non-agency) | 40 | 45 | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ||
Mutual funds fixed income | 18 | 23 | ||
Fixed income subtotal | 3,122 | 3,362 | ||
Private equity | 5 | ' | ||
Direct lending securities | 314 | 183 | ||
Other debt obligations | 14 | 15 | ||
Nuclear decommissioning trust fund investments subtotal | 8,076 | [2],[3] | 7,218 | [2] |
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 26 | 23 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 16 | 14 | ||
Commingled funds | ' | 9 | ||
Equity securities subtotal | 16 | 23 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 49 | 130 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 20 | 37 | ||
Corporate debt securities | 227 | 249 | ||
Federal agency mortgage-backed securities | ' | 49 | ||
Commingled funds fixed income | ' | 6 | ||
Fixed income subtotal | 296 | 471 | ||
Direct lending securities | 112 | 89 | ||
Other debt obligations | 1 | 1 | ||
Pledged assets for Zion Station decommissioning subtotal | 451 | [3] | 607 | [3] |
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 0 | 1 | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | 13 | [8] | 13 | [4],[8] |
Rabbi trust investments subtotal | 13 | 14 | ||
Exelon Generation Co L L C [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | ' | 487 | [1] | |
Fixed income [Abstract] | ' | ' | ||
Other investments | ' | 19 | ||
Total assets | ' | 10,433 | ||
Exelon Generation Co L L C [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -29 | -28 | ||
Total liabilities | -291 | -594 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 29 | 28 | ||
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | 4,901 | ||
Other derivatives | 3,960 | ' | ||
Proprietary trading | 1,761 | 3,193 | ||
Effect of netting and allocation of collateral received/(paid) | -4,424 | [6] | -6,056 | [7] |
Mark-to-market subtotal | 1,297 | 2,038 | [6] | |
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | -3,499 | ||
Other derivatives | -2,827 | ' | ||
Proprietary trading | -1,703 | -3,121 | ||
Effect of netting and allocation of collateral received/(paid) | 4,280 | [6] | 6,087 | [5] |
Mark-to-market subtotal | -250 | -533 | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 32 | 51 | ||
Interest rate mark to market | 62 | 101 | ||
Interest rate mark-to-market Subtotal | 30 | 50 | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -32 | -51 | ||
Interest rate mark to market | -44 | -84 | ||
Interest rate mark-to-market Subtotal | -12 | -33 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total net assets | 4,267 | 3,414 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 459 | 245 | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 1,776 | 1,480 | ||
Exchange traded funds | 115 | ' | ||
Commingled funds | 0 | ' | ||
Equity securities subtotal | 1,891 | 1,480 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 882 | 1,057 | ||
Fixed income subtotal | 882 | 1,057 | ||
Nuclear decommissioning trust fund investments subtotal | 3,232 | [2] | 2,782 | [2] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Equity securities | 16 | 14 | ||
Equity securities subtotal | 16 | 14 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 45 | 118 | ||
Fixed income subtotal | 45 | 118 | ||
Pledged assets for Zion Station decommissioning subtotal | 61 | [3] | 132 | [3] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 0 | 1 | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | 13 | [8] | 13 | [4],[8] |
Rabbi trust investments subtotal | 13 | 14 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 1,006 | 487 | [1] | |
Fixed income [Abstract] | ' | ' | ||
Other investments | 0 | 2 | ||
Total assets | 4,266 | 3,497 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | 0 | ' | ||
Total liabilities | 1 | -83 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | 861 | ||
Other derivatives | 493 | ' | ||
Proprietary trading | 324 | 1,042 | ||
Effect of netting and allocation of collateral received/(paid) | -863 | [6] | -1,823 | [7] |
Mark-to-market subtotal | -46 | 80 | [6] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | -1,041 | ||
Other derivatives | -540 | ' | ||
Proprietary trading | ' | -1,084 | ||
Effect of netting and allocation of collateral received/(paid) | 869 | [6] | 2,042 | [5] |
Mark-to-market subtotal | 1 | -83 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 30 | ' | ||
Interest rate mark to market | 30 | ' | ||
Interest rate mark-to-market Subtotal | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -31 | ' | ||
Interest rate mark to market | -31 | ' | ||
Interest rate mark-to-market Subtotal | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total net assets | 5,388 | 5,476 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | 2,271 | 1,933 | ||
Equity securities subtotal | 2,271 | 1,933 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 294 | 321 | ||
Debt securities issued by foreign governments | 87 | 93 | ||
Corporate debt securities | 1,753 | 1,788 | ||
Federal agency mortgage-backed securities | 10 | 24 | ||
Commercial mortgage-backed securities (non-agency) | 40 | 45 | ||
Residential mortgage-backed securities (non-agency) | 7 | 11 | ||
Mutual funds fixed income | 18 | 23 | ||
Fixed income subtotal | 2,209 | 2,305 | ||
Other debt obligations | 14 | 15 | ||
Nuclear decommissioning trust fund investments subtotal | 4,494 | [2] | 4,253 | [2] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 26 | 23 | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | ' | 9 | ||
Equity securities subtotal | 0 | 9 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 4 | 12 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 20 | 37 | ||
Corporate debt securities | 227 | 249 | ||
Federal agency mortgage-backed securities | ' | 49 | ||
Commingled funds fixed income | ' | 6 | ||
Fixed income subtotal | 251 | 353 | ||
Other debt obligations | 1 | 1 | ||
Pledged assets for Zion Station decommissioning subtotal | 278 | [3] | 386 | [3] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other investments | 0 | ' | ||
Total assets | 5,568 | 5,765 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -29 | -28 | ||
Total liabilities | -180 | -289 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 29 | 28 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | 3,173 | ||
Other derivatives | 2,582 | ' | ||
Proprietary trading | 1,315 | 2,078 | ||
Effect of netting and allocation of collateral received/(paid) | -3,131 | [6] | -4,175 | [7] |
Mark-to-market subtotal | 766 | 1,076 | [6] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | -2,289 | ||
Other derivatives | -1,890 | ' | ||
Proprietary trading | -1,256 | -1,959 | ||
Effect of netting and allocation of collateral received/(paid) | 3,007 | [6] | 4,020 | [5] |
Mark-to-market subtotal | -139 | -228 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | 2 | 51 | ||
Interest rate mark to market | 32 | 101 | ||
Interest rate mark-to-market Subtotal | 30 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Effect of netting and allocation of collateral received/(paid) | -1 | -51 | ||
Interest rate mark to market | -13 | -84 | ||
Interest rate mark-to-market Subtotal | -12 | -33 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total net assets | 942 | 949 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Private equity | 5 | ' | ||
Direct lending securities | 314 | 183 | ||
Nuclear decommissioning trust fund investments subtotal | 350 | [2] | 183 | [2] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Fixed income subtotal | 0 | ' | ||
Direct lending securities | 112 | 89 | ||
Pledged assets for Zion Station decommissioning subtotal | 112 | [3] | 89 | [3] |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Other investments | 15 | 17 | ||
Total assets | 1,054 | 1,171 | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | 0 | ' | ||
Total liabilities | -112 | -222 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 0 | ' | ||
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | 867 | ||
Other derivatives | 885 | ' | ||
Proprietary trading | 122 | 73 | ||
Effect of netting and allocation of collateral received/(paid) | -430 | [6] | -58 | [7] |
Mark-to-market subtotal | 577 | 882 | [6] | |
Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Cash flow hedges | ' | -169 | ||
Other derivatives | -397 | ' | ||
Proprietary trading | -119 | -78 | ||
Effect of netting and allocation of collateral received/(paid) | 404 | [6] | 25 | [5] |
Mark-to-market subtotal | -112 | -222 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 17 | 18 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 176 | 49 | ||
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | -5 | -8 | ||
Rabbi trust investments subtotal | -5 | -8 | ||
Commonwealth Edison Co [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 0 | -111 | ||
Fixed income [Abstract] | ' | ' | ||
Total assets | -5 | -119 | ||
Commonwealth Edison Co [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Mark-to-market subtotal | 193 | [9] | 293 | [10],[9] |
Deferred compensation | 8 | 8 | ||
Total liabilities | 201 | 301 | ||
Total net assets | 196 | 182 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | -8 | -8 | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Mutual funds | -5 | -8 | ||
Rabbi trust investments subtotal | -5 | -8 | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 0 | -111 | ||
Fixed income [Abstract] | ' | ' | ||
Total assets | -5 | -119 | ||
Total net assets | -5 | -119 | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Mark-to-market subtotal | ' | 293 | [10],[9] | |
Deferred compensation | 8 | 8 | ||
Total liabilities | 8 | 8 | ||
Total net assets | 8 | 8 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | -8 | -8 | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total liabilities | 193 | 293 | ||
Total net assets | 193 | 293 | ||
Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Mark-to-market subtotal | 193 | [9] | ' | |
PECO Energy Co [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | ' | 9 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | 0 | 0 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 0 | 0 | ||
PECO Energy Co [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | -9 | [11] | ' | |
PECO Energy Co [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | -175 | -346 | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | ' | -9 | [11] | |
Total assets | -184 | -355 | ||
Total net assets | -167 | -337 | ||
PECO Energy Co [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -17 | -18 | ||
Total liabilities | -17 | -18 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 17 | 18 | ||
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | ' | 9 | ||
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | -9 | [11] | -9 | [11] |
PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | -175 | -346 | ||
Fixed income [Abstract] | ' | ' | ||
Total assets | -184 | -355 | ||
Total net assets | -184 | -355 | ||
PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -17 | -18 | ||
Total liabilities | -17 | -18 | ||
Total net assets | 17 | 18 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 17 | 18 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | 6 | 5 | ||
Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | 6 | ' | ||
Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 31 | 33 | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | ' | 5 | ||
Total assets | 37 | 38 | ||
Total net assets | 31 | 33 | ||
Baltimore Gas and Electric Company [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -6 | -5 | ||
Total liabilities | -6 | -5 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 6 | 5 | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | 6 | 5 | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | 6 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Cash equivalents | 31 | 33 | ||
Fixed income [Abstract] | ' | ' | ||
Rabbi trust investments subtotal | ' | 5 | ||
Total assets | 37 | 38 | ||
Total net assets | 37 | 38 | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | -6 | ' | ||
Total liabilities | -6 | -5 | ||
Total net assets | -6 | -5 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | 6 | ' | ||
Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Deferred compensation | ' | -5 | ||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract] | ' | ' | ||
Deferred compensation | ' | $5 | ||
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||
[2] | Excludes net assets (liabilities) of $(5) million and $30 million at December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||
[3] | Excludes net assets of $7 million at both December 31, 2013 and December 31, 2012, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||
[4] | The mutual funds held by the Rabbi trusts include $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013, and $53 million related to deferred compensation and $16 million related to Supplemental Executive Retirement Plan at December 31, 2012. | |||
[5] | Excludes $32 million and $28 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | |||
[6] | The Level 3 balance does not include current assets for Generation and current liabilities for ComEd of $226 million at December 31, 2012 related to the fair value of Generation's financial swap contract with ComEd. | |||
[7] | Includes collateral postings (received) from counterparties. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013. Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $219 million, $(155) million and $(33) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2012. | |||
[8] | Excludes $10 million and $8 million of the cash surrender value of life insurance investments at December 31, 2013 and December 31, 2012, respectively. | |||
[9] | The Level 3 balance includes the current liability of $226 million at December 31, 2012, related to the fair value of ComEd's financial swap contract with Generation which eliminates upon consolidation in Exelon's Consolidated Financial Statements. | |||
[10] | The Level 3 balance includes the current and noncurrent liability of $17 million and $176 million at December 31, 2013, respectively, and $18 million and $49 million at December 31, 2012, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||
[11] | Excludes $14 million and $13 million of the cash surrender value of life insurance investments at December 31, 2013 and 2012, respectively. |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities (Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation) (Details) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2011 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Other Investments [Member] | Other Investments [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | |||||||||||
Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Other Investments [Member] | Other Investments [Member] | Other Investments [Member] | Derivative [Member] | Derivative [Member] | |||||||||||||||||||||||
Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | ||||||||||||||||||||||||||||||||||||
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Beginning balance | $656 | ' | $656 | $67 | $183 | $13 | ' | $89 | $37 | ' | $367 | ' | $367 | [1] | $17 | [1] | $17 | ' | ' | ' | $949 | $867 | ' | ($13) | $183 | ' | ($37) | $89 | ' | ' | ' | $660 | $817 | $17 | ' | ' | ($293) | ($800) | ||||||
Total realized / unrealized gains (losses) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Included in income | -42 | ' | ' | 59 | 2 | ' | 0 | 0 | ' | ' | -44 | [2] | ' | ' | 59 | [1],[3] | ' | ' | ' | ' | -49 | -66 | 2 | ' | ' | 0 | ' | ' | ' | ' | ' | -51 | [2] | -66 | [4] | ' | ' | ' | ' | ' | ||||
Included in other comprehensive income | 2 | ' | ' | 0 | 0 | ' | ' | 0 | ' | ' | ' | ' | ' | 0 | [1] | 2 | ' | ' | ' | 217 | 475 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 219 | 475 | [5] | 2 | ' | ' | ' | ' | ||||||
Included in payable for Zion Station decommissioning | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Included in regulatory assets | -118 | ' | ' | 40 | 8 | ' | 1 | 0 | ' | ' | -126 | [6] | ' | ' | 39 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100 | [7],[8] | 507 | [10],[9] | ||||
Included in noncurrent payables to affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | -8 | ' | ' | 1 | -8 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Change in collateral | 7 | -32 | ' | ' | 0 | ' | ' | 0 | ' | ' | 7 | ' | ' | -32 | [1] | ' | ' | ' | ' | -7 | 32 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -7 | 32 | ' | ' | ' | ' | ' | |||||||
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Purchases | 297 | ' | ' | 583 | 203 | ' | 169 | 62 | ' | 63 | 28 | ' | ' | 334 | [1],[11] | 4 | 17 | ' | ' | 297 | 583 | ' | ' | 203 | 169 | ' | 62 | 63 | ' | ' | 28 | 334 | [11] | ' | 17 | 4 | ' | ' | ||||||
Sales | -86 | ' | ' | -11 | -28 | ' | ' | -39 | ' | -11 | -11 | ' | ' | ' | -8 | ' | ' | ' | 86 | 11 | -28 | ' | ' | ' | ' | 39 | 11 | -11 | ' | ' | ' | -8 | ' | ' | ' | ' | ||||||||
Settlements | -18 | ' | ' | ' | -18 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18 | ' | ' | ' | 18 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Transfers into Level 3 - (Asset) / Liability | ' | -39 | 87 | ' | ' | ' | ' | ' | ' | ' | ' | -39 | [1] | 86 | ' | 1 | ' | ' | -39 | -87 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -39 | -86 | ' | 1 | ' | ' | ' | ' | |||||||
Transfers out of Level 3 - (Asset) / Liability | -36 | ' | ' | -89 | 0 | ' | ' | 0 | ' | ' | -35 | ' | ' | -89 | [1] | -1 | ' | ' | ' | -36 | -89 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -35 | -89 | -1 | ' | ' | ' | ' | |||||||
Ending balance | 749 | 656 | ' | 656 | 350 | 13 | 183 | 112 | 37 | 89 | 272 | 367 | ' | 367 | [1] | 15 | 17 | ' | ' | 942 | 949 | ' | ' | 350 | 183 | -37 | 112 | 89 | ' | ' | 465 | 660 | ' | 17 | 15 | -193 | -293 | |||||||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 168 | ' | ' | 214 | 1 | ' | 0 | 0 | ' | ' | 167 | ' | ' | 214 | [1] | ' | ' | ' | ' | 157 | -165 | 1 | ' | ' | 0 | ' | ' | ' | ' | ' | 156 | -165 | ' | ' | ' | ' | ' | |||||||
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts | -211 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Fair value of Constellation fair value assets acquired | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 310 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Acquisition of marketable securities | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $14 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
[1] | Excludes $98 million of increases in fair value and $566 million of realized losses due to settlements for the year ended December 31, 2012 of Generationbs financial swap contract with ComEd, which eliminates upon consolidation in Exelonbs Consolidated Financial Statements. This position was de-designated as a cash flow hedge prior to the merger date. | |||||||||||||||||||||||||||||||||||||||||||
[2] | Includes a reduction for the reclassification of $211 million of realized gains due to settlement of derivative contracts recorded in results of operations for the year ended December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||
[3] | Includes a reduction for the reclassification of $155 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | |||||||||||||||||||||||||||||||||||||||||||
[4] | Includes a reduction for the reclassification of $99 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the year ended December 31, 2012. | |||||||||||||||||||||||||||||||||||||||||||
[5] | Includes $98 million of increases in fair value and $566 million of realized losses reclassified from OCI due to settlements associated with Generation's financial swap contract with ComEd for the year ended December 31, 2012. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||
[6] | Excludes decreases in fair value of $11 million of and realized losses reclassified due to settlements of $215 million associated with Generationbs financial swap contract with ComEd for the year ended December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||
[7] | Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||
[8] | Includes $126 million of increases in the fair value and realized losses due to settlements of $7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||
[9] | Includes $98 million of increases in fair value and $566 million of realized gains due to settlements associated with ComEd's financial swap contract with Generation for the year ended December 31, 2012. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements. | |||||||||||||||||||||||||||||||||||||||||||
[10] | Includes $34 million of decreases in the fair value and realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2012 | |||||||||||||||||||||||||||||||||||||||||||
[11] | Includes $310 million of fair value from contracts and $14 million of other investments acquired as a result of the merger. |
Fair_Value_of_Financial_Assets5
Fair Value of Financial Assets and Liabilities (Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings) (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Operating Revenue [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | ($152) | $54 |
Change in the unrealized gains (losses) relating to assets and liabilities held | 40 | 230 |
Purchased Fuel and Electric [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | 108 | 5 |
Change in the unrealized gains (losses) relating to assets and liabilities held | 127 | -16 |
Other, net [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | 2 | ' |
Change in the unrealized gains (losses) relating to assets and liabilities held | 1 | ' |
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | -158 | 61 |
Change in the unrealized gains (losses) relating to assets and liabilities held | 30 | 181 |
Exelon Generation Co L L C [Member] | Purchased Fuel and Electric [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | 107 | 5 |
Change in the unrealized gains (losses) relating to assets and liabilities held | 126 | -16 |
Exelon Generation Co L L C [Member] | Other, net [Member] | ' | ' |
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items] | ' | ' |
Total gains (losses) included in income | 2 | ' |
Change in the unrealized gains (losses) relating to assets and liabilities held | $1 | ' |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities (Fair Value Inputs Assets Quantitative Information) (Details) (USD $) | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 |
Derivative [Member] | Derivative [Member] | Derivative [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | |
Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | Fair Value Inputs Level 3 [Member] | |
Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Discounted Cash Flow [Member] | Option Model Valuation Technique [Member] | Option Model Valuation Technique [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Option Model Valuation Technique [Member] | Option Model Valuation Technique [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | Derivative [Member] | ||
Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Option Model Valuation Technique [Member] | Option Model Valuation Technique [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | Option Model Valuation Technique [Member] | Option Model Valuation Technique [Member] | Minimum [Member] | Maximum [Member] | Maximum [Member] | Discounted Cash Flow [Member] | Discounted Cash Flow [Member] | ||||||||||||
Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | Minimum [Member] | Maximum [Member] | |||||||||||||||||||||
Derivatives Fair Value [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | $226,000,000 | ' | ' | ' | ' | $473,000,000 | ' | ' | ' | ' | ' | ' | ' | $488,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | ' | ' | ' | ' | ' | ' | ' | ' | -6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | -67,000,000 | ' | ' | -193,000,000 | ' | ' | ' |
Fair Value Inputs [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Forward power price assets | ' | ' | ' | 14 | 79 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8 | 176 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Forward power price liabilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15 | 106 | ' | ' | ' | ' | ' | ' | ' | ' | 10 | 176 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Forward gas price assets | ' | ' | ' | $3.26 | $6.27 | ' | ' | ' | ' | ' | ' | ' | ' | ' | $2.98 | $16.63 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Volatility percentage | ' | ' | ' | ' | ' | ' | 28.00% | 132.00% | ' | ' | ' | 16.00% | 48.00% | ' | ' | ' | 15.00% | 142.00% | ' | ' | ' | 14.00% | 19.00% | ' | ' | ' | ' | ' | ' | ' |
Marketability Reserve | ' | 8.00% | 9.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.50% | 8.30% | ' | 8.00% | 3.50% | ' |
Forward heat rate | ' | 8.00% | 9.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.00% | 9.00% |
Renewable factor | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 81.00% | 123.00% | ' | ' | 84.00% | 128.00% |
Derivative_Financial_Instrumen2
Derivative Financial Instruments (Commodity Price Risk) (Details) | 12 Months Ended | ||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
GWh | GWh | GWh | |
Exelon Generation Co L L C [Member] | ' | ' | ' |
Proprietary Trading Volumes [Abstract] | ' | ' | ' |
Proprietary trading activities volume | 8,762 | 12,958 | 5,742 |
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' | ' |
Expected generation hedged in next twelve months | 92.00% | ' | ' |
Expected generation hedged in year two | 62.00% | ' | ' |
Expected generation hedged in year three | 30.00% | ' | ' |
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' |
Percent Of Expected Generation Being Hedged [Abstract] | ' | ' | ' |
Expected generation hedged in next twelve months | 95.00% | ' | ' |
Expected generation hedged in year two | 65.00% | ' | ' |
Expected generation hedged in year three | 33.00% | ' | ' |
PECO Energy Co [Member] | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | 30.00% | ' | ' |
Baltimore Gas and Electric Company [Member] | Minimum [Member] | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | 10.00% | ' | ' |
Baltimore Gas and Electric Company [Member] | Maximum [Member] | ' | ' | ' |
Percent Of Gas Purchases Being Hedged [Abstract] | ' | ' | ' |
Estimated percentage of natural gas purchases hedged | 20.00% | ' | ' |
Derivative_Financial_Instrumen3
Derivative Financial Instruments (Interest Rate Risk) (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Cost Of Capital Strategies [Abstract] | ' | ' | ' | ||
Hypothetical increase in interest rates associated with variable-rate debt | 50.00% | ' | ' | ||
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound | $5,000,000 | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | ' | 4,000,000 | ' | ||
Mark-to-market derivative assets (noncurrent assets) | ' | 59,000,000 | ' | ||
Total mark-to-market derivative assets | ' | 63,000,000 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | ' | -2,000,000 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | -31,000,000 | ' | ||
Total mark-to-market derivative liabilities | ' | -33,000,000 | ' | ||
Total mark-to-market derivative net assets (liabilities) | ' | 30,000,000 | ' | ||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ||
Gain on swaps/borrowings | 11,000,000 | ' | ' | ||
Loss on swaps/borrowings | ' | -3,000,000 | -1,000,000 | ||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | ||
Fair value of interest rate swaps from merger acquiree | 150,000,000 | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Mark-to-market derivative liabilities | 300,000,000 | 281,000,000 | ' | ||
Unrealized Gain (Loss) on Derivatives | 445,000,000 | 604,000,000 | -291,000,000 | ||
Derivative, Notional Amount | 2,651,000,000 | 2,498,000,000 | ' | ||
Designated as Hedging Instrument [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives | 190,000,000 | ' | ' | ||
Notional amounts on forward starting interest rate swaps | 1,000,000 | ' | ' | ||
Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -1,000,000 | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Deferred Gain on Derivatives | 26,000,000 | ' | ' | ||
Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Unrealized Gain (Loss) on Derivatives | 26,000,000 | 49,000,000 | ' | ||
Derivative, Notional Amount | 1,275,000,000 | 650,000,000 | ' | ||
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Increase In Notional Amount Of Derivative Instruments | 625,000,000 | ' | ' | ||
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | ||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ||
Loss on swaps/borrowings | -24,000,000 | -9,000,000 | ' | ||
Derivative [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | -1,000,000 | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 38,000,000 | ' | ' | ||
Total mark-to-market derivative assets | 37,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -1,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -15,000,000 | ' | ' | ||
Total mark-to-market derivative liabilities | -16,000,000 | ' | ' | ||
Total mark-to-market derivative net assets (liabilities) | 21,000,000 | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Derivative, Notional Amount | 1,425,000,000 | ' | ' | ||
Derivative [Member] | Interest Expense [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | ||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ||
Gain on swaps/borrowings | ' | ' | 1,000,000 | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Cost Of Capital Strategies [Abstract] | ' | ' | ' | ||
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound | 5,000,000 | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | ' | 4,000,000 | ' | ||
Mark-to-market derivative assets (noncurrent assets) | ' | 46,000,000 | ' | ||
Total mark-to-market derivative assets | ' | 50,000,000 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | ' | -2,000,000 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | -31,000,000 | ' | ||
Total mark-to-market derivative liabilities | ' | -33,000,000 | ' | ||
Total mark-to-market derivative net assets (liabilities) | ' | 17,000,000 | ' | ||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ||
Loss on swaps/borrowings | ' | -6,000,000 | [1] | ' | |
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
DOE loan guarantee | 646,000,000 | ' | ' | ||
DOE interest rate swap | 485,000,000 | ' | ' | ||
Mark-to-market derivative liabilities | 120,000,000 | 232,000,000 | ' | ||
Unrealized Gain (Loss) on Derivatives | 448,000,000 | 611,000,000 | -291,000,000 | ||
Exelon Generation Co L L C [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | -1,000,000 | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 31,000,000 | ' | ' | ||
Total mark-to-market derivative assets | 30,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -1,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -11,000,000 | ' | ' | ||
Total mark-to-market derivative liabilities | -12,000,000 | ' | ' | ||
Total mark-to-market derivative net assets (liabilities) | 18,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Antelope Valle [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Percentage of interest rate swap in relation to DOE guarantee | 75 | ' | ' | ||
Notional amount of interest rate swap DOE advance | 350,000,000 | ' | ' | ||
Percent of DOE loan advance offset | 75.00% | ' | ' | ||
Notional amount of remaining cash flow hedges | 135,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | ' | 38,000,000 | ' | ||
Total mark-to-market derivative assets | ' | 38,000,000 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | ' | -1,000,000 | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | -31,000,000 | ' | ||
Total mark-to-market derivative liabilities | ' | -32,000,000 | ' | ||
Total mark-to-market derivative net assets (liabilities) | ' | 6,000,000 | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | ||
Notional amount of interest rate swaps acquired from merger | 28,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Fair Value Hedge Derivatives | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Derivative, Notional Amount | 195,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 26,000,000 | ' | ' | ||
Total mark-to-market derivative assets | 26,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -1,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -10,000,000 | ' | ' | ||
Total mark-to-market derivative liabilities | -11,000,000 | ' | ' | ||
Total mark-to-market derivative net assets (liabilities) | 15,000,000 | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Derivative, Notional Amount | 144,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | ||
Interest rate swaps previously held by acquiree | 550,000,000 | 550,000,000 | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Unrealized Gain (Loss) on Derivatives | 23,000,000 | 38,000,000 | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | Cash Flow Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Derivative, Notional Amount | 470,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Notional amounts on forward starting interest rate swaps | 27,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Fair Value Hedges [Abstract] | ' | ' | ' | ||
Fair value assets | 2,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Swap | Fair Value Hedging [Member] | ' | ' | ' | ||
Derivative, Gain (Loss) on Derivative, Net [Abstract] | ' | ' | ' | ||
Loss on swaps/borrowings | -15,000,000 | [1] | -6,000,000 | [1] | ' |
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Expense [Member] | Antelope Valle [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member] | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Derivative, Notional Amount | 485,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | ' | 3,000,000 | ' | ||
Mark-to-market derivative assets (noncurrent assets) | ' | 8,000,000 | ' | ||
Total mark-to-market derivative assets | ' | 11,000,000 | ' | ||
Mark-to-market derivative liabilities (current liabilities) | ' | -1,000,000 | ' | ||
Total mark-to-market derivative liabilities | ' | -1,000,000 | ' | ||
Total mark-to-market derivative net assets (liabilities) | ' | 10,000,000 | ' | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | 3,000,000 | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 3,000,000 | ' | ' | ||
Total mark-to-market derivative assets | 6,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -1,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -1,000,000 | ' | ' | ||
Total mark-to-market derivative liabilities | -2,000,000 | ' | ' | ||
Total mark-to-market derivative net assets (liabilities) | 4,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Swap | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Unrealized Gain (Loss) on Derivatives | 2,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | Antelope Valle [Member] | Interest Rate Swap | ' | ' | ' | ||
Interest Rate Risk - Cash Flow Hedges [Abstract] | ' | ' | ' | ||
Mark-to-market derivative liabilities | 10,000,000 | ' | ' | ||
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | ' | 20,000,000 | [2] | ' | |
Mark-to-market derivative assets (noncurrent assets) | ' | 32,000,000 | [2] | ' | |
Total mark-to-market derivative assets | ' | 52,000,000 | [2] | ' | |
Mark-to-market derivative liabilities (current liabilities) | ' | -19,000,000 | [2] | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | -32,000,000 | [2] | ' | |
Total mark-to-market derivative liabilities | ' | -51,000,000 | [2] | ' | |
Total mark-to-market derivative net assets (liabilities) | ' | 1,000,000 | [2] | ' | |
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | 15,000,000 | [3] | ' | ' | |
Mark-to-market derivative assets (noncurrent assets) | 15,000,000 | [3] | ' | ' | |
Total mark-to-market derivative assets | 30,000,000 | [3] | ' | ' | |
Mark-to-market derivative liabilities (current liabilities) | -18,000,000 | [3] | ' | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | -13,000,000 | [3] | ' | ' | |
Total mark-to-market derivative liabilities | -31,000,000 | [3] | ' | ' | |
Total mark-to-market derivative net assets (liabilities) | -1,000,000 | [3] | ' | ' | |
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | ' | -19,000,000 | [4] | ' | |
Mark-to-market derivative assets (noncurrent assets) | ' | -32,000,000 | [4] | ' | |
Total mark-to-market derivative assets | ' | -51,000,000 | [4] | ' | |
Mark-to-market derivative liabilities (current liabilities) | ' | 19,000,000 | [4] | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | ' | 32,000,000 | [4] | ' | |
Total mark-to-market derivative liabilities | ' | 51,000,000 | [4] | ' | |
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (current assets) | -19,000,000 | [5] | ' | ' | |
Mark-to-market derivative assets (noncurrent assets) | -13,000,000 | [5] | ' | ' | |
Total mark-to-market derivative assets | -32,000,000 | [5] | ' | ' | |
Mark-to-market derivative liabilities (current liabilities) | 19,000,000 | [5] | ' | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | 13,000,000 | [5] | ' | ' | |
Total mark-to-market derivative liabilities | 32,000,000 | [5] | ' | ' | |
Other Segments [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | ' | 13,000,000 | ' | ||
Total mark-to-market derivative assets | ' | 13,000,000 | ' | ||
Total mark-to-market derivative net assets (liabilities) | ' | 13,000,000 | ' | ||
Other Segments [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | ' | ' | ' | ||
Derivative Interest Rate Risk [Abstract] | ' | ' | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 7,000,000 | ' | ' | ||
Total mark-to-market derivative assets | 7,000,000 | ' | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -4,000,000 | ' | ' | ||
Total mark-to-market derivative liabilities | -4,000,000 | ' | ' | ||
Total mark-to-market derivative net assets (liabilities) | $3,000,000 | ' | ' | ||
[1] | For the years ended December 31, 2013 and 2012, the loss on Generation swaps included $16 million and $12 realized in earnings, respectively, with $2 million and an immaterial amount excluded from hedge effectiveness testing, respectively | ||||
[2] | Generation enters into interest rate derivative contracts to economically hedge risk associated with theB interest rate component of commodity positions.B The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure.B Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||
[3] | Generation enters into interest rate derivative contracts to economically hedge risk associated with theB interest rate component of commodity positions.B The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure.B Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. | ||||
[4] | Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | ||||
[5] | Represents the netting of fair value balances with the same counterparty and any associated cash collateral |
Derivative_Financial_Instrumen4
Derivative Financial Instruments (Fair Value Measurments) (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | $727 | $938 | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 607 | 937 | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -159 | -352 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -300 | -281 | ' | |||
Total mark-to-market derivative net assets (liabilities) | 854 | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | 459 | -241 | ' | |||
Reclassification to realized at settlement | 52 | 768 | ' | |||
Net mark-to-market gains (losses) | 511 | 527 | ' | |||
Operating Revenue [Member] | Intersegment Eliminations [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | -6 | [1] | -94 | [1] | ' | |
Reclassification to realized at settlement | 13 | [1] | 101 | [1] | ' | |
Net mark-to-market gains (losses) | 7 | [1] | 7 | [1] | ' | |
Derivative [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | ' | 934 | ' | |||
Mark-to-market derivative assets with affiliate (current assets) | 728 | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 569 | 878 | ' | |||
Total mark-to-market derivative assets | 1,297 | 1,812 | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -158 | -350 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -285 | -250 | ' | |||
Total mark-to-market derivative liabilities | -443 | -600 | ' | |||
Total mark-to-market derivative net assets (liabilities) | ' | 1,212 | ' | |||
Energy Related Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 464 | 747 | 512 | |||
Total Cash Flow Hedges [Member] | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Accumulated OCI derivative gain - Beginning Balance | 368 | 488 | ' | |||
Effective portion of changes in fair value | 29 | [2] | 330 | [2] | ' | |
Accumulated OCI derivative gain - Ending Balance | 120 | 368 | 488 | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 464 | 747 | 512 | |||
Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | ' | ' | ' | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 0 | 10 | 1 | |||
Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Reclassifications from accumulated OCI to net income | -277 | -453 | ' | |||
Total Cash Flow Hedges [Member] | Purchased PowerOne [Member] | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Ineffective portion recognized in income | ' | 3 | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Reclassifications from accumulated OCI to net income | 14,207 | 12,735 | 9,286 | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Expected reclassification from accumulated other comprehensive income to results of operations | 195 | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | 727 | 938 | ' | |||
Mark-to-market derivative assets with affiliate (current assets) | ' | 226 | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 600 | 924 | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -142 | -334 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -120 | -232 | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | 465 | -147 | 218 | |||
Reclassification to realized at settlement | 39 | 667 | -515 | |||
Net mark-to-market gains (losses) | 504 | 520 | -297 | [3] | ||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | |||
Proprietary Trading Activities [Abstract] | ' | ' | ' | |||
Change in fair value | -21 | -12 | 23 | |||
Reclassification to realized at settlement | -18 | 108 | -26 | |||
Net mark-to-market gains (losses) | -39 | 96 | -3 | |||
Exelon Generation Co L L C [Member] | Pro Forma [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | ' | ' | 218 | |||
Reclassification to realized at settlement | ' | ' | -515 | |||
Net mark-to-market gains (losses) | ' | ' | -297 | [3] | ||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | 285 | -362 | 87 | |||
Reclassification to realized at settlement | -65 | 429 | -296 | |||
Net mark-to-market gains (losses) | 220 | 67 | -209 | [3] | ||
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | Pro Forma [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | ' | ' | 258 | |||
Reclassification to realized at settlement | ' | ' | -516 | |||
Net mark-to-market gains (losses) | ' | ' | -258 | [3] | ||
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | 180 | 215 | 131 | |||
Reclassification to realized at settlement | 104 | 238 | -219 | |||
Net mark-to-market gains (losses) | 284 | 453 | -88 | [3] | ||
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | Pro Forma [Member] | ' | ' | ' | |||
Other Derivatives Not Designated As Hedging Instruments [Abstract] | ' | ' | ' | |||
Change in fair value | ' | ' | -40 | |||
Reclassification to realized at settlement | ' | ' | 1 | |||
Net mark-to-market gains (losses) | ' | ' | -39 | [3] | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | ' | 934 | [4] | ' | ||
Mark-to-market derivative assets with affiliate (current assets) | 728 | [5] | 226 | [4] | ' | |
Mark-to-market derivative assets (noncurrent assets) | 569 | [5] | 878 | [4] | ' | |
Total mark-to-market derivative assets | 1,297 | [5] | 2,038 | [4] | ' | |
Mark-to-market derivative liabilities (current liabilities) | -141 | [5] | -332 | [4] | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | -109 | [5] | -201 | [4] | ' | |
Total mark-to-market derivative liabilities | -250 | [5] | -533 | [4] | ' | |
Total mark-to-market derivative net assets (liabilities) | 1,047 | [5] | 1,505 | [4] | ' | |
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | 2,616 | 2,883 | [6] | ' | ||
Mark-to-market derivative assets with affiliate (current assets) | ' | 226 | [6] | ' | ||
Mark-to-market derivative assets (noncurrent assets) | 1,344 | 1,792 | [6] | ' | ||
Total mark-to-market derivative assets | 3,960 | 4,901 | [6] | ' | ||
Mark-to-market derivative liabilities (current liabilities) | -2,023 | -2,419 | [6] | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -804 | -1,080 | [6] | ' | ||
Total mark-to-market derivative liabilities | -2,827 | -3,499 | [6] | ' | ||
Total mark-to-market derivative net assets (liabilities) | 1,133 | 1,402 | [6] | ' | ||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | |||
Current assets collateral offset | 84 | 113 | ' | |||
Noncurrent assets collateral offset | 72 | 201 | ' | |||
Current liabilities collateral offset | -12 | -214 | ' | |||
Noncurrent liabilities collateral offset | 0 | -131 | ' | |||
Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member] | ' | ' | ' | |||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | |||
Fair value swap contract current asset | 0 | 226 | ' | |||
Fair value swap contract noncurrent asset | ' | 0 | ' | |||
Noncurrent liability DOE interest rate swap | ' | 28 | ' | |||
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | 1,476 | 2,469 | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 285 | 724 | ' | |||
Total mark-to-market derivative assets | 1,761 | 3,193 | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -1,410 | -2,432 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -293 | -689 | ' | |||
Total mark-to-market derivative liabilities | -1,703 | -3,121 | ' | |||
Total mark-to-market derivative net assets (liabilities) | 58 | 72 | ' | |||
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets | -3,364 | [7] | -4,418 | [7] | ' | |
Mark-to-market derivative assets (noncurrent assets) | -1,060 | [7] | -1,638 | [7] | ' | |
Total mark-to-market derivative assets | -4,424 | [7] | -6,056 | [7] | ' | |
Mark-to-market derivative liabilities (current liabilities) | 3,292 | [7] | 4,519 | [7] | ' | |
Mark-to-market derivative liabilities (noncurrent liabilities) | 988 | [7] | 1,568 | [7] | ' | |
Total mark-to-market derivative liabilities | 4,280 | [7] | 6,087 | [7] | ' | |
Total mark-to-market derivative net assets (liabilities) | -144 | [7] | 31 | [7] | ' | |
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | |||
Total cash collateral received net of cash collateral posted | 144 | -31 | ' | |||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Accumulated OCI derivative gain - Beginning Balance | 532 | [8],[9] | 925 | [8],[9] | ' | |
Effective portion of changes in fair value | 0 | 432 | [10] | ' | ||
Accumulated OCI derivative gain - Ending Balance | 119 | [9] | 532 | [8],[9] | ' | |
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Net gain (loss) related to effective portion of changes in fair value of swap contract | ' | 88 | ' | |||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | ' | ' | ' | |||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Unrealized gain (loss) related to fair value of swap contract | ' | 133 | 420 | |||
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | 133 | 375 | ' | |||
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Reclassifications from accumulated OCI to net income | -413 | [11] | -828 | [11] | ' | |
Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Purchased PowerOne [Member] | ' | ' | ' | |||
Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Ineffective portion recognized in income | ' | 3 | ' | |||
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | ' | ' | ' | |||
Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract] | ' | ' | ' | |||
Net gains (losses) related to interest rate swaps and treasury rate locks | -5 | -20 | ' | |||
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks | -15 | -9 | ' | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 683 | 1,368 | 968 | |||
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | ' | ' | ' | |||
Cash Flow Hedge Activity Impact [Abstract] | ' | ' | ' | |||
Net unrealized pre-tax gain (loss) on effective cash flow hedges | 0 | 5 | 10 | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets (noncurrent assets) | 0 | 0 | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -17 | -18 | ' | |||
Mark-to-market derivative liability with affiliate (current liability) | 0 | -226 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -176 | -49 | ' | |||
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities) | 0 | 0 | ' | |||
Commonwealth Edison Co [Member] | Derivative [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Total mark-to-market derivative net assets (liabilities) | -193 | [12] | ' | ' | ||
Commonwealth Edison Co [Member] | Derivative [Member] | Intersegment Eliminations [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative assets with affiliate (current assets) | ' | -226 | [6] | ' | ||
Total mark-to-market derivative assets | ' | -226 | [6] | ' | ||
Mark-to-market derivative liability with affiliate (current liability) | ' | 226 | [6] | ' | ||
Total mark-to-market derivative liabilities | ' | 226 | [6] | ' | ||
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative liabilities (current liabilities) | -17 | [12] | -18 | [12],[6] | ' | |
Mark-to-market derivative liability with affiliate (current liability) | ' | -226 | [12],[6] | ' | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -176 | [12] | -49 | [12],[6] | ' | |
Total mark-to-market derivative liabilities | -193 | [12] | -293 | [12],[6] | ' | |
Total mark-to-market derivative net assets (liabilities) | ' | -293 | [12],[6] | ' | ||
Commonwealth Edison Co [Member] | Cash Flow Hedging [Member] | ' | ' | ' | |||
Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract] | ' | ' | ' | |||
Fair value swap contract current liability | 0 | 226 | ' | |||
Fair value swap contract noncurrent liability | ' | 0 | ' | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Derivatives Fair Value [Line Items] | ' | ' | ' | |||
Mark-to-market derivative liabilities (current liabilities) | 0 | 0 | ' | |||
Mark-to-market derivative liability with affiliate (current liability) | 0 | 0 | ' | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | 0 | 0 | ' | |||
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities) | $0 | $0 | ' | |||
[1] | Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value are recorded to operating revenues and eliminated in consolidation. | |||||
[2] | Includes $15 million and $9 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the year ended December 31, 2013 and 2012, respectively | |||||
[3] | Exelon and Generation have historically presented mark-to-market gains and losses within purchased power expense for all non-trading, energy-related derivatives that were not accounted for as cash flow hedges. In 2011, Exelon and Generation classified the mark-to-market gains and losses for contracts, where the underlying hedged transaction was an expected sale to hedge power, to operating revenues. | |||||
[4] | Current and noncurrent assets are shown net of collateral of $113 million and $201 million, respectively, and current and noncurrent liabilities are shown net of collateral of $ (214) million and $ (131) million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $ (31) million at December 31, 2012 | |||||
[5] | Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013. | |||||
[6] | Includes current and noncurrent assets for Generation and current and noncurrent liabilities for ComEd of $226 million related to the fair value of the five-year financial swap contract between Generation and ComEd, as described above. For Generation, excludes $28 million of noncurrent liability relating to an interest rate swap in connection with a loan agreement to fund Antelope Valley as discussed above | |||||
[7] | Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above | |||||
[8] | Includes $133 million and $420 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012 and 2011 | |||||
[9] | Excludes $5 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2013 and 2012, respectively | |||||
[10] | Includes $88 million of gains, net of taxes, related to the effective portion of changes in fair value of the five-year financial swap contract with ComEd for the year ended December 31, 2012. As of the merger date, cash flow hedges were discontinued, as such, this amount represents changes in fair value prior to the merger date. | |||||
[11] | Includes $133 million and $375 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the years ended December 31, 2013 and 2012, respectively | |||||
[12] | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers |
Derivative_Financial_Instrumen5
Derivative Financial Instruments (Credit Risk) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | |
In Millions, unless otherwise specified | |||
Exelon Generation Co L L C [Member] | ' | ' | |
Counter Party With Exposure [Abstract] | ' | ' | |
Cash Collateral Held | $206 | $499 | |
Letters Of Credit Held | 34 | 45 | |
Due From Related Parties [Abstract] | ' | ' | |
Net receivable from electric utility | 38 | ' | |
Net receivable from affiliated electric and gas utility | 38 | ' | |
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | |
Due From Related Parties [Abstract] | ' | ' | |
Net receivable from affiliated electric and gas utility | 38 | ' | |
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | ' | ' | |
Due From Related Parties [Abstract] | ' | ' | |
Net receivable from affiliated electric and gas utility | 38 | ' | |
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | |
Due From Related Parties [Abstract] | ' | ' | |
Net receivable from affiliated electric and gas utility | 27 | ' | |
Exelon Generation Co L L C [Member] | Total Exposure Before Credit Collateral [Member] | ' | ' | |
Credit Risk [Abstract] | ' | ' | |
Investment grade | 1,621 | ' | |
Non-investment grade | 27 | ' | |
No external ratings - internally rated - investment grade | 416 | ' | |
No external ratings - internally rated - non-investment grade | 30 | ' | |
Total | 2,094 | ' | |
Exelon Generation Co L L C [Member] | Credit Collateral [Member] | ' | ' | |
Credit Risk [Abstract] | ' | ' | |
Investment grade | 172 | [1] | ' |
Non-investment grade | 9 | [1] | ' |
No external ratings - internally rated - investment grade | 1 | [1] | ' |
No external ratings - internally rated - non-investment grade | 2 | [1] | ' |
Total | 184 | [1] | ' |
Exelon Generation Co L L C [Member] | Net Exposure [Member] | ' | ' | |
Credit Risk [Abstract] | ' | ' | |
Investment grade | 1,449 | ' | |
Non-investment grade | 18 | ' | |
No external ratings - internally rated - investment grade | 415 | ' | |
No external ratings - internally rated - non-investment grade | 28 | ' | |
Total | 1,910 | ' | |
Financial institutions | 256 | ' | |
Investor-owned utilities, marketers and power producers | 684 | ' | |
Energy cooperative and municipalities | 907 | ' | |
Other | 63 | ' | |
Total | 1,910 | ' | |
Exelon Generation Co L L C [Member] | Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | ' | ' | |
Credit Risk [Abstract] | ' | ' | |
Investment grade | 1 | ' | |
No external ratings - internally rated - investment grade | 1 | ' | |
Total | 2 | ' | |
Exelon Generation Co L L C [Member] | Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | ' | ' | |
Credit Risk [Abstract] | ' | ' | |
Investment grade | 491 | ' | |
No external ratings - internally rated - investment grade | 226 | ' | |
Total | 717 | ' | |
Commonwealth Edison Co [Member] | ' | ' | |
Counter Party With Exposure [Abstract] | ' | ' | |
Cash Collateral Held | 19 | ' | |
PECO Energy Co [Member] | ' | ' | |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' | ' | |
Credit exposure under natural gas supply and management agreements | 9 | ' | |
Baltimore Gas and Electric Company [Member] | ' | ' | |
Natural Gas Supply And Management Agreement Credit Exposure [Abstract] | ' | ' | |
Credit exposure under off system sales | 14 | ' | |
Other Segments [Member] | ' | ' | |
Counter Party With Exposure [Abstract] | ' | ' | |
Cash Collateral Held | 155 | ' | |
Letters Of Credit Held | $29 | ' | |
[1] | As of December 31, 2013, credit collateral held from counterparties where Generation had credit exposure included $155 million of cash and $29 million of letters of credit |
Derivative_Financial_Instrumen6
Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | ||||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Letters of credit posted | ' | $563 | ||
Line Of Credit Facility Amount Outstanding | 1,416 | ' | ||
Exelon Generation Co L L C [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Aggregate fair value of derivatives with credit-risk-related contingent features | -1,056 | [1] | -1,849 | [1] |
Contractual right of offset related to derivative assets | 846 | [2] | 1,426 | [2] |
Net liability position after contractual right of offset | -210 | [3] | -423 | [3] |
Incremental collateral for credit rating downgrade to BBB- and Baa3 | 2 | ' | ||
Cash collateral held | 206 | 499 | ||
Cash collateral posted | 72 | 527 | ||
Letters of credit held | 34 | 45 | ||
Letters of credit posted | 364 | ' | ||
Line Of Credit Facility Amount Outstanding | 1,413 | ' | ||
Master Netting Arrangements [Abstract] | ' | ' | ||
Cash collateral received not offset against net derivative positions | 10 | 3 | ||
Commonwealth Edison Co [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Cash collateral held | 19 | ' | ||
PECO Energy Co [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | 42 | ' | ||
Line Of Credit Facility Amount Outstanding | 1 | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Incremental collateral for loss of investment grade credit rating | 85 | ' | ||
Other Segments [Member] | ' | ' | ||
Collateral And Contingent Related Features [Abstract] | ' | ' | ||
Cash collateral held | 155 | ' | ||
Letters of credit held | $29 | ' | ||
[1] | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent ignoring the effects of master netting agreements. | |||
[2] | Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. | |||
[3] | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
Debt_and_Credit_Agreements_Det
Debt and Credit Agreements (Details) (USD $) | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 9 Months Ended | 12 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 28, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 18, 2012 | Jun. 18, 2012 | Jun. 28, 2012 | Jun. 18, 2012 | Jun. 18, 2012 | Jun. 28, 2012 | Jul. 13, 2012 | Jun. 28, 2012 | Jun. 18, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||||||||||||||||||||||||||||
CreditAgreementThreshold | Commercial Paper [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | ComEd Financing Three Affiliate [Member] | ComEd Financing Three Affiliate [Member] | PECO Trust Three Affiliate [Member] | PECO Trust Three Affiliate [Member] | PECO Trust Four Affiliate [Member] | PECO Trust Four Affiliate [Member] | Baltimore Gas Electric Trust [Member] | Baltimore Gas Electric Trust [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Fixed Rate Debt [Member] | Floating Rate Debt [Member] | Capital Lease Obligations [Member] | Capital Lease Obligations [Member] | Notes Payable To Banks [Member] | Notes Payable To Banks [Member] | Senior Notes [Member] | Senior Notes [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Pollution Control Notes [Member] | Pollution Control Notes [Member] | Pollution Control Notes [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Long Term Debt Assumed [Member] | Long Term Debt Assumed [Member] | Long Term Debt Assumed [Member] | Long Term Debt Exchange Offer Exchanged [Member] | Exelon Corporate [Member] | Exelon Corporate [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||||||||||||||||||||||||||||||
BasisPoints | Interest Rate Swap [Member] | Interest Rate Swap [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Floating Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Floating Rate Debt [Member] | Fixed Rate Note, 4.55% Due 2015 [Member] | Notes, 5.15% Due 2020 [Member] | Senior Notes, 7.6% Due 2032 [Member] | BasisPoints | BasisPoints | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Designated as Hedging Instrument [Member] | Floating Rate Debt [Member] | Capital Lease Obligations [Member] | Capital Lease Obligations [Member] | Notes Payable To Banks [Member] | Notes Payable To Banks [Member] | Senior Notes [Member] | Senior Notes [Member] | Pollution Control Notes [Member] | Pollution Control Notes [Member] | Pollution Control Notes [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Non Recourse Debt [Member] | Long Term Debt Issuances [Member] | Long Term Debt Issuances [Member] | Long Term Debt Assumed [Member] | Long Term Debt Exchange Offer Issued And Sold [Member] | Long Term Debt Exchange Offer Issued And Sold [Member] | Long Term Debt Exchange Offer Purchased [Member] | Long Term Debt Exchange Offer Exchanged [Member] | Long Term Debt Exchange Offer Exchanged [Member] | Long Term Debt Exchange Offer Exchanged [Member] | CreditAgreementThreshold | Commercial Paper [Member] | WillisTowerCapitalLease749May12053Member [Member] | Fixed Rate Debt [Member] | Notes Payable To Banks [Member] | Notes Payable To Banks [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | Suboridanted Debentures [Member] | BasisPoints | PECO Trust Three Affiliate [Member] | PECO Trust Three Affiliate [Member] | PECO Trust Four Affiliate [Member] | PECO Trust Four Affiliate [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | First Mortgage Bonds [Member] | BasisPoints | Commercial Paper [Member] | Baltimore Gas Electric Trust [Member] | Baltimore Gas Electric Trust [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Hedging [Member] | Fair Value Hedging [Member] | CreditAgreementThreshold | Foreign Exchange Contract [Member] | Interest Rate Swap [Member] | Interest Rate Swap [Member] | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | Constellation Solar Horizons Financing [Member] | Constellation Solar Horizons Financing [Member] | Sacramento PV Energy [Member] | Sacramento PV Energy [Member] | Secured Solar Credit Lending Agreement [Member] | Holyoke [Member] | Denver International Airport [Member] | Upstream Gas Property [Member] | Fixed Rate Debt [Member] | Floating Rate Debt [Member] | Senior Notes, 4.25% June 15, 2022 [Member] | Senior Notes, 5.6% June 15, 2042 [Member] | Senior Notes [Member] | Senior Notes, 7.6% Due 2032 [Member] | CreditAgreementThreshold | Fixed Rate Debt [Member] | Fixed Rate Debt [Member] | CreditAgreementThreshold | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedging [Member] | MW | MW | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Secured Long Term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $7,746,000,000 | [1],[2] | $7,397,000,000 | [1],[2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $5,546,000,000 | [3],[4] | $5,447,000,000 | [3],[4] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||
Unsecured Long Term Debt | 1,750,000,000 | 1,850,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,571,000,000 | 8,021,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,271,000,000 | 6,721,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,750,000,000 | 1,850,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long-term debt to affiliate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,007,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long Term Notes Payable | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 181,000,000 | [5] | 177,000,000 | [5] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 33,000,000 | [5] | 30,000,000 | [5] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 148,000,000 | 140,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||
Long Term Pollution Control Bond | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-recourse debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,000,000 | 38,000,000 | 39,000,000 | 41,000,000 | 113,000,000 | 11,000,000 | 7,000,000 | 72,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - MW | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | 30 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - Term | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | '18 years | ' | ' | '3 years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - Commitment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 150,000,000 | ' | ' | 150,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - Commitment Increase Available | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - Interest Rate Swap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Non-Recourse Debt - Hedge Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75.00% | 75.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Total long-term debt | 18,760,000,000 | 18,297,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,552,000,000 | 7,271,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,694,000,000 | 5,587,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,947,000,000 | 1,647,000,000 | ' | ' | ' | ' | ' | ' | ' | 2,015,000,000 | 2,182,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Unamortized debt discount and premium, net | -19,000,000 | -17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -11,000,000 | -13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Unamortized settled fair value hedge, net | -384,000,000 | -448,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Fair value hedge carrying value adjustment, net | 7,000,000 | 17,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long-term debt due within one year | -1,509,000,000 | -1,047,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -561,000,000 | -28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 617,000,000 | 252,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -250,000,000 | -300,000,000 | ' | ' | ' | ' | ' | ' | ' | -70,000,000 | -467,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long-term debt | 17,325,000,000 | 17,190,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 265,000,000 | 332,000,000 | 238,000,000 | 262,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,077,000,000 | 150,000,000 | ' | 550,000,000 | 550,000,000 | 700,000,000 | ' | ' | 5,559,000,000 | 5,245,000,000 | ' | ' | ' | ' | 262,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,077,000,000 | 150,000,000 | ' | ' | ' | ' | ' | 441,000,000 | 1,000,000 | ' | ' | 5,058,000,000 | 5,315,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,947,000,000 | 1,647,000,000 | ' | ' | ' | ' | ' | 2,200,000,000 | [6],[7] | 1,950,000,000 | [6],[7] | 1,746,000,000 | 1,446,000,000 | ' | ' | ' | ' | 265,000,000 | 332,000,000 | |||||||||||||||||||||||||||||||||
Total long-term debt with adjustments | 17,623,000,000 | 17,698,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,168,000,000 | 7,455,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,941,000,000 | 1,711,000,000 | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long-term debt to PECO Energy Transition Trust due within one year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Subordinated debentures | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 206,000,000 | [8] | 206,000,000 | [8] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||
Total long-term debt to financing trusts | 648,000,000 | [9] | 648,000,000 | [9] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | [10] | ' | [10] | ' | ' | |||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 298,000,000 | 648,000,000 | ' | ' | ' | ' | 206,000,000 | [9] | 206,000,000 | [9] | 81,000,000 | [9] | 81,000,000 | [9] | 103,000,000 | [9] | 103,000,000 | [9] | 258,000,000 | [9] | 258,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,523,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,808,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 206,000,000 | 206,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 184,000,000 | [11] | 184,000,000 | [11] | 81,000,000 | [11] | 81,000,000 | [11] | 103,000,000 | [11] | 103,000,000 | [11] | ' | ' | ' | 258,000,000 | 258,000,000 | ' | ' | 258,000,000 | [10] | 258,000,000 | [10] | ' | ' | ||||||||||||||||||||
Interest rate on long-term debt | ' | ' | ' | ' | ' | ' | 6.35% | ' | 7.38% | ' | 5.75% | ' | 6.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.55% | 5.15% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.25% | 5.60% | ' | ' | ' | ' | ' | ' | 7.60% | ' | ' | ' | ' | ' | ' | 6.95% | ' | ' | ' | 6.35% | ' | ' | 7.38% | ' | 5.75% | ' | ' | ' | ' | ' | ' | ' | ' | 6.20% | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Minimum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.68% | ' | ' | ' | ' | ' | 4.50% | ' | 2.00% | ' | 1.20% | ' | 2.80% | 4.10% | ' | ' | 2.33% | 1.96% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4.50% | ' | 2.00% | ' | 4.10% | ' | ' | 2.33% | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.96% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.63% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1.20% | ' | 2.80% | ' | ' | ' | ' | ' | 5.68% | ' | |||||||||||||||||||||||||||||||||||
Maximum interest rate on long-term debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.82% | ' | ' | ' | ' | ' | 7.83% | ' | 7.60% | ' | 7.63% | ' | 6.35% | ' | ' | ' | 5.50% | 2.77% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.83% | ' | 7.60% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.50% | 2.77% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7.63% | 7.49% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.95% | ' | ' | 6.35% | ' | ' | ' | ' | ' | 5.82% | ' | |||||||||||||||||||||||||||||||||||
Long Term Debt | 19,408,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,552,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 775,000,000 | ' | ' | 535,000,000 | ' | 5,900,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,384,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 2,273,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Long term debt old notes | 258,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 608,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Cash payment related to exchange offer | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Increase in fair value adjustment | 403,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Fair Value Adjustment Outstanding | 199,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 166,000,000 | 199,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Derivative, Gain on Derivative | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Footnotes To Long-Term Debt [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due Current | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due In Two Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due In Three Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due In Four Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due In Five Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Leases Future Minimum Payments Due Thereafter | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Capital Lease Obligations Noncurrent | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Notional amount of interest rate cash flow hedge derivatives | 2,651,000,000 | 2,498,000,000 | ' | ' | 1,275,000,000 | 650,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 195,000,000 | 144,000,000 | 470,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Loss on interest rate swap | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Aggregate bank commitments under unsecured revolving credit facilities | 8,375,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | 5,675,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Outstanding borrowings/facility draws | 1,416,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | 1,413,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Outstanding letters of credit | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Actual available capacity | 6,959,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 498,000,000 | ' | 4,262,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 599,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Available capacity to support additional commercial paper borrowings | 6,565,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 498,000,000 | ' | 4,187,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 816,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 599,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 465,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Footnotes To Line Of Credit Facility [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Credit facility agreements with minority and community banks | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Letters of credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
ShortTermBorrowingsAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Average Interest Rate On Commercial Paper Borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.27% | 0.47% | 0.32% | 0.45% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.40% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.31% | 0.43% | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Maximum borrowings outstanding | 682,000,000 | 505,000,000 | 600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 291,000,000 | 165,000,000 | 304,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 446,000,000 | 366,000,000 | 407,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000,000 | 76,000,000 | 190,000,000 | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Maximum program size | 8,300,000,000 | [12] | 8,300,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | [12] | 500,000,000 | [12] | 5,600,000,000 | [12] | 5,600,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | [12] | 1,000,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | [12] | 600,000,000 | [12] | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | [12] | 600,000,000 | [12] | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||
Commercial paper borrowings | ' | 0 | ' | 319,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 184,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000,000 | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Short-term debt outstanding amount | 341,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 184,000,000 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Average borrowings | 254,000,000 | 199,000,000 | 218,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,000,000 | 4,000,000 | 51,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 203,000,000 | 110,000,000 | 36,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | 6,000,000 | 26,000,000 | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Average interest rates, computed on a daily basis | 0.37% | 0.48% | 0.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.32% | 0.45% | 0.48% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.40% | 0.50% | 0.71% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.31% | 0.43% | 0.38% | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Credit Agreements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Additional amounts available upon request under current credit facilities | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Amount that would constitute an event of default | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Basis points adders for prime-based borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.00275 | ' | 0.00075 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.00075 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Basis points adders for LIBOR-based borrowings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.01275 | ' | 0.01075 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.01 | ' | ' | ' | ' | ' | ' | ' | ' | 0.01075 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Bilateral letters of credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 75,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Basis Points For Prime Based Borrowings Current | 0.0065 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Basis Points For LIBOR Based Borrowings Current | 0.0165 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Previous Aggregate Commitments Of Acquired Entity | 2,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Amended Aggregate Commitments Of Acquired Entity | $1,500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Credit agreement interest coverage minimum threshold | 2.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | ' | 2 | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
Debt Covenant Actual | 7.67% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11.45% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8.29% | ' | ' | ' | ' | ' | ' | ' | ' | 7.85% | ' | ' | ' | ' | ' | ' | ' | |||||||||||||||||||||||||||||||||||
[1] | Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's assets are subject to the liens of their respective mortgage indentures. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | Includes First Mortgage Bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Substantially all of ComEd's assets other than expressly excepted property are subject to the lien of its mortgage indenture. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | Includes First Mortgage Bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | Includes capital lease obligations of $41 million and $30 million at December 31, 2013 and 2012, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $5 million and $19 million will be made in 2014, 2015, 2016, 2017, 2018 and thereafter, respectively. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | Substantially all of PECO's assets are subject to the lien of its mortgage indenture. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Includes First Mortgage Bonds issued under the PECO mortgage indenture securing pollution control bonds and notes. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Amount owed to this financing trust is recorded as debt to financing trust within ComEd's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | Amounts owed to these financing trusts are recorded as debt to financing trusts within Exelon's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | B (a)B B B B B B B B Amount owed to this financing trust is recorded as debt to financing trust within BGE's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[11] | Amounts owed to this financing trust are recorded as debt to financing trusts within PECO's Consolidated Balance Sheets. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[12] | (a) Equals aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of a $75 million bilateral agreement) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. |
Debt_and_Credit_Agreements_Mat
Debt and Credit Agreements (Maturitites of Long-term Debt) (Details) (USD $) | Dec. 31, 2013 | |
In Millions, unless otherwise specified | ||
Long Term Debt By Maturity [Abstract] | ' | |
Long Term Debt Maturities Repayments Of Principal In Next Twelve Months | $1,428 | |
Long Term Debt Maturities Repayments Of Principal In Year Two | 1,615 | |
Long Term Debt Maturities Repayments Of Principal In Year Three | 1,346 | |
Long Term Debt Maturities Repayments Of Principal In Year Four | 1,396 | |
Long Term Debt Maturities Repayments Of Principal In Year Five | 1,345 | |
Long Term Debt Maturities Repayments Of Principal After Year Five | 12,278 | [1] |
Long Term Debt | 19,408 | |
Exelon Generation Co L L C [Member] | ' | |
Long Term Debt By Maturity [Abstract] | ' | |
Long Term Debt Maturities Repayments Of Principal In Next Twelve Months | 561 | |
Long Term Debt Maturities Repayments Of Principal In Year Two | 555 | |
Long Term Debt Maturities Repayments Of Principal In Year Three | 81 | |
Long Term Debt Maturities Repayments Of Principal In Year Four | 706 | |
Long Term Debt Maturities Repayments Of Principal In Year Five | 5 | |
Long Term Debt Maturities Repayments Of Principal After Year Five | 5,644 | |
Long Term Debt | 7,552 | |
Commonwealth Edison Co [Member] | ' | |
Long Term Debt By Maturity [Abstract] | ' | |
Long Term Debt Maturities Repayments Of Principal In Next Twelve Months | 617 | |
Long Term Debt Maturities Repayments Of Principal In Year Two | 260 | |
Long Term Debt Maturities Repayments Of Principal In Year Three | 665 | |
Long Term Debt Maturities Repayments Of Principal In Year Four | 425 | |
Long Term Debt Maturities Repayments Of Principal In Year Five | 840 | |
Long Term Debt Maturities Repayments Of Principal After Year Five | 3,093 | [2] |
Long Term Debt | 5,900 | |
PECO Energy Co [Member] | ' | |
Long Term Debt By Maturity [Abstract] | ' | |
Long Term Debt Maturities Repayments Of Principal In Next Twelve Months | 250 | |
Long Term Debt Maturities Repayments Of Principal In Year Two | 0 | |
Long Term Debt Maturities Repayments Of Principal In Year Three | 300 | |
Long Term Debt Maturities Repayments Of Principal In Year Four | 0 | |
Long Term Debt Maturities Repayments Of Principal In Year Five | 500 | |
Long Term Debt Maturities Repayments Of Principal After Year Five | 1,334 | [3] |
Long Term Debt | 2,384 | |
Baltimore Gas and Electric Company [Member] | ' | |
Long Term Debt By Maturity [Abstract] | ' | |
Long Term Debt Maturities Repayments Of Principal In Next Twelve Months | 0 | |
Long Term Debt Maturities Repayments Of Principal In Year Two | 0 | |
Long Term Debt Maturities Repayments Of Principal In Year Three | 300 | |
Long Term Debt Maturities Repayments Of Principal In Year Four | 265 | |
Long Term Debt Maturities Repayments Of Principal In Year Five | 0 | |
Long Term Debt Maturities Repayments Of Principal After Year Five | 1,708 | [4] |
Long Term Debt | $2,273 | |
[1] | )B B B B B B B B Includes $648 million due to ComEd, PECO and BGE financing trusts. | |
[2] | Includes $206 million due to ComEd financing trust. | |
[3] | Includes $184 million due to PECO financing trusts. | |
[4] | Includes $258 million due to BGE financing trust. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | ||||||
Jan. 13, 2011 | Dec. 31, 2012 | Mar. 31, 2012 | Dec. 31, 2011 | Mar. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | |
U.S. Federal statutory rate | ' | ' | ' | ' | ' | 35.00% | [1] | 35.00% | 35.00% |
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | |
State income taxes, net of Federal income tax benefit | ' | ' | ' | ' | ' | 4.70% | [1] | -3.60% | 4.40% |
Qualified nuclear decommissioning trust fund income (losses) | ' | ' | ' | ' | ' | 3.70% | [1] | 5.40% | 0.50% |
Domestic production activities deduction | ' | ' | ' | ' | ' | ' | ' | -0.30% | |
Tax exempt income | ' | ' | ' | ' | ' | -0.20% | [1] | -0.20% | -0.20% |
Nontaxable postretirement benefits | ' | ' | ' | ' | ' | ' | -1.10% | ' | |
Health Care Reform Legislation | ' | ' | ' | ' | ' | 0.10% | [1] | 0.10% | -0.20% |
Amortization of investment tax credit | ' | ' | ' | ' | ' | -1.90% | [1] | 2.20% | -0.30% |
Plant basis differences | ' | ' | ' | ' | ' | -1.60% | [1] | -2.40% | -1.00% |
Production Tax Credits | ' | ' | ' | ' | ' | -2.10% | [1] | ' | 0.90% |
Fines and Penalties | ' | ' | ' | ' | ' | ' | -2.60% | ' | |
Merger Expenses | ' | ' | ' | ' | ' | ' | -2.40% | ' | |
Other | ' | ' | ' | ' | ' | -0.10% | [1] | -1.10% | -0.20% |
Effective income tax rate | ' | ' | ' | ' | ' | 37.60% | [1] | 34.90% | 36.80% |
Unrecognized Tax Benefits For Which Timing Of Ultimate Benefits Uncertain [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Tax positions for which there is uncertainty about the timing of tax benefits | ' | $730,000,000 | ' | ' | ' | $1,387,000,000 | $730,000,000 | ' | |
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits that if recognized would affect the effective tax rate | ' | 294,000,000 | ' | ' | ' | 788,000,000 | 294,000,000 | ' | |
Increases based on tax positions prior to current year | ' | ' | ' | ' | ' | -493,000,000 | -91,000,000 | 3,000,000 | |
Interest recognized related to uncertain tax positions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net interest receivable (payable) recognized related to uncertain tax positions | ' | 31,000,000 | ' | ' | ' | -349,000,000 | 31,000,000 | ' | |
Net interest (income) expense recognized related to uncertain tax positions | ' | ' | ' | ' | ' | 391,000,000 | -1,000,000 | -56,000,000 | |
1999 Sale of Fossil Generating Assets [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Deferred tax gain on sale of fossil generating assets | ' | ' | ' | ' | ' | 2,800,000,000 | ' | ' | |
Deferred tax gain under involuntary conversion provisions of the IRC | ' | ' | ' | ' | ' | 1,600,000,000 | ' | ' | |
Deferred tax gain under like-kind exchange provisions of the IRC | ' | ' | ' | ' | ' | 1,200,000,000 | ' | ' | |
IRS asserted penalties for understatement of tax | ' | ' | ' | ' | ' | 87,000,000 | ' | ' | |
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position | ' | ' | ' | ' | ' | 840,000,000 | ' | ' | |
Potential interest expense from a successful IRS challenge of the like-kind exchange position | ' | ' | ' | ' | ' | 305,000,000 | ' | ' | |
Unsuccessful Litigation Determinations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Expected non-cash charge to earnings | ' | ' | ' | ' | ' | 265,000,000 | ' | ' | |
Unrecognized tax benefits for Generation Repairs | ' | ' | ' | ' | ' | 107,000,000 | ' | ' | |
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
FIN 48 Tax Remeasurement Interest Expense | ' | ' | ' | ' | ' | ' | ' | 65,000,000 | |
Tax Settlement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Payment to IRS for open tax positions | ' | ' | ' | ' | ' | ' | ' | 302,000,000 | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
IL State Deferred Income Tax Expense due to rate change | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | |
Regulatory asset related to state tax rate change | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | |
Additional Income Tax Expense (Benefit) Due To 2011 New Tax Law | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | |
Change in state income tax provision due to rate change | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | |
Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income tax benefit recorded as a result of re-apportionment of state income taxes | ' | 3,000,000 | 116,000,000 | 1,000,000 | 22,000,000 | ' | ' | ' | |
Deferred state tax liability resulting from purchase accounting | ' | ' | 44,000,000 | ' | ' | ' | ' | ' | |
DeferredStateTaxAssetFromStateTaxApportionment | ' | ' | 72,000,000 | ' | ' | ' | ' | ' | |
Income and cash tax benefit as a result of repair costs deduction [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Cash tax benefit (detriment) as a result of repair costs deduction | ' | ' | ' | ' | ' | ' | ' | 300,000,000 | |
Gas Distribution Repair Tax Benefit Expense | ' | ' | ' | ' | ' | ' | 26,000,000 | 26,000,000 | |
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits - beginning balance | ' | ' | 807,000,000 | ' | 787,000,000 | 1,024,000,000 | 807,000,000 | 787,000,000 | |
Merger Balance Transfer | ' | ' | ' | ' | ' | ' | 195,000,000 | ' | |
Increases based on tax positions related to current year | ' | ' | ' | ' | ' | 19,000,000 | 34,000,000 | 5,000,000 | |
Changes to tax positions that only affect timing | ' | ' | ' | ' | ' | 649,000,000 | -88,000,000 | 21,000,000 | |
Increases based on tax positions prior to current year | ' | ' | ' | ' | ' | -493,000,000 | -91,000,000 | 3,000,000 | |
Decreases based on tax positions prior to current year | ' | ' | ' | ' | ' | 6,000,000 | 6,000,000 | ' | |
Decreases related to settlements with taxing authorities | ' | ' | ' | ' | ' | 0 | 2,000,000 | ' | |
Decreases from expiration of statute of limitations | ' | ' | ' | ' | ' | -4,000,000 | -7,000,000 | -3,000,000 | |
Unrecognized tax benefits - ending balance | ' | 1,024,000,000 | ' | 807,000,000 | ' | 2,175,000,000 | 1,024,000,000 | 807,000,000 | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense (Benefit) | ' | ' | ' | ' | ' | 1,044,000,000 | 627,000,000 | 1,457,000,000 | |
Operating Loss Carryforwards [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Federal net operating loss | ' | ' | ' | ' | ' | 377,000,000 | [2] | ' | ' |
Federal general business credits carryforward | ' | ' | ' | ' | ' | 556,000,000 | ' | ' | |
State net operating loss carryforward | ' | ' | ' | ' | ' | 3,061,000,000 | [3] | ' | ' |
Deferred taxes | ' | ' | ' | ' | ' | 161,000,000 | ' | ' | |
Valuation allowance | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Plant basis differences | ' | -10,689,000,000 | ' | ' | ' | -11,612,000,000 | -10,689,000,000 | ' | |
Accrual based contracts | ' | -389,000,000 | ' | ' | ' | -214,000,000 | -389,000,000 | ' | |
Unrealized gains on derivative financial instruments | ' | -392,000,000 | ' | ' | ' | -509,000,000 | -392,000,000 | ' | |
Deferred pension and other post-retirement obligation | ' | 2,356,000,000 | ' | ' | ' | 1,489,000,000 | 2,356,000,000 | ' | |
Nuclear decommissioning activities | ' | -604,000,000 | ' | ' | ' | -647,000,000 | -604,000,000 | ' | |
Deferred debt refinancing costs | ' | -537,000,000 | ' | ' | ' | 173,000,000 | -537,000,000 | ' | |
Net operating losses | ' | 421,000,000 | ' | ' | ' | 252,000,000 | 421,000,000 | ' | |
Tax credit carry-forward | ' | 226,000,000 | ' | ' | ' | 534,000,000 | 226,000,000 | ' | |
Investment in CENG | ' | -405,000,000 | ' | ' | ' | -541,000,000 | -405,000,000 | ' | |
Other, net | ' | 701,000,000 | ' | ' | ' | 804,000,000 | 701,000,000 | ' | |
Deferred income tax liabilities, net | ' | -11,169,000,000 | ' | ' | ' | -11,882,000,000 | -11,169,000,000 | ' | |
Unamortized investment tax credits | ' | -251,000,000 | ' | ' | ' | -490,000,000 | -251,000,000 | ' | |
Total deferred income tax liabilities, net and unamortized investment tax credits | ' | -11,420,000,000 | ' | ' | ' | -12,372,000,000 | -11,420,000,000 | ' | |
Federal Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 744,000,000 | 37,000,000 | 1,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | 140,000,000 | 701,000,000 | 1,200,000,000 | |
Investment tax credit amortization | ' | ' | ' | ' | ' | -15,000,000 | -11,000,000 | -12,000,000 | |
State Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 181,000,000 | -25,000,000 | -3,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | -6,000,000 | -75,000,000 | 271,000,000 | |
More Than One Year And Within Four Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
More Than Four Years And Within Fourteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
More Than Fifteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | |
U.S. Federal statutory rate | ' | ' | ' | ' | ' | 35.00% | [1] | 35.00% | 35.00% |
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | |
State income taxes, net of Federal income tax benefit | ' | ' | ' | ' | ' | 1.60% | [1] | 4.70% | 4.50% |
Qualified nuclear decommissioning trust fund income (losses) | ' | ' | ' | ' | ' | 6.10% | [1] | 9.10% | 0.70% |
Domestic production activities deduction | ' | ' | ' | ' | ' | ' | ' | -0.40% | |
Tax exempt income | ' | ' | ' | ' | ' | -0.30% | [1] | -0.40% | -0.20% |
Nontaxable postretirement benefits | ' | ' | ' | ' | ' | ' | -1.30% | ' | |
Health Care Reform Legislation | ' | ' | ' | ' | ' | ' | ' | 0.00% | |
Amortization of investment tax credit | ' | ' | ' | ' | ' | -3.00% | [1] | 3.70% | -0.30% |
Production Tax Credits | ' | ' | ' | ' | ' | -3.40% | [1] | ' | 1.20% |
Uncertain Tax Position Remeasurement | ' | ' | ' | ' | ' | ' | ' | 0.00% | |
Fines and Penalties | ' | ' | ' | ' | ' | ' | -4.40% | ' | |
Other | ' | ' | ' | ' | ' | 0.70% | [1] | -0.50% | -0.70% |
Effective income tax rate | ' | ' | ' | ' | ' | 36.70% | [1] | 47.30% | 37.40% |
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits that if recognized would affect the effective tax rate | ' | 263,000,000 | ' | ' | ' | 768,000,000 | 263,000,000 | ' | |
Information by nature of uncertainty related to unrecognized tax benefits | ' | ' | ' | ' | ' | 84,000,000 | ' | ' | |
Increases based on tax positions prior to current year | ' | ' | ' | ' | ' | -493,000,000 | -91,000,000 | 3,000,000 | |
Interest recognized related to uncertain tax positions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net interest receivable (payable) recognized related to uncertain tax positions | ' | -20,000,000 | ' | ' | ' | -37,000,000 | -20,000,000 | ' | |
Net interest (income) expense recognized related to uncertain tax positions | ' | ' | ' | ' | ' | 17,000,000 | 11,000,000 | -40,000,000 | |
Status Of Like Kind Exchange Position [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Receivable from Exelon intercompany money pool | ' | ' | ' | ' | ' | 44,000,000 | ' | ' | |
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
FIN 48 Tax Remeasurement Current Tax Expense (Benefit) | ' | ' | ' | ' | ' | ' | ' | -70,000,000 | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
IL State Deferred Income Tax Expense due to rate change | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | |
Additional Income Tax Expense (Benefit) Due To 2011 New Tax Law | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | |
Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income tax benefit recorded as a result of re-apportionment of state income taxes | ' | 7,000,000 | 14,000,000 | 8,000,000 | 11,000,000 | ' | ' | ' | |
Deferred state tax liability resulting from purchase accounting | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | |
Income and cash tax benefit as a result of repair costs deduction [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Cash tax benefit (detriment) as a result of repair costs deduction | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | |
Allocated tax benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Allocated tax benefits | ' | ' | ' | ' | ' | 26,000,000 | 48,000,000 | 30,000,000 | |
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits - beginning balance | ' | ' | 683,000,000 | ' | 664,000,000 | 876,000,000 | 683,000,000 | 664,000,000 | |
Merger Balance Transfer | ' | ' | ' | ' | ' | ' | 183,000,000 | ' | |
Increases based on tax positions related to current year | ' | ' | ' | ' | ' | 19,000,000 | 3,000,000 | 1,000,000 | |
Changes to tax positions that only affect timing | ' | ' | ' | ' | ' | 36,000,000 | -69,000,000 | 24,000,000 | |
Increases based on tax positions prior to current year | ' | ' | ' | ' | ' | -493,000,000 | -91,000,000 | 3,000,000 | |
Decreases based on tax positions prior to current year | ' | ' | ' | ' | ' | 5,000,000 | 6,000,000 | ' | |
Decreases related to settlements with taxing authorities | ' | ' | ' | ' | ' | 0 | 2,000,000 | ' | |
Decreases from expiration of statute of limitations | ' | ' | ' | ' | ' | -4,000,000 | -7,000,000 | -3,000,000 | |
Unrecognized tax benefits - ending balance | ' | 876,000,000 | ' | 683,000,000 | ' | 1,415,000,000 | 876,000,000 | 683,000,000 | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense (Benefit) | ' | ' | ' | ' | ' | 615,000,000 | 500,000,000 | 1,056,000,000 | |
Operating Loss Carryforwards [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Federal net operating loss | ' | ' | ' | ' | ' | 36,000,000 | ' | ' | |
Federal general business credits carryforward | ' | ' | ' | ' | ' | 556,000,000 | ' | ' | |
State net operating loss carryforward | ' | ' | ' | ' | ' | 1,498,000,000 | [4] | ' | ' |
Deferred taxes | ' | ' | ' | ' | ' | 82,000,000 | ' | ' | |
Valuation allowance | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Plant basis differences | ' | -3,545,000,000 | ' | ' | ' | -3,879,000,000 | -3,545,000,000 | ' | |
Accrual based contracts | ' | -389,000,000 | ' | ' | ' | -214,000,000 | -389,000,000 | ' | |
Unrealized gains on derivative financial instruments | ' | -479,000,000 | ' | ' | ' | -505,000,000 | -479,000,000 | ' | |
Deferred pension and other post-retirement obligation | ' | -439,000,000 | ' | ' | ' | -362,000,000 | -439,000,000 | ' | |
Nuclear decommissioning activities | ' | -604,000,000 | ' | ' | ' | -646,000,000 | -604,000,000 | ' | |
Deferred debt refinancing costs | ' | 163,000,000 | ' | ' | ' | 79,000,000 | 163,000,000 | ' | |
Net operating losses | ' | 226,000,000 | ' | ' | ' | 76,000,000 | 226,000,000 | ' | |
Tax credit carry-forward | ' | 226,000,000 | ' | ' | ' | 534,000,000 | 226,000,000 | ' | |
Investment in CENG | ' | -419,000,000 | ' | ' | ' | -541,000,000 | -419,000,000 | ' | |
Other, net | ' | 9,000,000 | ' | ' | ' | 67,000,000 | 9,000,000 | ' | |
Deferred income tax liabilities, net | ' | -5,251,000,000 | ' | ' | ' | -5,391,000,000 | -5,251,000,000 | ' | |
Unamortized investment tax credits | ' | -216,000,000 | ' | ' | ' | -454,000,000 | -216,000,000 | ' | |
Total deferred income tax liabilities, net and unamortized investment tax credits | ' | -5,467,000,000 | ' | ' | ' | -5,845,000,000 | -5,467,000,000 | ' | |
Exelon Generation Co L L C [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 250,000,000 | 104,000,000 | 431,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | 360,000,000 | 326,000,000 | 435,000,000 | |
Investment tax credit amortization | ' | ' | ' | ' | ' | -11,000,000 | -6,000,000 | -7,000,000 | |
Exelon Generation Co L L C [Member] | State Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 50,000,000 | -12,000,000 | 74,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | -34,000,000 | 88,000,000 | 123,000,000 | |
Exelon Generation Co L L C [Member] | Settlement With Taxing Authority [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Accounting for Uncertainty in Income Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Information by nature of uncertainty related to unrecognized tax benefits | ' | ' | ' | ' | ' | 55,000,000 | ' | ' | |
Exelon Generation Co L L C [Member] | More Than One Year And Within Four Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
Exelon Generation Co L L C [Member] | More Than Four Years And Within Fourteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
Exelon Generation Co L L C [Member] | More Than Fifteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | |
U.S. Federal statutory rate | ' | ' | ' | ' | ' | 35.00% | 35.00% | 35.00% | |
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | |
State income taxes, net of Federal income tax benefit | ' | ' | ' | ' | ' | 3.40% | 4.60% | 3.60% | |
Nontaxable postretirement benefits | ' | ' | ' | ' | ' | ' | -0.40% | ' | |
Health Care Reform Legislation | ' | ' | ' | ' | ' | 0.70% | 0.40% | -1.00% | |
Amortization of investment tax credit | ' | ' | ' | ' | ' | -0.60% | ' | -0.40% | |
Plant basis differences | ' | ' | ' | ' | ' | -0.80% | -0.30% | ' | |
Production Tax Credits | ' | ' | ' | ' | ' | -0.10% | ' | ' | |
Uncertain Tax Position Remeasurement | ' | ' | ' | ' | ' | ' | ' | -0.30% | |
Other | ' | ' | ' | ' | ' | 0.30% | -0.60% | 0.60% | |
Effective income tax rate | ' | ' | ' | ' | ' | 37.90% | 38.70% | 37.50% | |
Interest recognized related to uncertain tax positions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net interest receivable (payable) recognized related to uncertain tax positions | ' | 107,000,000 | ' | ' | ' | -174,000,000 | 107,000,000 | ' | |
Net interest (income) expense recognized related to uncertain tax positions | ' | ' | ' | ' | ' | 281,000,000 | -20,000,000 | -14,000,000 | |
Unsuccessful Litigation Determinations [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Expected non-cash charge to earnings | ' | ' | ' | ' | ' | 170,000,000 | ' | ' | |
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
FIN 48 Tax Remeasurement Interest Expense | ' | ' | ' | ' | ' | ' | ' | 36,000,000 | |
FIN 48 Tax Remeasurement Current Tax Expense (Benefit) | ' | ' | ' | ' | ' | ' | ' | 70,000,000 | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
IL State Deferred Income Tax Expense due to rate change | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | |
Regulatory asset related to state tax rate change | ' | ' | ' | ' | 15,000,000 | ' | ' | ' | |
Additional Income Tax Expense (Benefit) Due To 2011 New Tax Law | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | |
Income and cash tax benefit as a result of repair costs deduction [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Cash tax benefit (detriment) as a result of repair costs deduction | ' | ' | ' | ' | ' | ' | ' | 250,000,000 | |
Allocated tax benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Allocated tax benefits | ' | ' | ' | ' | ' | ' | ' | 0 | |
Non-cash contribution to equity | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | |
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits - beginning balance | ' | ' | 70,000,000 | ' | 72,000,000 | 67,000,000 | 70,000,000 | 72,000,000 | |
Changes to tax positions that only affect timing | ' | ' | ' | ' | ' | 257,000,000 | -3,000,000 | -2,000,000 | |
Unrecognized tax benefits - ending balance | ' | 67,000,000 | ' | 70,000,000 | ' | 324,000,000 | 67,000,000 | 70,000,000 | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense (Benefit) | ' | ' | ' | ' | ' | 152,000,000 | 239,000,000 | 250,000,000 | |
Operating Loss Carryforwards [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Federal net operating loss | ' | ' | ' | ' | ' | 139,000,000 | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Plant basis differences | ' | -3,537,000,000 | ' | ' | ' | -3,523,000,000 | -3,537,000,000 | ' | |
Unrealized gains on derivative financial instruments | ' | -4,000,000 | ' | ' | ' | -4,000,000 | -4,000,000 | ' | |
Deferred pension and other post-retirement obligation | ' | -598,000,000 | ' | ' | ' | -522,000,000 | -598,000,000 | ' | |
Deferred debt refinancing costs | ' | -25,000,000 | ' | ' | ' | -21,000,000 | -25,000,000 | ' | |
Net operating losses | ' | 32,000,000 | ' | ' | ' | 47,000,000 | 32,000,000 | ' | |
Other, net | ' | 83,000,000 | ' | ' | ' | 154,000,000 | 83,000,000 | ' | |
Deferred income tax liabilities, net | ' | -4,165,000,000 | ' | ' | ' | -4,110,000,000 | -4,165,000,000 | ' | |
Unamortized investment tax credits | ' | -24,000,000 | ' | ' | ' | -22,000,000 | -24,000,000 | ' | |
Total deferred income tax liabilities, net and unamortized investment tax credits | ' | -4,189,000,000 | ' | ' | ' | -4,132,000,000 | -4,189,000,000 | ' | |
Commonwealth Edison Co [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 160,000,000 | -40,000,000 | -329,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | -27,000,000 | 237,000,000 | 544,000,000 | |
Investment tax credit amortization | ' | ' | ' | ' | ' | -2,000,000 | -2,000,000 | -3,000,000 | |
Commonwealth Edison Co [Member] | State Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 50,000,000 | 6,000,000 | -123,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | -29,000,000 | 38,000,000 | 161,000,000 | |
Commonwealth Edison Co [Member] | More Than One Year And Within Four Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
Commonwealth Edison Co [Member] | More Than Four Years And Within Fourteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 9.50% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
Commonwealth Edison Co [Member] | More Than Fifteen Years [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
State Tax Legislation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Illinois state corporate tax rate | 7.75% | ' | ' | ' | ' | ' | ' | ' | |
New Illinois state corporate tax rate as a result of 2011 Illinois State Tax Rate Legislation | 7.30% | ' | ' | ' | ' | ' | ' | ' | |
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | |
U.S. Federal statutory rate | ' | ' | ' | ' | ' | 35.00% | 35.00% | 35.00% | |
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | |
State income taxes, net of Federal income tax benefit | ' | ' | ' | ' | ' | 1.60% | 2.00% | -0.50% | |
Nontaxable postretirement benefits | ' | ' | ' | ' | ' | ' | -0.30% | ' | |
Health Care Reform Legislation | ' | ' | ' | ' | ' | ' | ' | 0.00% | |
Amortization of investment tax credit | ' | ' | ' | ' | ' | -0.10% | ' | -0.30% | |
Plant basis differences | ' | ' | ' | ' | ' | -7.10% | -11.50% | -6.90% | |
Production Tax Credits | ' | ' | ' | ' | ' | 0.00% | ' | ' | |
Other | ' | ' | ' | ' | ' | -0.30% | ' | 0.00% | |
Effective income tax rate | ' | ' | ' | ' | ' | 29.10% | 25.00% | 27.30% | |
Interest recognized related to uncertain tax positions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net interest receivable (payable) recognized related to uncertain tax positions | ' | 2,000,000 | ' | ' | ' | 3,000,000 | 2,000,000 | ' | |
Net interest (income) expense recognized related to uncertain tax positions | ' | ' | ' | ' | ' | -1,000,000 | -1,000,000 | -1,000,000 | |
Status Of Like Kind Exchange Position [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Receivable from Exelon intercompany money pool | ' | 0 | ' | ' | ' | 0 | 0 | ' | |
FIN 48 Tax Remeasurement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
FIN 48 Tax Remeasurement Interest Expense | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | |
Income and cash tax benefit as a result of repair costs deduction [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Cash tax benefit (detriment) as a result of repair costs deduction | ' | ' | ' | ' | ' | ' | ' | 95,000,000 | |
Gas Distribution Repair Tax Benefit Expense | ' | ' | ' | ' | ' | ' | 29,000,000 | 29,000,000 | |
Allocated tax benefits [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Allocated tax benefits | ' | ' | ' | ' | ' | 27,000,000 | 9,000,000 | 18,000,000 | |
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits - beginning balance | ' | ' | 48,000,000 | ' | 44,000,000 | 44,000,000 | 48,000,000 | 44,000,000 | |
Increases based on tax positions related to current year | ' | ' | ' | ' | ' | ' | 0 | 4,000,000 | |
Changes to tax positions that only affect timing | ' | ' | ' | ' | ' | 0 | ' | 0 | |
Unrecognized tax benefits - ending balance | ' | 44,000,000 | ' | 48,000,000 | ' | 44,000,000 | 44,000,000 | 48,000,000 | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense (Benefit) | ' | ' | ' | ' | ' | 162,000,000 | 127,000,000 | 146,000,000 | |
Operating Loss Carryforwards [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
State net operating loss carryforward | ' | ' | ' | ' | ' | 167,000,000 | [5] | ' | ' |
Deferred taxes | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Plant basis differences | ' | -2,437,000,000 | ' | ' | ' | -2,573,000,000 | -2,437,000,000 | ' | |
Deferred pension and other post-retirement obligation | ' | -11,000,000 | ' | ' | ' | 0 | -11,000,000 | ' | |
Deferred debt refinancing costs | ' | -4,000,000 | ' | ' | ' | -3,000,000 | -4,000,000 | ' | |
Net operating losses | ' | 14,000,000 | ' | ' | ' | 11,000,000 | 14,000,000 | ' | |
Other, net | ' | 100,000,000 | ' | ' | ' | 122,000,000 | 100,000,000 | ' | |
Deferred income tax liabilities, net | ' | -2,288,000,000 | ' | ' | ' | -2,401,000,000 | -2,288,000,000 | ' | |
Unamortized investment tax credits | ' | -3,000,000 | ' | ' | ' | -3,000,000 | -3,000,000 | ' | |
Total deferred income tax liabilities, net and unamortized investment tax credits | ' | -2,291,000,000 | ' | ' | ' | -2,404,000,000 | -2,291,000,000 | ' | |
PECO Energy Co [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 126,000,000 | 88,000,000 | -71,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | 23,000,000 | 25,000,000 | 223,000,000 | |
Investment tax credit amortization | ' | ' | ' | ' | ' | -1,000,000 | -2,000,000 | -2,000,000 | |
PECO Energy Co [Member] | State Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 16,000,000 | 4,000,000 | -37,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | -2,000,000 | 12,000,000 | 33,000,000 | |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Effective Income Tax Rate Reconciliation | ' | ' | ' | ' | ' | ' | ' | ' | |
U.S. Federal statutory rate | ' | ' | ' | ' | ' | 35.00% | [6] | 35.00% | 35.00% |
Increase (decrease) due to: | ' | ' | ' | ' | ' | ' | ' | ' | |
State income taxes, net of Federal income tax benefit | ' | ' | ' | ' | ' | 4.90% | [6] | 24.30% | 5.20% |
Health Care Reform Legislation | ' | ' | ' | ' | ' | 0.20% | [6] | 11.60% | -0.50% |
Amortization of investment tax credit | ' | ' | ' | ' | ' | 0.00% | [6] | -8.60% | -0.50% |
Plant basis differences | ' | ' | ' | ' | ' | -0.20% | [6] | -9.00% | -2.00% |
Production Tax Credits | ' | ' | ' | ' | ' | 0.00% | ' | ' | |
Merger Expenses | ' | ' | ' | ' | ' | ' | -24.20% | ' | |
Other | ' | ' | ' | ' | ' | -0.90% | [6] | -13.90% | -1.70% |
Effective income tax rate | ' | ' | ' | ' | ' | 39.00% | [6] | 63.60% | 35.50% |
Interest recognized related to uncertain tax positions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net interest receivable (payable) recognized related to uncertain tax positions | ' | 0 | ' | ' | ' | ' | 0 | ' | |
Net interest (income) expense recognized related to uncertain tax positions | ' | ' | ' | ' | ' | ' | 9,000,000 | -3,000,000 | |
Income and cash tax benefit as a result of repair costs deduction [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | |
Cash tax benefit (detriment) as a result of repair costs deduction | ' | ' | ' | ' | ' | ' | ' | 27,000,000 | |
Reconciliation Of Unrecognized Tax Benefits Excluding Amounts Pertaining To Examined Tax Returns [Roll Forward] | ' | ' | ' | ' | ' | ' | ' | ' | |
Unrecognized tax benefits - beginning balance | ' | ' | 11,000,000 | ' | 73,000,000 | 0 | 11,000,000 | 73,000,000 | |
Changes to tax positions that only affect timing | ' | ' | ' | ' | ' | 0 | -11,000,000 | -62,000,000 | |
Unrecognized tax benefits - ending balance | ' | 0 | ' | 11,000,000 | ' | 0 | 0 | 11,000,000 | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense (Benefit) | ' | ' | ' | ' | ' | 134,000,000 | 7,000,000 | 75,000,000 | |
Operating Loss Carryforwards [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Federal net operating loss | ' | ' | ' | ' | ' | 31,000,000 | ' | ' | |
State net operating loss carryforward | ' | ' | ' | ' | ' | 768,000,000 | [7] | ' | ' |
Deferred taxes | ' | ' | ' | ' | ' | 41,000,000 | ' | ' | |
Valuation allowance | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Plant basis differences | ' | -1,553,000,000 | ' | ' | ' | -1,538,000,000 | -1,553,000,000 | ' | |
Deferred pension and other post-retirement obligation | ' | -12,000,000 | ' | ' | ' | -74,000,000 | -12,000,000 | ' | |
Deferred debt refinancing costs | ' | -4,000,000 | ' | ' | ' | -5,000,000 | -4,000,000 | ' | |
Net operating losses | ' | ' | ' | ' | ' | 52,000,000 | ' | ' | |
Other, net | ' | 67,000,000 | ' | ' | ' | 26,000,000 | 67,000,000 | ' | |
Deferred income tax liabilities, net | ' | -1,650,000,000 | ' | ' | ' | -1,792,000,000 | -1,650,000,000 | ' | |
Unamortized investment tax credits | ' | -6,000,000 | ' | ' | ' | -6,000,000 | -6,000,000 | ' | |
Total deferred income tax liabilities, net and unamortized investment tax credits | ' | -1,656,000,000 | ' | ' | ' | -1,798,000,000 | -1,656,000,000 | ' | |
Baltimore Gas and Electric Company [Member] | Federal Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | 9,000,000 | -97,000,000 | -71,000,000 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | 100,000,000 | 101,000,000 | 130,000,000 | |
Investment tax credit amortization | ' | ' | ' | ' | ' | -1,000,000 | -1,000,000 | -1,000,000 | |
Baltimore Gas and Electric Company [Member] | State Income Tax Expense Benefit Continuing Operations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Income Tax Expense Benefit Continuing Operations [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Current Income Tax Expense Benefit | ' | ' | ' | ' | ' | ' | ' | 0 | |
Deferred Income Tax Expense Benefit | ' | ' | ' | ' | ' | 26,000,000 | 4,000,000 | 17,000,000 | |
Exelon Corporate [Member] | ' | ' | ' | ' | ' | ' | ' | ' | |
Tax Effects Of Temporary Differences [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | |
Net operating losses | ' | $105,000,000 | ' | ' | ' | ' | $105,000,000 | ' | |
[1] | Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012 - December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012 - December 31, 2012. | ||||||||
[2] | Exelon's federal net operating loss will expire beginning in 2031 | ||||||||
[3] | Exelonbs state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||
[4] | Generationbs state net operating losses losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2014 | ||||||||
[5] | PECObs state net operating losses will expire beginning in 203 | ||||||||
[6] | BGE activity represents the activity for the twelve months ended December 31, 2012 and 2011. | ||||||||
[7] | BGEbs state net operating losses will expire beginning in 202 |
Asset_Retirement_Obligation_De
Asset Retirement Obligation (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | |||
Resulting pre-tax income (loss) from nuclear ARO adjustment | ($10,000,000) | ($28,000,000) | ' | |||
Assumed Annual After Tax Returns On Fund | 2.00% | ' | ' | |||
Assumed Annual After Tax Returns On Fund1 | 3.00% | ' | ' | |||
Decommissioning [Abstract] | ' | ' | ' | |||
Zion Station spent nuclear fuel obligation | 79,000,000 | 65,000,000 | ' | |||
ZionSolutions rent payable | 1 | ' | ' | |||
EnergySolutions letter of credit | 200,000,000 | ' | ' | |||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | |||
Current annual decommissioning costs collected | 24,000,000 | ' | ' | |||
Shortfall of decommissioning funds with recourse | 50,000,000 | ' | ' | |||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | ' | |||
NDT fund investments | 8,071,000,000 | 7,248,000,000 | ' | |||
Percent of NDT funds invested in equity | 47.00% | 48.00% | ' | |||
Percent of NDT funds invested in fixed income securities | 53.00% | 52.00% | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Annual average accretion of the ARO | 2325.00% | ' | ' | |||
Number of years used in present value measurement | '30 years | ' | ' | |||
Historical five-year annual average after-tax return on NDT funds | 11.70% | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | 9,000,000 | 10,000,000 | ' | |||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | |||
Pledged assets for Zion Station decommissioning | 458,000,000 | 614,000,000 | ' | |||
Total payable to ZionSolutions | 414,000,000 | [1] | 564,000,000 | [1] | ' | |
Current payable to ZionSolutions | 109,000,000 | [2] | 132,000,000 | [2] | ' | |
Zion Station decommissioning costs withdrawn | 498,000,000 | 335,000,000 | ' | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | |||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 406,000,000 | [3],[4],[5] | 386,000,000 | [3],[4],[5] | -74,000,000 | [3],[4],[5] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 146,000,000 | [5] | 105,000,000 | [5] | -4,000,000 | [5] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | |||
Gains on Zion Station Pledged Assets | 7,000,000 | 48,000,000 | ' | |||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 4,741,000,000 | [6] | 3,680,000,000 | ' | ||
Accretion expense | 259,000,000 | 231,000,000 | ' | |||
Net increase (decrease) resulting from updates to estimated future cash flows | -140,000,000 | 833,000,000 | ' | |||
Costs incurred to decommission retired plants | -5,000,000 | -3,000,000 | ' | |||
ARO ending balance | 4,855,000,000 | [6] | 4,741,000,000 | [6] | ' | |
Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 343,000,000 | 209,000,000 | ' | |||
Development projects | 2,000,000 | 47,000,000 | ' | |||
Accretion expense | -18,000,000 | [7] | -13,000,000 | [7] | ' | |
Net increase (decrease) resulting from updates to estimated future cash flows | 1,000,000 | [8] | 27,000,000 | [8] | ' | |
Merger with Constellation | 0 | [9] | ' | ' | ||
Payments | 13,000,000 | 11,000,000 | ' | |||
ARO ending balance | 351,000,000 | 343,000,000 | ' | |||
Minimum [Member] | ' | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Years after cessation of plant operations | '10 years | ' | ' | |||
Maximum [Member] | ' | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Years after cessation of plant operations | '70 years | ' | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | |||
Resulting pre-tax income (loss) from nuclear ARO adjustment | -10,000,000 | -28,000,000 | ' | |||
Assumed Annual After Tax Returns On Fund | 2.00% | ' | ' | |||
Assumed Annual After Tax Returns On Fund1 | 3.00% | ' | ' | |||
Decommissioning [Abstract] | ' | ' | ' | |||
Zion Station spent nuclear fuel obligation | 79,000,000 | 65,000,000 | ' | |||
ZionSolutions rent payable | 1 | ' | ' | |||
EnergySolutions letter of credit | 200,000,000 | ' | ' | |||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | |||
Current annual decommissioning costs collected | 24,000,000 | ' | ' | |||
Shortfall of decommissioning funds with recourse | 50,000,000 | ' | ' | |||
Percent of additional decommissioning shortfall with recourse | 5.00% | ' | ' | |||
NDT fund investments | 8,071,000,000 | 7,248,000,000 | ' | |||
Percent of NDT funds invested in equity | 47.00% | 48.00% | ' | |||
Percent of NDT funds invested in fixed income securities | 53.00% | 52.00% | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Annual average accretion of the ARO | 2325.00% | ' | ' | |||
Number of years used in present value measurement | '30 years | ' | ' | |||
Historical five-year annual average after-tax return on NDT funds | 11.70% | ' | ' | |||
NRC funding assurance parent guarantees | 115,000,000 | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | 9,000,000 | 10,000,000 | ' | |||
Reduction to operating and maintenance expense due to updates to estimated future cash flows | 13,000,000 | ' | ' | |||
Nuclear Decommissioning Obligation [Line Items] | ' | ' | ' | |||
Pledged assets for Zion Station decommissioning | 458,000,000 | 614,000,000 | ' | |||
Total payable to ZionSolutions | 414,000,000 | [1] | 564,000,000 | [1] | ' | |
Current payable to ZionSolutions | 109,000,000 | [2] | 132,000,000 | [2] | ' | |
Zion Station decommissioning costs withdrawn | 498,000,000 | 335,000,000 | ' | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | |||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 406,000,000 | [3],[4],[5] | 386,000,000 | [3],[4],[5] | -74,000,000 | [3],[4],[5] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 146,000,000 | [5] | 105,000,000 | [5] | -4,000,000 | [5] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | |||
Gains on Zion Station Pledged Assets | 7,000,000 | 48,000,000 | ' | |||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 4,741,000,000 | [6] | 3,680,000,000 | ' | ||
Accretion expense | 259,000,000 | 231,000,000 | ' | |||
Net increase (decrease) resulting from updates to estimated future cash flows | -140,000,000 | 833,000,000 | ' | |||
Costs incurred to decommission retired plants | -5,000,000 | -3,000,000 | ' | |||
ARO ending balance | 4,855,000,000 | [6] | 4,741,000,000 | [6] | ' | |
Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 207,000,000 | 92,000,000 | ' | |||
Development projects | 2,000,000 | 47,000,000 | ' | |||
Accretion expense | -13,000,000 | [7] | -8,000,000 | [7] | ' | |
Net increase (decrease) resulting from updates to estimated future cash flows | -11,000,000 | [8] | 18,000,000 | [8] | ' | |
Merger with Constellation | 0 | [9] | ' | ' | ||
Payments | 10,000,000 | 8,000,000 | ' | |||
ARO ending balance | 201,000,000 | 207,000,000 | ' | |||
Exelon Generation Co L L C [Member] | Minimum [Member] | ' | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Years after cessation of plant operations | '10 years | ' | ' | |||
Exelon Generation Co L L C [Member] | Maximum [Member] | ' | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Years after cessation of plant operations | '70 years | ' | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | 2,000,000 | ' | ' | |||
Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 99,000,000 | 89,000,000 | ' | |||
Accretion expense | -4,000,000 | [7] | -4,000,000 | [7] | ' | |
Net increase (decrease) resulting from updates to estimated future cash flows | 0 | [8] | 8,000,000 | [8] | ' | |
Payments | 2,000,000 | 2,000,000 | ' | |||
ARO ending balance | 101,000,000 | 99,000,000 | ' | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | 1,000,000 | ' | ' | |||
PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 29,000,000 | 28,000,000 | ' | |||
Accretion expense | -1,000,000 | [7] | -1,000,000 | [7] | ' | |
Net increase (decrease) resulting from updates to estimated future cash flows | 0 | [8] | 1,000,000 | [8] | ' | |
Payments | 0 | 1,000,000 | ' | |||
ARO ending balance | 30,000,000 | 29,000,000 | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Reduction to operating and maintenance expense due to updates to estimated future cash flows | 3,000,000 | ' | ' | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
BGE ARO costs incurred prior to merger | 8,000,000 | ' | ' | |||
Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 8,000,000 | ' | ' | |||
Net increase (decrease) resulting from updates to estimated future cash flows | 12,000,000 | [8] | ' | ' | ||
ARO ending balance | $19,000,000 | ' | $1,000,000 | |||
[1] | (a) Excludes a liability recorded within Exelonbs and Generationbs Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | |||||
[2] | (b) Included in Other current liabilities within Exelonbs and Generationbs Consolidated Balance Sheets. | |||||
[3] | Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | |||||
[4] | Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | |||||
[5] | Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||
[6] | Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | |||||
[7] | For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. | |||||
[8] | During the year ended December 31, 2013, Generation recorded an increase in operating and maintenance expense of $13 million. ComEd and PECO did not record any adjustments in operating and maintenance expense for the year ended December 31, 2013. During the year ended December 31, 2012, Generation recorded a reduction in operating and maintenance expense of $8 million. ComEd, PECO, and BGE did not record any reductions in operating and maintenance expense for the year ended December 31, 2012. | |||||
[9] | Exelonbs ARO includes $8 million of BGE costs incurred prior to the closing of Exelonbs merger with Constellation. Refer to Note 4 b Merger and Acquisitions for additional information. Includes $ 2 million, $ 1 million, and $0 million as the current portion of the ARO at December 31, 2013 for ComEd, PECO, and BGE, respectively, which is included in other current liabilities on Exelonbs and each of the respective utilitiesb Consolidated Balance Sheets. |
Nuclear_Decommissioning_Detail
Nuclear Decommissioning (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | $9,000,000 | $10,000,000 | ' | |||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | |||
Net adjustment to nuclear ARO | 114,000,000 | 1,061,000,000 | ' | |||
Resulting pre-tax income (loss) from nuclear ARO adjustment | -10,000,000 | -28,000,000 | ' | |||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | |||
NDT fund investments | 8,071,000,000 | 7,248,000,000 | ' | |||
Shortfall of decommissioning funds with recourse | 50,000,000 | ' | ' | |||
Decommissioning Shortfall Percentage | 5.00% | ' | ' | |||
Decommissioning [Abstract] | ' | ' | ' | |||
Zion Station spent nuclear fuel obligation | 79,000,000 | 65,000,000 | ' | |||
Pledged assets for Zion Station decommissioning | 458,000,000 | 614,000,000 | ' | |||
Total payable to ZionSolutions | 414,000,000 | [1] | 564,000,000 | [1] | ' | |
Current payable to ZionSolutions | 109,000,000 | [2] | 132,000,000 | [2] | ' | |
Zion Station decommissioning costs withdrawn | 498,000,000 | 335,000,000 | ' | |||
ZionSolutions rent payable | 1 | ' | ' | |||
EnergySolutions letter of credit | 200,000,000 | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Annual average accretion of the ARO | 2325.00% | ' | ' | |||
Historical five-year annual average after-tax return on NDT funds | 11.70% | ' | ' | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | |||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 406,000,000 | [3],[4],[5] | 386,000,000 | [3],[4],[5] | -74,000,000 | [3],[4],[5] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 146,000,000 | [5] | 105,000,000 | [5] | -4,000,000 | [5] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | |||
Gains on Zion Station Pledged Assets | 7,000,000 | 48,000,000 | ' | |||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 4,741,000,000 | [6] | 3,680,000,000 | ' | ||
Accretion expense | 259,000,000 | 231,000,000 | ' | |||
Net increase (decrease) resulting from updates to estimated future cash flows | -140,000,000 | 833,000,000 | ' | |||
Costs incurred to decommission retired plants | -5,000,000 | -3,000,000 | ' | |||
ARO ending balance | 4,855,000,000 | [6] | 4,741,000,000 | [6] | ' | |
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | 9,000,000 | 10,000,000 | ' | |||
Reduction to operating and maintenance expense due to updates to estimated future cash flows | 13,000,000 | ' | ' | |||
Nuclear Decommissioning Asset Retirement Obligations [Abstract] | ' | ' | ' | |||
Net adjustment to nuclear ARO | 114,000,000 | 1,061,000,000 | ' | |||
Resulting pre-tax income (loss) from nuclear ARO adjustment | -10,000,000 | -28,000,000 | ' | |||
Nuclear Decommissioning Trust Fund Investments [Abstract] | ' | ' | ' | |||
NDT fund investments | 8,071,000,000 | 7,248,000,000 | ' | |||
Shortfall of decommissioning funds with recourse | 50,000,000 | ' | ' | |||
Decommissioning Shortfall Percentage | 5.00% | ' | ' | |||
Decommissioning [Abstract] | ' | ' | ' | |||
Zion Station spent nuclear fuel obligation | 79,000,000 | 65,000,000 | ' | |||
Pledged assets for Zion Station decommissioning | 458,000,000 | 614,000,000 | ' | |||
Total payable to ZionSolutions | 414,000,000 | [1] | 564,000,000 | [1] | ' | |
Current payable to ZionSolutions | 109,000,000 | [2] | 132,000,000 | [2] | ' | |
Zion Station decommissioning costs withdrawn | 498,000,000 | 335,000,000 | ' | |||
ZionSolutions rent payable | 1 | ' | ' | |||
EnergySolutions letter of credit | 200,000,000 | ' | ' | |||
NRC Minimum Funding Requirements [Abstract] | ' | ' | ' | |||
Annual average accretion of the ARO | 2325.00% | ' | ' | |||
Historical five-year annual average after-tax return on NDT funds | 11.70% | ' | ' | |||
NRC funding assurance parent guarantees | 115,000,000 | ' | ' | |||
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items] | ' | ' | ' | |||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | 406,000,000 | [3],[4],[5] | 386,000,000 | [3],[4],[5] | -74,000,000 | [3],[4],[5] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 146,000,000 | [5] | 105,000,000 | [5] | -4,000,000 | [5] |
Footnotes To Unrealized Gains Losses On NDT Funds [Abstract] | ' | ' | ' | |||
Gains on Zion Station Pledged Assets | 7,000,000 | 48,000,000 | ' | |||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | ' | ' | ' | |||
Asset Retirement Obligation Roll Forward Analysis [Roll Forward] | ' | ' | ' | |||
ARO beginning balance | 4,741,000,000 | [6] | 3,680,000,000 | ' | ||
Accretion expense | 259,000,000 | 231,000,000 | ' | |||
Net increase (decrease) resulting from updates to estimated future cash flows | -140,000,000 | 833,000,000 | ' | |||
Costs incurred to decommission retired plants | -5,000,000 | -3,000,000 | ' | |||
ARO ending balance | 4,855,000,000 | [6] | 4,741,000,000 | [6] | ' | |
PECO Energy Co [Member] | ' | ' | ' | |||
Footnotes To Asset Retirement Obligation [Abstract] | ' | ' | ' | |||
Current Portion of ARO | $1,000,000 | ' | ' | |||
[1] | (a) Excludes a liability recorded within Exelonbs and Generationbs Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized. | |||||
[2] | (b) Included in Other current liabilities within Exelonbs and Generationbs Consolidated Balance Sheets. | |||||
[3] | Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets. | |||||
[4] | Excludes $7 million, $73 million and $48 million of net unrealized gains related to the Zion Station pledged assets in 2013, 2012 and 2011, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets. | |||||
[5] | Net unrealized gains (losses) related to Generation's NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||
[6] | Includes $9 million and $10 million as the current portion of the ARO at December 31, 2013 and 2012, respectively, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. |
Retirement_Benefits_Details
Retirement Benefits (Details) (USD $) | 12 Months Ended | |||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Defined Benefit Plan Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Abstract] | ' | ' | ' | |||
Effect of a one percentage point increase in assumed healthcare cost trend on 2010 total service and interest cost components | $90,000,000 | ' | ' | |||
Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010 | 858,000,000 | ' | ' | |||
Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components | -62,000,000 | ' | ' | |||
Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010 | -607,000,000 | ' | ' | |||
Prescription Drug Benefit Effect Of Subsidy On Net Periodic Postretirement Benefit Cost [Abstract] | ' | ' | ' | |||
Amortization of the actuarial experience loss | ' | -17,000,000 | 3,000,000 | |||
Reduction in current period service cost | ' | ' | 9,000,000 | |||
Reduction in interest cost on the APBO | ' | ' | 16,000,000 | |||
Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act | ' | -17,000,000 | 28,000,000 | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 422,000,000 | 462,000,000 | 2,360,000,000 | |||
Federal subsidy payments received not included in contributions | ' | 10,000,000 | 11,000,000 | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 825,000,000 | 820,000,000 | 542,000,000 | |||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 85,000,000 | 67,000,000 | 78,000,000 | |||
Projected Benefit Obligation In Excess Of Plan Assets [Member] | ' | ' | ' | |||
Defined Benefit Plan Pension Plans With Accumulated Benefit Obligations In Excess Of Plan Assets [Abstract] | ' | ' | ' | |||
Projected benefit obligation | 15,452,000,000 | 16,800,000,000 | ' | |||
Fair value of net plan assets | 13,564,000,000 | 13,357,000,000 | ' | |||
Accumulated Benefit Obligation In Excess Of Plan Assets [Member] | ' | ' | ' | |||
Defined Benefit Plan Pension Plans With Accumulated Benefit Obligations In Excess Of Plan Assets [Abstract] | ' | ' | ' | |||
Projected benefit obligation | 15,452,000,000 | 16,796,000,000 | ' | |||
Accumulated benefit obligation | 14,552,000,000 | 15,657,000,000 | ' | |||
Fair value of net plan assets | 13,564,000,000 | 13,353,000,000 | ' | |||
Exelon Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Regulatory asset increase (decrease) due to updated valuation adjustment | 93,000,000 | ' | ' | |||
Aoci Valuation Adjustment | -75,000,000 | ' | ' | |||
Constellation Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Regulatory asset increase (decrease) due to updated valuation adjustment | 14,000,000 | ' | ' | |||
Aoci Valuation Adjustment | 2,000,000 | ' | ' | |||
Business Services Company [Member] | ' | ' | ' | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 71,000,000 | [1] | 99,000,000 | [1] | 48,000,000 | [1] |
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 7,000,000 | 5,000,000 | 7,000,000 | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 149,000,000 | 178,000,000 | 1,070,000,000 | |||
Federal subsidy payments received not included in contributions | ' | 5,000,000 | 5,000,000 | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 347,000,000 | 341,000,000 | 249,000,000 | |||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 40,000,000 | 30,000,000 | 40,000,000 | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 122,000,000 | 138,000,000 | 977,000,000 | |||
Federal subsidy payments received not included in contributions | ' | 4,000,000 | 4,000,000 | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 309,000,000 | 282,000,000 | 213,000,000 | |||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 22,000,000 | 19,000,000 | 22,000,000 | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 31,000,000 | 45,000,000 | 137,000,000 | |||
Federal subsidy payments received not included in contributions | ' | 1,000,000 | 1,000,000 | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 43,000,000 | 50,000,000 | 32,000,000 | |||
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 8,000,000 | 7,000,000 | 9,000,000 | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 24,000,000 | 16,000,000 | 67,000,000 | |||
Federal subsidy payments received not included in contributions | ' | 2,000,000 | 3,000,000 | |||
Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract] | ' | ' | ' | |||
Amount included in capital and operating & maintenance expense | 55,000,000 | [2],[3] | 60,000,000 | [2],[3] | 51,000,000 | [2],[3] |
Defined Contribution Plan Contributions By Employer [Abstract] | ' | ' | ' | |||
Savings plan matching contributions | 8,000,000 | 7,000,000 | 7,000,000 | |||
Pension Plans Defined Benefit [Member] | ' | ' | ' | |||
Change in benefit obligation: | ' | ' | ' | |||
Net benefit obligation at beginning of year | 16,800,000,000 | 13,538,000,000 | ' | |||
Service cost | 317,000,000 | 280,000,000 | 212,000,000 | |||
Actuarial gain (loss) | -1,363,000,000 | 1,520,000,000 | ' | |||
Interest cost | 650,000,000 | 698,000,000 | 649,000,000 | |||
Plan amendments | 1,000,000 | ' | ' | |||
Acquisitions/divestitures | ' | 1,880,000,000 | ' | |||
Curtailments | ' | -10,000,000 | ' | |||
Settlements | -69,000,000 | [4] | -169,000,000 | [4] | ' | |
Special termination benefits | ' | 15,000,000 | ' | |||
Gross benefits paid | -877,000,000 | [5] | -952,000,000 | [5] | ' | |
Net benefit obligation at end of year | 15,459,000,000 | 16,800,000,000 | 13,538,000,000 | |||
Change in plan assets: | ' | ' | ' | |||
Fair value of net plan assets at beginning of year | 13,357,000,000 | 11,302,000,000 | ' | |||
Actual return on plan assets | 821,000,000 | 1,484,000,000 | ' | |||
Employer contributions | 339,000,000 | 149,000,000 | ' | |||
Gross benefits paid | -877,000,000 | [5] | -952,000,000 | [5] | ' | |
Acquisitions/divestitures - Plan Assets | ' | 1,543,000,000 | ' | |||
Settlements | -69,000,000 | [4] | -169,000,000 | [4] | ' | |
Fair value of net plan assets at end of year | 13,571,000,000 | 13,357,000,000 | 11,302,000,000 | |||
Components of net periodic benefit cost: | ' | ' | ' | |||
Service cost | 317,000,000 | 280,000,000 | 212,000,000 | |||
Interest cost | 650,000,000 | 698,000,000 | 649,000,000 | |||
Settlement charges | -9,000,000 | -31,000,000 | ' | |||
Expected return on assets | -1,015,000,000 | -988,000,000 | -939,000,000 | |||
Contractual termination benefit cost | ' | -14,000,000 | [6] | ' | ||
Net periodic benefit cost | 537,000,000 | 500,000,000 | 267,000,000 | |||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ' | ' | ' | |||
Other current liabilities | 12,000,000 | 15,000,000 | ' | |||
Pension obligations | 1,876,000,000 | 3,428,000,000 | ' | |||
Unfunded status (net benefit obligation less net plan assets) | 1,888,000,000 | 3,443,000,000 | ' | |||
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets: | ' | ' | ' | |||
Actuarial gain (Loss) | 1,169,000,000 | -1,693,000,000 | -744,000,000 | |||
Amortization of actuarial gain (loss) | -562,000,000 | -450,000,000 | -331,000,000 | |||
Current year prior service cost | ' | 1,000,000 | ' | |||
Amortization of prior service cost | -14,000,000 | -15,000,000 | -14,000,000 | |||
Curtailments | ' | -10,000,000 | ' | |||
Settlements | -8,000,000 | -31,000,000 | ' | |||
Total recognized in OCI and regulatory assets | -1,753,000,000 | [7] | 1,188,000,000 | [7] | 399,000,000 | [7] |
Changes in plan assets and benefit obligations recognized in OCI | 1,071,000,000 | 283,000,000 | 181,000,000 | |||
Changes in plan assets and benefit obligations recognized in regulatory assets | 682,000,000 | 904,000,000 | 218,000,000 | |||
Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax [Abstract] | ' | ' | ' | |||
Prior service cost (credit) | 62,000,000 | 76,000,000 | ' | |||
Actuarial loss | 6,192,000,000 | 7,931,000,000 | ' | |||
Total components of periodic benefit cost not yet recognized | 6,254,000,000 | [8] | 8,007,000,000 | [8] | ' | |
Benefits included in accumulated other comprehensive income | 3,523,000,000 | 4,594,000,000 | ' | |||
Benefits included in regulatory assets | 2,731,000,000 | 3,413,000,000 | ' | |||
Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets To Be Amortized Before Tax [Abstract] | ' | ' | ' | |||
Prior service cost (credit) | 14,000,000 | ' | ' | |||
Actuarial loss | 427,000,000 | ' | ' | |||
Total components of periodic benefit cost to be amortized | 441,000,000 | [9] | ' | ' | ||
Benefits included in accumulated other comprehensive income | 232,000,000 | ' | ' | |||
Benefits included in regulatory assets | 209,000,000 | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 339,000,000 | 149,000,000 | 2,094,000,000 | [10] | ||
Defined Benefit Plan Estimated Future Benefit Payments [Abstract] | ' | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year One | 929,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Two | 851,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Three | 873,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Four | 902,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Five | 1,015,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Five Fiscal Years Thereafter | 5,257,000,000 | ' | ' | |||
Total estimated future benefits payments through 2020 | 9,827,000,000 | ' | ' | |||
Pension Plans Defined Benefit [Member] | Remeasurement [Member] | ' | ' | ' | |||
Design Changes Impact [Abstract] | ' | ' | ' | |||
Discount rate used for remeasurement due to design changes | 4.21% | ' | ' | |||
Pension Plans Defined Benefit [Member] | Equity Securities [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 31.00% | ' | ' | |||
Total weighted average asset allocation | 35.00% | 35.00% | ' | |||
Pension Plans Defined Benefit [Member] | Fixed Income Securities [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 38.00% | ' | ' | |||
Total weighted average asset allocation | 37.00% | 40.00% | ' | |||
Pension Plans Defined Benefit [Member] | Alternative Investments [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 31.00% | [11] | ' | ' | ||
Total weighted average asset allocation | 28.00% | [11] | 25.00% | [11] | ' | |
Pension Plans Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Benefit obligation increase (decrease) reflecting actual census data | 8,000,000 | ' | ' | |||
Pension Plans Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Benefit obligation increase (decrease) reflecting actual census data | 23,000,000 | ' | ' | |||
Pension Plans Defined Benefit [Member] | Business Services Company [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 91,000,000 | 63,000,000 | 157,000,000 | [10] | ||
Pension Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 119,000,000 | 48,000,000 | 954,000,000 | [10] | ||
Pension Plans Defined Benefit [Member] | Commonwealth Edison Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 118,000,000 | 25,000,000 | 873,000,000 | [10] | ||
Pension Plans Defined Benefit [Member] | PECO Energy Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 11,000,000 | 13,000,000 | 110,000,000 | [10] | ||
Pension Plans Defined Benefit [Member] | Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | ' | 54,000,000 | 197,000,000 | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ' | |||
Change in benefit obligation: | ' | ' | ' | |||
Net benefit obligation at beginning of year | 4,820,000,000 | 4,062,000,000 | ' | |||
Service cost | 162,000,000 | 156,000,000 | 142,000,000 | |||
Actuarial gain (loss) | -551,000,000 | 313,000,000 | ' | |||
Interest cost | 194,000,000 | 205,000,000 | 207,000,000 | |||
Plan participants' contributions | 34,000,000 | 34,000,000 | ' | |||
Plan amendments | 15,000,000 | -103,000,000 | ' | |||
Acquisitions/divestitures | ' | 362,000,000 | ' | |||
Curtailments | ' | -8,000,000 | ' | |||
Special termination benefits | ' | 6,000,000 | ' | |||
Gross benefits paid | -223,000,000 | -219,000,000 | ' | |||
Federal subsidy on benefits paid | ' | 12,000,000 | ' | |||
Net benefit obligation at end of year | 4,451,000,000 | 4,820,000,000 | 4,062,000,000 | |||
Reinsurance proceeds received | ' | 1.3 | ' | |||
Change in plan assets: | ' | ' | ' | |||
Fair value of net plan assets at beginning of year | 2,135,000,000 | 1,797,000,000 | ' | |||
Actual return on plan assets | 209,000,000 | 197,000,000 | ' | |||
Employer contributions | 83,000,000 | 325,000,000 | ' | |||
Plan participants' contributions | 34,000,000 | 34,000,000 | ' | |||
Gross benefits paid | -223,000,000 | -219,000,000 | ' | |||
Benefits paid net | -223,000,000 | [5] | -218,000,000 | [5] | ' | |
Fair value of net plan assets at end of year | 2,238,000,000 | 2,135,000,000 | 1,797,000,000 | |||
Components of net periodic benefit cost: | ' | ' | ' | |||
Service cost | 162,000,000 | 156,000,000 | 142,000,000 | |||
Interest cost | 194,000,000 | 205,000,000 | 207,000,000 | |||
Expected return on assets | -132,000,000 | -115,000,000 | -111,000,000 | |||
Curtailments charges | ' | -7,000,000 | ' | |||
Contractual termination benefit cost | ' | -6,000,000 | [6] | ' | ||
Net periodic benefit cost | 288,000,000 | 320,000,000 | 275,000,000 | |||
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract] | ' | ' | ' | |||
Other current liabilities | 23,000,000 | 23,000,000 | ' | |||
Non-pension postretirement benefit obligations | 2,190,000,000 | 2,662,000,000 | ' | |||
Unfunded status (net benefit obligation less net plan assets) | 2,213,000,000 | 2,685,000,000 | ' | |||
Changes in plan assets and benefit obligations recognized in OCI and regulatory assets: | ' | ' | ' | |||
Actuarial gain (Loss) | 628,000,000 | -304,000,000 | -74,000,000 | |||
Amortization of actuarial gain (loss) | -83,000,000 | -81,000,000 | -66,000,000 | |||
Current year prior service cost | 15,000,000 | -109,000,000 | ' | |||
Amortization of prior service cost | 19,000,000 | 17,000,000 | 38,000,000 | |||
Current year transition (asset) obligation | ' | 1,000,000 | ' | |||
Amortization of transition obligation | 0 | -11,000,000 | -9,000,000 | |||
Curtailments | ' | -1,000,000 | ' | |||
Total recognized in OCI and regulatory assets | -677,000,000 | [7] | 120,000,000 | [7] | 37,000,000 | [7] |
Changes in plan assets and benefit obligations recognized in OCI | 352,000,000 | 39,000,000 | 13,000,000 | |||
Changes in plan assets and benefit obligations recognized in regulatory assets | 325,000,000 | 81,000,000 | 24,000,000 | |||
Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax [Abstract] | ' | ' | ' | |||
Prior service cost (credit) | -73,000,000 | -107,000,000 | ' | |||
Actuarial loss | 474,000,000 | 1,185,000,000 | ' | |||
Total components of periodic benefit cost not yet recognized | 401,000,000 | [8] | 1,078,000,000 | [8] | ' | |
Benefits included in accumulated other comprehensive income | 161,000,000 | 514,000,000 | ' | |||
Benefits included in regulatory assets | 240,000,000 | 564,000,000 | ' | |||
Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets To Be Amortized Before Tax [Abstract] | ' | ' | ' | |||
Prior service cost (credit) | -16,000,000 | ' | ' | |||
Actuarial loss | 32,000,000 | ' | ' | |||
Total components of periodic benefit cost to be amortized | 16,000,000 | [9] | ' | ' | ||
Benefits included in accumulated other comprehensive income | 7,000,000 | ' | ' | |||
Benefits included in regulatory assets | 9,000,000 | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 83,000,000 | [12] | 323,000,000 | [12] | 277,000,000 | [12] |
Defined Benefit Plan Estimated Future Benefit Payments [Abstract] | ' | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year One | 204,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Two | 210,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Three | 219,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Four | 228,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Year Five | 238,000,000 | ' | ' | |||
Defined Benefit Plan Expected Future Benefit Payments In Five Fiscal Years Thereafter | 1,383,000,000 | ' | ' | |||
Total estimated future benefits payments through 2020 | 2,482,000,000 | ' | ' | |||
Disclosure Of Expected Gross Prescription Drug Subsidy Receipts [Abstract] | ' | ' | ' | |||
Prescription Drug Subsidy Receipts Year One | 0 | ' | ' | |||
Prescription Drug Subsidy Receipts Year Two | 0 | ' | ' | |||
Prescription Drug Subsidy Receipts Year Three | 0 | ' | ' | |||
Prescription Drug Subsidy Receipts Year Four | 0 | ' | ' | |||
Prescription Drug Subsidy Receipts Year Five | 0 | ' | ' | |||
Prescription Drug Subsidy Receipts Five Fiscal Years Thereafter | 0 | ' | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Remeasurement [Member] | ' | ' | ' | |||
Design Changes Impact [Abstract] | ' | ' | ' | |||
Discount rate used for remeasurement due to design changes | 4.66% | ' | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Equity Securities [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 41.00% | ' | ' | |||
Total weighted average asset allocation | 45.00% | 46.00% | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Fixed Income Securities [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 39.00% | ' | ' | |||
Total weighted average asset allocation | 37.00% | 40.00% | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Alternative Investments [Member] | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Asset Allocations [Abstract] | ' | ' | ' | |||
Target asset allocation percentage | 20.00% | [11] | ' | ' | ||
Total weighted average asset allocation | 18.00% | [11] | 14.00% | [11] | ' | |
Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Benefit obligation increase (decrease) reflecting actual census data | -39,000,000 | ' | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ' | ' | ' | |||
Valuation Adjustment Impact [Abstract] | ' | ' | ' | |||
Benefit obligation increase (decrease) reflecting actual census data | -12,000,000 | ' | ' | |||
Other Postretirement Benefit Plans Defined Benefit [Member] | Business Services Company [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 5,000,000 | [12] | 24,000,000 | [12] | 20,000,000 | [12] |
Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 30,000,000 | [12] | 135,000,000 | [12] | 121,000,000 | [12] |
Other Postretirement Benefit Plans Defined Benefit [Member] | Commonwealth Edison Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 4,000,000 | [12] | 119,000,000 | [12] | 108,000,000 | [12] |
Other Postretirement Benefit Plans Defined Benefit [Member] | PECO Energy Co [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | 20,000,000 | [12] | 33,000,000 | [12] | 28,000,000 | [12] |
Other Postretirement Benefit Plans Defined Benefit [Member] | Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Pension And Other Postretirement Benefit Contributions [Abstract] | ' | ' | ' | |||
Pension and non-pension postretirement benefit contributions | $24,000,000 | [12],[13] | $12,000,000 | [12],[13] | ' | |
[1] | These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge. | |||||
[2] | The amounts included in capital and operating and maintenance expense for the years ended December 31, 2012 and 2011 include $12 million and $51 million, respectively, in costs incurred prior to the closing of Exelonbs merger with Constellation on March 12, 2012. These amounts are not included in Exelonbs capital expenditures and operating and maintenance expense for the years ended December 31, 2012 and 2011. | |||||
[3] | BGEbs pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012. | |||||
[4] | Represents cash settlements only. | |||||
[5] | Exelon's other postretirement benefits paid for the year ended December 31, 2012 are net of $1.3 million of reinsurance proceeds received from the Department of Health and Human Services as part of the Early Retiree Reinsurance Program pursuant to the Affordable Care Act of 2010. In 2013, the Program was no longer accepting applications for reimbursement | |||||
[6] | ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012. | |||||
[7] | Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $399 million loss related to pension benefits, $181 million and $218 million were recognized in AOCI and regulatory assets, respectively, during 2011. Of the $37 million loss related to other postretirement benefits, $13 million and $24 million were recognized in AOCI and regulatory assets, respectively, during 2011. | |||||
[8] | Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013. Of the $8,007 million related to pension benefits, $4,594 million and $3,413 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. Of the $1,078 million related to other postretirement benefits, $514 million and $564 million are included in AOCI and regulatory assets, respectively, at December 31, 2012. | |||||
[9] | Of the $441 million related to pension benefits at December 31, 2013, $232 million and $209 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively. Of the $16 million related to other postretirement benefits at December 31, 2013, $7 million and $9 million are expected to be amortized from AOCI and regulatory assets in 2013, respectively | |||||
[10] | The increase in 2011 pension contributions was related to Exelonbs $2.1 billion contribution to its pension plans as a result of accelerated cash benefits associated with the Tax Relief Act of 2010. | |||||
[11] | Alternative investments include private equity, hedge funds and real estate | |||||
[12] | The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012, and $11 million, $5 million, $4 million, $1 million and $3 million, respectively, in 2011. Effective January 1, 2013, Exelon is no longer receiving this subsidy | |||||
[13] | BGEbs pension benefit contributions for 2012 and 2011 exclude $0 million and $54 million, respectively, of pension contributions made by BGE prior to the closing of Exelonbs merger with Constellation on March 12, 2012. BGEbs other postretirement benefit payments for 2012 and 2011 exclude $4 million and $13 million, respectively, of other postretirement benefit payments made by BGE prior to the closing of Exelonbs merger with Constellation on March 12, 2012. These pre-merger contributions are not included in Exelonbs financial statements but are reflected in BGEbs financial statements. |
Retirement_Benefits_Assumption
Retirement Benefits - Assumptions Used In Calculations (Details) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||
Pension Plans Defined Benefit [Member] | ' | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract] | ' | ' | ' | ' | |||
Discount rate | ' | 4.80% | 3.92% | 4.74% | |||
Rate of compensation increase | ' | 3.25% | [1] | 3.25% | [2] | 3.75% | |
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' | |||
Expected return on plan assets | 7.00% | 7.50% | [3] | 7.50% | [3] | 8.00% | [3] |
Discount rate | ' | 3.92% | [4] | 3.71% | [5] | 5.26% | |
Rate of compensation increase | ' | 3.75% | [2] | 3.75% | 3.75% | ||
Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ' | ' | |||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation [Abstract] | ' | ' | ' | ' | |||
Discount rate | ' | 4.90% | 4.00% | 4.80% | |||
Rate of compensation increase | ' | 3.25% | [1] | 3.25% | [2] | 3.75% | |
Healthcare cost trend on covered charges | ' | 6.00% | 6.50% | 6.50% | |||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract] | ' | ' | ' | ' | |||
Expected return on plan assets | 6.59% | 6.45% | [3] | 6.68% | [3] | 7.08% | [3] |
Discount rate | ' | 4.00% | [4] | 3.72% | [5] | 5.30% | |
Rate of compensation increase | ' | 3.75% | [2] | 3.75% | 3.75% | ||
Healthcare cost trend on covered charges | ' | 6.50% | 6.50% | 7.00% | |||
[1] | 3.25% for 2014-2018 and 3.75% thereafter. | ||||||
[2] | 3.25% for 2013-2017 and 3.75% thereafter | ||||||
[3] | Not applicable to pension and other postretirement benefit plans that do not have plan assets. | ||||||
[4] | The discount rates above represent the initial discount rates used to establish Exelonbs pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurements. | ||||||
[5] | The discount rates above represent the initial discounts rates used to establish Exelonbs pension and other postretirement benefits costs for 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements. |
Retirement_Benefits_Fair_Value
Retirement Benefits - Fair Value Recurring Basis (Details) (USD $) | Dec. 31, 2013 | Dec. 31, 2012 | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | $1,230,000,000 | [1] | $995,000,000 | [1] |
Fixed income [Abstract] | ' | ' | ||
Total pension and other postretirement benefit plan assets | 15,766,000,000 | [2] | 15,411,000,000 | |
Fair Value Defined Benefit Plan Measured On Recurring Basis Financial Statement Footnotes [Abstract] | ' | ' | ||
Derivative, Notional Amount | 2,651,000,000 | 2,498,000,000 | ||
Net Assets Pending Transactions Excluded | 43,000,000 | 81,000,000 | ||
Pension Plans Defined Benefit [Member] | ' | ' | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | ' | 1,000,000 | ||
Equity Securities [Abstract] | ' | ' | ||
Individually held | 3,092,000,000 | 2,562,000,000 | ||
Commingled funds | 1,167,000,000 | 1,111,000,000 | ||
Mutual funds | 270,000,000 | 323,000,000 | ||
Equity securities subtotal | 4,529,000,000 | 3,996,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 917,000,000 | 1,037,000,000 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 88,000,000 | 108,000,000 | ||
Foreign debt | 205,000,000 | 252,000,000 | ||
Corporate debt securities | 2,968,000,000 | 3,330,000,000 | ||
Federal agency mortgage-backed securities | 90,000,000 | 117,000,000 | ||
Non-federal agency mortgage-backed securities | 26,000,000 | 28,000,000 | ||
Commingled funds fixed income | 558,000,000 | 274,000,000 | ||
Mutual funds fixed income | 320,000,000 | 295,000,000 | ||
Fixed income subtotal | 5,045,000,000 | 5,429,000,000 | [2] | |
Hedge funds | 2,305,000,000 | 2,315,000,000 | ||
Private equity | 806,000,000 | 754,000,000 | ||
Real estate | 848,000,000 | 781,000,000 | ||
Pension plan assets | 13,533,000,000 | 13,276,000,000 | ||
Pension Plans Defined Benefit [Member] | Individually Held [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 264,000,000 | 280,000,000 | ||
Pension Plans Defined Benefit [Member] | Commingled Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 2,000,000 | 75,000,000 | ||
Pension Plans Defined Benefit [Member] | Real Estate Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 582,000,000 | 426,000,000 | ||
Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Derivative Instruments | 7,000,000 | [3] | 9,000,000 | [3] |
Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Derivative Instruments | -134,000,000 | [3] | ' | |
Hedge funds | ' | -21,000,000 | [3] | |
Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | 51,000,000 | 44,000,000 | ||
Equity Securities [Abstract] | ' | ' | ||
Individually held | 286,000,000 | 198,000,000 | ||
Commingled funds | 515,000,000 | 530,000,000 | ||
Mutual funds | 164,000,000 | 230,000,000 | ||
Equity securities subtotal | 965,000,000 | 958,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 18,000,000 | 18,000,000 | ||
Debt securities issued by states of the United States and political subdivisions of the states | 149,000,000 | 125,000,000 | ||
Foreign debt | 2,000,000 | 3,000,000 | ||
Corporate debt securities | 50,000,000 | 50,000,000 | ||
Federal agency mortgage-backed securities | 45,000,000 | 52,000,000 | ||
Non-federal agency mortgage-backed securities | 7,000,000 | 6,000,000 | ||
Commingled funds fixed income | 218,000,000 | 271,000,000 | ||
Mutual funds fixed income | 305,000,000 | 297,000,000 | ||
Fixed income subtotal | 794,000,000 | 822,000,000 | ||
Hedge funds | 299,000,000 | 200,000,000 | ||
Private equity | 2,000,000 | 1,000,000 | ||
Real estate | 122,000,000 | 110,000,000 | ||
Postretirement benefit plan subtotal | 2,233,000,000 | 2,135,000,000 | ||
Other Postretirement Benefit Plans Defined Benefit [Member] | Individually Held [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 8,000,000 | 7,000,000 | ||
Other Postretirement Benefit Plans Defined Benefit [Member] | Commingled Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | ' | 2,000,000 | ||
Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 114,000,000 | 101,000,000 | ||
Fair Value Inputs Level 1 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total pension and other postretirement benefit plan assets | 5,368,000,000 | [2] | 4,999,000,000 | |
Fair Value Inputs Level 1 [Member] | Pension Plans Defined Benefit [Member] | ' | ' | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | ' | 1,000,000 | ||
Equity Securities [Abstract] | ' | ' | ||
Individually held | 3,090,000,000 | 2,562,000,000 | ||
Mutual funds | 270,000,000 | 323,000,000 | ||
Equity securities subtotal | 3,360,000,000 | 2,885,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 908,000,000 | 1,037,000,000 | ||
Mutual funds fixed income | 5,000,000 | 4,000,000 | ||
Fixed income subtotal | 913,000,000 | 1,041,000,000 | [2] | |
Real estate | 264,000,000 | 280,000,000 | ||
Pension plan assets | 4,537,000,000 | 4,207,000,000 | ||
Fair Value Inputs Level 1 [Member] | Pension Plans Defined Benefit [Member] | Individually Held [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Hedge funds | ' | 280,000,000 | ||
Real estate | 264,000,000 | ' | ||
Fair Value Inputs Level 1 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ||
Defined Benefit Plan Disclosure [Line Items] | ' | ' | ||
Cash equivalents | 51,000,000 | 44,000,000 | ||
Equity Securities [Abstract] | ' | ' | ||
Individually held | 286,000,000 | 198,000,000 | ||
Mutual funds | 164,000,000 | 230,000,000 | ||
Equity securities subtotal | 450,000,000 | 428,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 17,000,000 | 18,000,000 | ||
Mutual funds fixed income | 305,000,000 | 295,000,000 | ||
Fixed income subtotal | 322,000,000 | 313,000,000 | ||
Real estate | 8,000,000 | 7,000,000 | ||
Postretirement benefit plan subtotal | 831,000,000 | 792,000,000 | ||
Fair Value Inputs Level 1 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Individually Held [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 8,000,000 | 7,000,000 | ||
Fair Value Inputs Level 2 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total pension and other postretirement benefit plan assets | 7,813,000,000 | [2] | 7,889,000,000 | |
Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | 1,167,000,000 | 1,111,000,000 | ||
Mutual funds | ' | 0 | ||
Equity securities subtotal | 1,167,000,000 | 1,111,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 9,000,000 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 88,000,000 | 108,000,000 | ||
Foreign debt | 205,000,000 | 252,000,000 | ||
Corporate debt securities | 2,927,000,000 | 3,330,000,000 | ||
Federal agency mortgage-backed securities | 90,000,000 | 117,000,000 | ||
Non-federal agency mortgage-backed securities | 26,000,000 | 28,000,000 | ||
Commingled funds fixed income | 558,000,000 | 274,000,000 | ||
Mutual funds fixed income | 315,000,000 | 291,000,000 | ||
Fixed income subtotal | 4,091,000,000 | 4,388,000,000 | [2] | |
Hedge funds | 1,266,000,000 | 1,080,000,000 | ||
Real estate | 2,000,000 | 75,000,000 | ||
Pension plan assets | 6,526,000,000 | 6,654,000,000 | ||
Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Commingled Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 2,000,000 | 75,000,000 | ||
Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Assets [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Derivative Instruments | 7,000,000 | [3] | 9,000,000 | [3] |
Fair Value Inputs Level 2 [Member] | Pension Plans Defined Benefit [Member] | Derivative Financial Instruments Liabilities [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Derivative Instruments | -134,000,000 | [3] | -21,000,000 | [3] |
Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Commingled funds | 515,000,000 | 530,000,000 | ||
Equity securities subtotal | 515,000,000 | 530,000,000 | ||
Fixed income [Abstract] | ' | ' | ||
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies | 1,000,000 | ' | ||
Debt securities issued by states of the United States and political subdivisions of the states | 149,000,000 | 125,000,000 | ||
Foreign debt | 2,000,000 | 3,000,000 | ||
Corporate debt securities | 50,000,000 | 50,000,000 | ||
Federal agency mortgage-backed securities | 45,000,000 | 52,000,000 | ||
Non-federal agency mortgage-backed securities | 7,000,000 | 6,000,000 | ||
Commingled funds fixed income | 218,000,000 | 271,000,000 | ||
Mutual funds fixed income | ' | 2,000,000 | ||
Fixed income subtotal | 472,000,000 | 509,000,000 | ||
Hedge funds | 295,000,000 | 188,000,000 | ||
Real estate | 5,000,000 | 8,000,000 | ||
Postretirement benefit plan subtotal | 1,287,000,000 | 1,235,000,000 | ||
Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Commingled Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | ' | 2,000,000 | ||
Fair Value Inputs Level 2 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 5,000,000 | 6,000,000 | ||
Fair Value Inputs Level 3 [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Total pension and other postretirement benefit plan assets | 2,585,000,000 | [2] | 2,523,000,000 | |
Fair Value Inputs Level 3 [Member] | Pension Plans Defined Benefit [Member] | ' | ' | ||
Equity Securities [Abstract] | ' | ' | ||
Individually held | 2,000,000 | ' | ||
Equity securities subtotal | 2,000,000 | ' | ||
Fixed income [Abstract] | ' | ' | ||
Corporate debt securities | 41,000,000 | ' | ||
Fixed income subtotal | 41,000,000 | ' | ||
Hedge funds | 1,039,000,000 | 1,235,000,000 | ||
Private equity | 806,000,000 | 754,000,000 | ||
Real estate | 582,000,000 | 426,000,000 | ||
Pension plan assets | 2,470,000,000 | 2,415,000,000 | ||
Fair Value Inputs Level 3 [Member] | Pension Plans Defined Benefit [Member] | Real Estate Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | 582,000,000 | 426,000,000 | ||
Fair Value Inputs Level 3 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Hedge funds | 4,000,000 | 12,000,000 | ||
Private equity | 2,000,000 | 1,000,000 | ||
Real estate | 109,000,000 | 95,000,000 | ||
Postretirement benefit plan subtotal | 115,000,000 | 108,000,000 | ||
Fair Value Inputs Level 3 [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | Real Estate Funds [Member] | ' | ' | ||
Fixed income [Abstract] | ' | ' | ||
Real estate | $109,000,000 | $95,000,000 | ||
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||
[2] | Excludes net assets of $43 million and $81 million at December 31, 2013 and 2012, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases. | |||
[3] | Derivative instruments have a total notional amount of $2,651 million and $2,498 million at December 31, 2013 and 2012, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the companybs exposure to credit or market loss. |
Retirement_Benefits_Fair_Value1
Retirement Benefits - Fair Value Unobservable (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Pension Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | $2,415 | $2,426 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 292 | 217 |
Relating to assets sold during the period | -1 | ' |
Purchases | 752 | 689 |
Sales | -167 | -6 |
Settlements | -198 | -160 |
Transfers into (out of) Level 3 | -623 | -751 |
Fair value of net plan assets at the Ending of year | 2,470 | 2,415 |
Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 108 | 165 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 12 | 14 |
Purchases | 4 | 123 |
Sales | -1 | ' |
Settlements | -4 | -1 |
Transfers into (out of) Level 3 | -4 | -193 |
Fair value of net plan assets at the Ending of year | 115 | 108 |
Hedge Fund Investments [Member] | Pension Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 1,235 | 1,525 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 143 | 138 |
Relating to assets sold during the period | 3 | ' |
Purchases | 360 | 447 |
Sales | -76 | -6 |
Settlements | -3 | -4 |
Transfers into (out of) Level 3 | -623 | -865 |
Fair value of net plan assets at the Ending of year | 1,039 | 1,235 |
Hedge Fund Investments [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 12 | 157 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 1 | 11 |
Purchases | 0 | 32 |
Sales | -1 | ' |
Settlements | -4 | ' |
Transfers into (out of) Level 3 | -4 | -188 |
Fair value of net plan assets at the Ending of year | 4 | 12 |
Commingled Funds In Private Equity Investments [Member] | Pension Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 754 | 672 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 86 | 55 |
Purchases | 123 | 108 |
Sales | 0 | ' |
Settlements | -157 | -128 |
Transfers into (out of) Level 3 | 0 | 47 |
Fair value of net plan assets at the Ending of year | 806 | 754 |
Commingled Funds In Private Equity Investments [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 1 | 1 |
Actual return on plan assets: | ' | ' |
Purchases | 1 | 0 |
Fair value of net plan assets at the Ending of year | ' | 1 |
Commingled Funds In Equity And Fixed Income Securities [Member] | Pension Plans Defined Benefit [Member] | ' | ' |
Actual return on plan assets: | ' | ' |
Purchases | 41 | ' |
Fair value of net plan assets at the Ending of year | 41 | ' |
Commingled Funds In Equity And Fixed Income Securities [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' |
Actual return on plan assets: | ' | ' |
Fair value of net plan assets at the Ending of year | 2 | ' |
Commingled Funds In Direct Real Estate [Member] | Pension Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 426 | 229 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 63 | 24 |
Relating to assets sold during the period | -4 | ' |
Purchases | 226 | 134 |
Sales | -91 | 0 |
Settlements | -38 | -28 |
Transfers into (out of) Level 3 | 0 | 67 |
Fair value of net plan assets at the Ending of year | 582 | 426 |
Commingled Funds In Direct Real Estate [Member] | Other Postretirement Benefit Plans Defined Benefit [Member] | ' | ' |
Defined Benefit Plan Disclosure [Line Items] | ' | ' |
Fair value of net plan assets at the begining of year | 95 | 7 |
Actual return on plan assets: | ' | ' |
Relating to assets still held at the reporting date | 11 | 3 |
Purchases | 3 | 91 |
Settlements | 0 | -1 |
Transfers into (out of) Level 3 | 0 | -5 |
Fair value of net plan assets at the Ending of year | 109 | 95 |
CommingledFundsInEquitySecuritiesMember [Member] | Pension Plans Defined Benefit [Member] | ' | ' |
Actual return on plan assets: | ' | ' |
Purchases | 2 | ' |
Fair value of net plan assets at the Ending of year | $2 | ' |
Retirement_Benefits_Additional
Retirement Benefits - Additional (Details) (USD $) | 3 Months Ended | 12 Months Ended | 12 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Mar. 31, 2010 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Mar. 31, 2010 | Dec. 31, 2014 | Mar. 31, 2010 | Dec. 31, 2014 | Mar. 31, 2010 | Dec. 31, 2014 | Mar. 31, 2010 | Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2011 |
Projected Benefit Obligation In Excess Of Plan Assets [Member] | Projected Benefit Obligation In Excess Of Plan Assets [Member] | Accumulated Benefit Obligation In Excess Of Plan Assets [Member] | Accumulated Benefit Obligation In Excess Of Plan Assets [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Benefit Obligation and Plan Assets, and Funded Status [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Funded status of the pension and other postretirement benefit obligations | ' | ' | ' | ' | ' | 88.00% | 80.00% | 93.00% | 85.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Healthcare Reform Legislation Impact [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
After-tax charge to income tax expense as a result of health care reform legislation | $65 | ' | ' | ' | ' | ' | ' | ' | ' | $24 | ' | $11 | ' | $9 | ' | $3 | ' | ' | ' |
Excise tax on certain high-cost benefit plans | ' | ' | ' | ' | 40.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Components Of Net Periodic Benefit Costs [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act | ' | -17 | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Defined Benefit Plan Contributions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Expected qualified pension plan contributions | ' | ' | ' | 264 | ' | ' | ' | ' | ' | ' | 118 | ' | 119 | ' | 11 | ' | ' | ' | ' |
Expected non-qualified pension plan contributions | ' | ' | ' | 12 | ' | ' | ' | ' | ' | ' | 5 | ' | 1 | ' | ' | ' | 1 | ' | ' |
Expected other postretirement benefit plan contributions | ' | ' | ' | 430 | ' | ' | ' | ' | ' | ' | 168 | ' | 197 | ' | 19 | ' | 17 | 4 | 13 |
Securities Lending Program [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair value of securities on loan | ' | ' | ' | ' | 17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Fair value of cash and non-cash collateral received for loan securities | ' | ' | ' | ' | $17 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Severance_and_Plant_Retirement
Severance and Plant Retirements (Details) (USD $) | 12 Months Ended | 37 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | ||
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' | ' | ' | ||
Severance charges recorded | $6 | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Start | 111 | ' | ' | ' | ||
Severance Charges | ' | 124 | [1] | ' | ' | |
Non-Merger Severance Costs | 0 | 99 | ' | ' | ||
Stock Compensation Expense | ' | 7 | [1] | ' | ' | |
Other Expense Charges | ' | 7 | [1] | ' | 7 | [1] |
Total Severance Benefits | ' | 138 | [1] | ' | 138 | [1] |
Payments | 64 | 27 | ' | ' | ||
Restructuring Reserve, Period End | 53 | 111 | ' | 111 | ||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ||
BGE rate credit of $100 per residential customer | ' | 113 | [2] | ' | ' | |
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | ' | 113.5 | ' | ' | ||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | ' | 2 | ' | ' | ||
Charitable contributions at $7 million per year for 10 years | ' | 70 | ' | ' | ||
State funding for offshore wind development projects | ' | 32 | ' | ' | ||
Miscellaneous tax benefits | ' | -2 | ' | ' | ||
Total | ' | 328.5 | ' | ' | ||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | ||
Inventory write down related to plant retirements | 9 | ' | ' | ' | ||
Severance [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | 5 | 124 | ' | ' | ||
One-time Termination Benefits [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Expense | 3 | ' | ' | ' | ||
Other Severance Charges [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | 18 | 19 | 5 | ' | ||
Other Expense Charges | ' | 7 | ' | 7 | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ||
Corporate Restructuring Severance Benefit Obligation [Line Items] | ' | ' | ' | ' | ||
Severance charges recorded | 6 | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Start | 33 | ' | ' | ' | ||
Severance Charges | ' | 80 | [1] | ' | ' | |
Non-Merger Severance Costs | 0 | 34 | ' | ' | ||
Stock Compensation Expense | ' | 4 | [1] | ' | ' | |
Other Expense Charges | ' | 4 | [1] | ' | 4 | [1] |
Total Severance Benefits | ' | 88 | [1] | ' | 88 | [1] |
Payments | 24 | 9 | ' | ' | ||
Severance Costs Intercompany Allocation | 5 | ' | ' | ' | ||
Restructuring Reserve, Period End | 10 | 33 | ' | 33 | ||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ||
Charitable contributions at $7 million per year for 10 years | ' | 35 | ' | ' | ||
Total | ' | 35 | ' | ' | ||
Plant Retirements Reserve [LineItems] | ' | ' | ' | ' | ||
Plant Retirement Cash Payments | 2 | 4 | 4 | ' | ||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | ||
Plant retirement costs incurred | ' | ' | ' | 46 | ||
Severance benefits expense related to plant retirements | 1 | ' | 4 | 14 | ||
Inventory write down related to plant retirements | 9 | 6 | ' | 18 | ||
Plant shut-down costs | 1 | 11 | 2 | 14 | ||
Exelon Generation Co L L C [Member] | Eddystone Generating Station [Member] | ' | ' | ' | ' | ||
Plant Retirements Reliability Must Run Revenue [Abstract] | ' | ' | ' | ' | ||
PlantMonthlyRevenueDuringReliabilityMustRunPeriod | 6 | ' | ' | ' | ||
Exelon Generation Co L L C [Member] | Schuylkill Station Unit One [Member] | ' | ' | ' | ' | ||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | ||
Oil/gas-fired generation unit to be retired | 166 | 166 | ' | 166 | ||
Exelon Generation Co L L C [Member] | Riverside Station Unit Six [Member] | ' | ' | ' | ' | ||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | ||
Oil/gas-fired generation unit to be retired | 115 | ' | ' | ' | ||
Exelon Generation Co L L C [Member] | Riverside Station Unit Four[Member] | ' | ' | ' | ' | ||
Plant Retirement Positions Eliminated [Abstract] | ' | ' | ' | ' | ||
Oil/gas-fired generation unit to be retired | 74 | 115 | ' | 115 | ||
Exelon Generation Co L L C [Member] | Severance [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | 1 | 38 | ' | ' | ||
Exelon Generation Co L L C [Member] | One-time Termination Benefits [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Expense | 1 | ' | ' | ' | ||
Exelon Generation Co L L C [Member] | Stock Compensation Plan [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Stock Compensation Expense | ' | 2 | ' | ' | ||
Exelon Generation Co L L C [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | 16 | 14 | 5 | ' | ||
Other Expense Charges | ' | 2 | ' | 2 | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Start | 1 | ' | ' | ' | ||
Severance Charges | ' | 14 | [1],[3] | ' | ' | |
Stock Compensation Expense | ' | 1 | [1],[3] | ' | ' | |
Other Expense Charges | ' | 1 | [1],[3] | ' | 1 | [1],[3] |
Total Severance Benefits | ' | 16 | [1],[3] | ' | 16 | [1],[3] |
Payments | 1 | 1 | ' | ' | ||
Restructuring Reserve, Period End | 0 | 1 | ' | 1 | ||
Plant Retirement Cost [Abstract] | ' | ' | ' | ' | ||
Inventory write down related to plant retirements | 0 | 1 | ' | ' | ||
Commonwealth Edison Co [Member] | Severance [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | ' | 2 | ' | ' | ||
Commonwealth Edison Co [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | 2 | 2 | ' | ' | ||
PECO Energy Co [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | ' | 7 | [1] | ' | ' | |
Total Severance Benefits | ' | 7 | [1] | ' | 7 | [1] |
PECO Energy Co [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | ' | 1 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Restructuring Reserve, Period Start | 11 | ' | ' | ' | ||
Severance Charges | ' | 17 | [1],[3] | ' | ' | |
Stock Compensation Expense | ' | 1 | [1],[3] | ' | ' | |
Other Expense Charges | ' | 1 | [1],[3] | ' | 1 | [1],[3] |
Total Severance Benefits | ' | 19 | [1],[3] | ' | 19 | [1],[3] |
Payments | 5 | 1 | ' | ' | ||
Restructuring Reserve, Period End | 6 | 11 | ' | 11 | ||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ||
BGE rate credit of $100 per residential customer | ' | 113 | [2] | ' | ' | |
Charitable contributions at $7 million per year for 10 years | ' | 28 | ' | ' | ||
Miscellaneous tax benefits | ' | -2 | ' | ' | ||
Total | ' | 139 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | Severance [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | ' | 11 | ' | ' | ||
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member] | ' | ' | ' | ' | ||
Restructuring Reserve [Roll Forward] | ' | ' | ' | ' | ||
Severance Charges | ' | 3 | 4 | ' | ||
Other Expense Charges | ' | $1 | ' | $1 | ||
[1] | The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2013. | |||||
[2] | Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. | |||||
[3] | Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period. |
Preferred_Securities_Details
Preferred Securities (Details) (USD $) | Dec. 31, 2013 | Jun. 30, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | ||||
In Millions, except Share data, unless otherwise specified | Preferred Stock [Member] | Preferred Stock [Member] | Series A Preferred Stock [Member] | Series A Preferred Stock [Member] | Series B Preferred Stock [Member] | Series B Preferred Stock [Member] | Series C Preferred Stock [Member] | Series C Preferred Stock [Member] | Series D Preferred Stock [Member] | Series D Preferred Stock [Member] | Series 6.97% Preferred Stock [Member] | Series 6.97% Preferred Stock [Member] | Series 6.7% Preferred Stock [Member] | Series 6.7% Preferred Stock [Member] | Series 6.99% Preferred Stock [Member] | Series 6.99% Preferred Stock [Member] | Series 7.125% Preferred Stock [Member] | Series 7.125% Preferred Stock [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | |||||||
Preferred Stock [Member] | Preferred Stock [Member] | Cumulative Preferred Stock [Member] | Cumulative Preferred Stock [Member] | Cumulative Preferred Stock [Member] | Cumulative Preferred Stock [Member] | Preference Stock [Member] | ||||||||||||||||||||||||||||
Preferred Securities Additional Narrative Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Shares authorized | ' | ' | ' | 100,000,000 | 100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 850,000 | 850,000 | 6,810,451 | 6,810,451 | ' | ' | 15,000,000 | 15,000,000 | 6,500,000 | ||||
Preferred Stock, Par or Stated Value Per Share | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $100 | ||||
Class of Stock [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Shares outstanding | 1,900,000 | ' | 1,900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | 500,000 | 400,000 | 400,000 | 600,000 | 600,000 | 400,000 | 400,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Dollar amount | $190 | $87 | $190 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $50 | $50 | $40 | $40 | $60 | $60 | $40 | $40 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Redemption price | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $100 | [1] | ' | $100.34 | [1] | ' | $100.70 | [1] | ' | $100 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Dividend Rate Percentage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6.97% | ' | 6.70% | ' | 6.99% | ' | 7.13% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Temporary Equity [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Shares outstanding | ' | ' | 874,720 | ' | ' | ' | 300,000 | ' | 150,000 | ' | 274,720 | ' | 150,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Dollar amount | ' | ' | $87 | ' | ' | ' | $30 | ' | $15 | ' | $27 | ' | $15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $0 | $87 | ' | ' | ' | ||||
Redemption price | ' | ' | ' | ' | ' | $106 | ' | $102 | ' | $112.50 | ' | $104 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
Dividend rate per dollar amount | ' | ' | ' | ' | ' | $3.80 | ' | $4.30 | ' | $4.40 | ' | $4.68 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||
[1] | Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends. |
StockBased_Compensation_Plans_2
Stock-Based Compensation Plans (Details) (USD $) | 12 Months Ended | ||||||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Jun. 30, 2013 | ||||
Common Stock [Abstract] | ' | ' | ' | ' | |||
Common Stock without par - Authorized | 2,000,000,000 | 2,000,000,000 | ' | ' | |||
Common Stock without par - Outstanding | 857,290,484 | 854,781,389 | ' | ' | |||
Common Stock reserved for warrants | 24,570 | ' | ' | ' | |||
Authorized Shares for LTIP [Abstract] | ' | ' | ' | ' | |||
Authorized Shares for LTIP | 16,000,000 | ' | ' | ' | |||
Share Based Compensation Components [Abstract] | ' | ' | ' | ' | |||
Performance Shares Expense | $48,000,000 | $46,000,000 | $26,000,000 | ' | |||
Stock-based compensation costs | 120,000,000 | 94,000,000 | 67,000,000 | ' | |||
Stock options | 3,000,000 | 15,000,000 | 8,000,000 | ' | |||
Restricted stock units | 61,000,000 | 50,000,000 | 31,000,000 | ' | |||
Other stock-based awards | 6,000,000 | 4,000,000 | 4,000,000 | ' | |||
Total stock-based compensation included in operating and maintenance expense | 118,000,000 | 115,000,000 | 69,000,000 | ' | |||
Income Tax Benefit | -44,000,000 | -44,000,000 | -27,000,000 | ' | |||
Total after-tax stock based compensation expense | 74,000,000 | 71,000,000 | 42,000,000 | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | 118,000,000 | [1],[2] | 115,000,000 | [1] | 69,000,000 | [1],[3] | ' |
Realized tax benefit when exercised/distributed: | ' | ' | ' | ' | |||
Stock options | 0 | 3,000,000 | 2,000,000 | ' | |||
Restricted stock units | 11,000,000 | 11,000,000 | 8,000,000 | ' | |||
Performance share awards | 11,000,000 | 7,000,000 | 7,000,000 | ' | |||
Stock deferral plan | 1,000,000 | 0 | 1,000,000 | ' | |||
Excess tax benefits included in other financing activities of Exelon's Consolidated Statements of Cash Flows: | ' | ' | ' | ' | |||
Stock options | 0 | 2,000,000 | 1,000,000 | ' | |||
Restricted stock units | 0 | 0 | 0 | ' | |||
Performance share awards | 0 | 0 | 0 | ' | |||
Stock deferral plan | 0 | 0 | 0 | ' | |||
Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward | ' | ' | ' | ' | |||
Shares outstanding, beginning balance - shares | 21,903,781 | ' | ' | ' | |||
Exercised - shares | -670,957 | ' | ' | ' | |||
Forfeited - shares | -54,743 | ' | ' | ' | |||
Expired - shares | -893,758 | ' | ' | ' | |||
Shares outstanding, ending balance - shares | 21,035,445 | 21,903,781 | ' | ' | |||
Exercisable stock options - shares | 20,188,327 | [4] | ' | ' | ' | ||
Shares outstanding, ending balance - weighted average remaining contractual life (years) | '4 years 8 months 23 days | ' | ' | ' | |||
Exercisable stock options - weighted average remaining contractual life (years) | '4 years 7 months 2 days | ' | ' | ' | |||
Shares outstanding, ending balance - aggregate intrinsic value | 10,000,000 | ' | ' | ' | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward | ' | ' | ' | ' | |||
Equity instruments other than options - shares, beginning balance | 1,960,665 | [5] | ' | ' | ' | ||
Vested - shares | -1,058,804 | ' | ' | ' | |||
Forfeited - shares | -54,743 | ' | ' | ' | |||
Equity instruments other than options - shares, ending balance | 847,118 | [5] | 1,960,665 | [5] | ' | ' | |
Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $40.56 | [5] | ' | ' | ' | ||
Vested - Weighted average grant date fair value (per share) | $40.89 | ' | ' | ' | |||
Forfeited - Weighted average grant date fair value (per share) | $39.36 | ' | ' | ' | |||
Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $40.22 | [5] | $40.56 | [5] | ' | ' | |
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract] | ' | ' | ' | ' | |||
Fully vested stock based compensation issued to retirement-eligible employees | ' | 448,827 | ' | ' | |||
Stock based compensation issued to retirement eligible employees that vested immediately on the date of the grant. | ' | 1,348,000 | ' | ' | |||
Fair value of each option estimated using the Black-Scholes-Merton option-pricing model | ' | ' | ' | ' | |||
Dividend yield | ' | 0.05% | 0.05% | ' | |||
Expected volatility | ' | 0.23% | 0.24% | ' | |||
Risk-free interest rate | ' | 0.01% | 0.03% | ' | |||
Weighted average grant date fair value | ' | $4.18 | $6.22 | ' | |||
Additional Information Regarding Stock Options Exercised [Abstract] | ' | ' | ' | ' | |||
Intrinsic value | 4,000,000 | [6] | 19,000,000 | [6] | 5,000,000 | [6] | ' |
Cash received for exercise price | 19,000,000 | 47,000,000 | 13,000,000 | ' | |||
Unrecognized compensation costs related to nonvested stock options | 2,000,000 | ' | ' | ' | |||
Weighted Average Period Non Vested Stock Options Are Expected To Be Recognized Over | '2 years 5 months | ' | ' | ' | |||
Restricted Stock Units [Abstract] | ' | ' | ' | ' | |||
Obligations related to outstanding restricted stock units not yet settled | ' | 58,000,000 | ' | 77,000,000 | |||
Obligations related to outstanding restricted stock units that will be settled in cash | 64,000,000 | ' | ' | ' | |||
Fair value of settled restricted stock | 28,000,000 | 25,000,000 | 19,000,000 | ' | |||
Performance Share Awards [Abstract] | ' | ' | ' | ' | |||
Weighted average grant date fair value | 31.55 | 39.71 | 43.52 | ' | |||
Performance shares settled at fair value of | 26,000,000 | 23,000,000 | 22,000,000 | ' | |||
Performance shares settled at fair value and paid with cash | 12,000,000 | 3,000,000 | 10,000,000 | ' | |||
Unrecognized compensation costs related to nonvested performance shares | 34,000,000 | ' | ' | ' | |||
Weighted average period | '1 year 11 months | ' | ' | ' | |||
Obligation Related To Outstanding Performance Share Awards [Abstract] | ' | ' | ' | ' | |||
Current Liabilities | 13,000,000 | [7] | 7,000,000 | [7] | ' | ' | |
Deferred credits and other liabilities | 24,000,000 | [8] | 11,000,000 | [8] | ' | ' | |
Common stock | 32,000,000 | 35,000,000 | ' | ' | |||
Total | 69,000,000 | 53,000,000 | ' | ' | |||
Share Repurchases [Abstract] | ' | ' | ' | ' | |||
Number of shares of common stock purchased under 2004 share repurchase program | 35,000,000 | ' | ' | ' | |||
Value of shares of common stock purchased under 2004 share repurchase program | 2,300,000,000 | ' | ' | ' | |||
Approved number of shares of common stock for repurchased under Q3 2008 share repurchase program | 1,500,000,000 | ' | ' | ' | |||
Employee Stock Option [Member] | ' | ' | ' | ' | |||
Share Based Compensation Arrangement By Share Based Payment Award Options Outstanding Roll Forward | ' | ' | ' | ' | |||
Shares outstanding, beginning balance - weighted average exercise price (per share) | $45.91 | ' | ' | ' | |||
Exercised - weighted average exercise price (per share) | $28.02 | ' | ' | ' | |||
Forfeited - weighted average exercise price (per share) | $39.36 | ' | ' | ' | |||
Expired - weighted average exercise price (per share) | $49.08 | ' | ' | ' | |||
Shares outstanding, ending balance - weighted average exercise price (per share) | $46.07 | ' | ' | ' | |||
Exercisable stock options - weighted average exercise price (per share) | $46.31 | [4] | ' | ' | ' | ||
Exercisable stock options - aggregate intrinsic value | 10,000,000 | [4] | ' | ' | ' | ||
Restricted Stock [Member] | ' | ' | ' | ' | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward | ' | ' | ' | ' | |||
Equity instruments other than options - shares, beginning balance | 2,029,161 | [9] | ' | ' | ' | ||
Granted - shares | 2,828,187 | ' | ' | ' | |||
Vested - shares | -842,439 | ' | ' | ' | |||
Forfeited - shares | -108,199 | ' | ' | ' | |||
Undistributed Vested Awards - shares | -520,013 | [10] | ' | ' | ' | ||
Equity instruments other than options - shares, ending balance | 3,386,697 | [9] | ' | ' | ' | ||
Granted - Weighted average grant date fair value (per share) | $31.06 | ' | ' | ' | |||
Vested - Weighted average grant date fair value (per share) | $42.90 | ' | ' | ' | |||
Forfeited - Weighted average grant date fair value (per share) | $36.37 | ' | ' | ' | |||
Undistributed Vested Awards - weighted average exercise price (per share) | $32.62 | [10] | ' | ' | ' | ||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract] | ' | ' | ' | ' | |||
Fully vested stock based compensation issued to retirement-eligible employees | 686,121 | ' | ' | ' | |||
Share Based Compensation Acquisition Arrangement [Abstract] | ' | ' | ' | ' | |||
No Sale Restricted Stock Converted Shares | 153,654 | ' | ' | ' | |||
No Sale Restricted Stock Converted Value | 6,000,000 | ' | ' | ' | |||
Performance Share Awards [Member] | ' | ' | ' | ' | |||
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Roll Forward | ' | ' | ' | ' | |||
Equity instruments other than options - shares, beginning balance | 1,312,734 | [11] | ' | ' | ' | ||
Granted - shares | 2,629,171 | ' | ' | ' | |||
Vested - shares | -612,624 | ' | ' | ' | |||
Forfeited - shares | -24,451 | ' | ' | ' | |||
Undistributed Vested Awards - shares | -1,290,640 | [12] | ' | ' | ' | ||
Equity instruments other than options - shares, ending balance | 2,014,190 | [11] | ' | ' | ' | ||
Equity instruments other than options - Weighted average grant date fair value (per share), beginning balance | $40.08 | [11] | ' | ' | ' | ||
Granted - Weighted average grant date fair value (per share) | $31.55 | ' | ' | ' | |||
Vested - Weighted average grant date fair value (per share) | $40.13 | ' | ' | ' | |||
Forfeited - Weighted average grant date fair value (per share) | $32.17 | ' | ' | ' | |||
Undistributed Vested Awards - weighted average exercise price (per share) | $34.28 | [12] | ' | ' | ' | ||
Equity instruments other than options - Weighted average grant date fair value (per share), ending balance | $32.74 | [11] | ' | ' | ' | ||
Schedule Of Share Based Compensation Arrangements By Share Based Payment Award Footnotes To Table [Abstract] | ' | ' | ' | ' | |||
Fully vested stock based compensation issued to retirement-eligible employees | 204,643 | 455,418 | ' | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | 48,000,000 | [2] | 42,000,000 | 31,000,000 | [3] | ' | |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | |||
Common Stock [Abstract] | ' | ' | ' | ' | |||
Par value of common stock | $12.50 | ' | ' | ' | |||
Common Stock par - Authorized | 250,000,000 | ' | ' | ' | |||
Common Stock par - Outstanding | 127,016,896 | 127,016,761 | ' | ' | |||
Warrants Outstanding | 73,709 | 74,182 | ' | ' | |||
Common Stock reserved for warrants | ' | 24,727 | ' | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | 9,000,000 | [2] | 11,000,000 | 5,000,000 | [3] | ' | |
PECO Energy Co [Member] | ' | ' | ' | ' | |||
Common Stock [Abstract] | ' | ' | ' | ' | |||
Common Stock without par - Authorized | 500,000,000 | ' | ' | ' | |||
Common Stock without par - Outstanding | 170,478,507 | 170,478,507 | ' | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | 5,000,000 | [2] | 5,000,000 | 5,000,000 | [3] | ' | |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Common Stock [Abstract] | ' | ' | ' | ' | |||
Common Stock without par - Authorized | 175,000,000 | ' | ' | ' | |||
Common Stock without par - Outstanding | 1,000 | 1,000 | ' | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | 6,000,000 | [2] | 5,000,000 | 6,000,000 | [3] | ' | |
Business Services Company [Member] | ' | ' | ' | ' | |||
Share Based Compensation Pre Tax Expense [Line Items] | ' | ' | ' | ' | |||
Pre-tax stock based compensation expense | $50,000,000 | [13],[2] | $52,000,000 | [13] | $28,000,000 | [13],[3] | ' |
[1] | The stock-based compensation expense (pre-tax) for December 31, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd does not reflect the impact of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. | ||||||
[2] | BGE's stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the year ended December 31, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. | ||||||
[3] | The total stock-based compensation expense (pre-tax) for December 31, 2011 of $69 million does not include the $6 million expense for BGE as those costs were incurred prior to the closing of Exelonbs merger with Constellation on March 12, 2012. | ||||||
[4] | Includes stock options issued to retirement eligible employees. | ||||||
[5] | Excludes 1,348,913 and 2,647,536 of stock options issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | ||||||
[6] | The difference between the market value on the date of exercise and the option exercise price. | ||||||
[7] | Represents the current liability related to performance share awards expected to be settled in cash. | ||||||
[8] | Represents the long-term liability related to performance share awards expected to be settled in cash. | ||||||
[9] | Excludes 931,628 and 686,121 of restricted stock units issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | ||||||
[10] | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2013. | ||||||
[11] | Excludes 1,411,824 and 204,643 of performance share awards issued to retirement-eligible employees as of December 31, 2013 and December 31, 2012, respectively, as they are fully vested. | ||||||
[12] | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2013. | ||||||
[13] | (a) B B B B B B B B BGE's stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the year ended December 31, 2012 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above. (b)B B B B B B B B These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above. (c)B B B B B B B B The stock-based compensation expense (pre-tax) for December 31, 2013 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd does not reflect the impact of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program. (d)B B B B B B B B The total stock-based compensation expense (pre-tax) for December 31, 2011 of $69 million does not include the $6 million expense for BGE as those costs were incurred prior to the closing of Exelonbs merger with Constellation on March 12, 2012. |
Earnings_Per_Share_and_Equity_2
Earnings Per Share and Equity (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Earnings Per Share And Equity Additional Narrative Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Stock options not included in the calculation of diluted common shares outstanding | ' | ' | ' | ' | ' | ' | ' | ' | 20 | 14 | 9 |
Treasury Stock, Shares held | 35 | ' | ' | ' | 35 | ' | ' | ' | 35 | 35 | 35 |
Treasury stock, at cost | $2,327 | ' | ' | ' | $2,327 | ' | ' | ' | $2,327 | $2,327 | ' |
Preferred Stock [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
PECO Cumulative Preferred Securities Redeemable | ' | ' | ' | ' | ' | ' | ' | ' | 87 | ' | ' |
Preferred stock redemption premium | ' | ' | ' | ' | ' | ' | ' | ' | 6 | ' | ' |
Earnings Per Share Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income from continuing operations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Income from discontinued operations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net income on common stock | ' | ' | ' | ' | ' | ' | ' | ' | 1,719 | 1,160 | 2,495 |
Average common shares outstanding - basic | 856 | 857 | 856 | 855 | 854 | 854 | 853 | 705 | 856 | 816 | 663 |
Assumed exercise of stock options, performance share awards and restricted stock | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 3 | 2 |
Average common shares outstanding - diluted | 860 | 860 | 860 | 855 | 857 | 857 | 856 | 707 | 860 | 819 | 665 |
Preferred securities | ' | ' | ' | ' | $87 | ' | ' | ' | ' | $87 | ' |
Changes_in_Accumulated_Other_C2
Changes in Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income by component)(Details) (USD $) | 9 Months Ended | 12 Months Ended | |||||
In Millions, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | ($2,767) | ($2,767) | ' | ' | |||
Net current-period OCI | ' | 727 | -317 | -27 | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | -2,040 | -2,767 | ' | |||
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | |||
Prior service costs | ' | ' | 1 | -4 | |||
Actuarial loss reclassified to periodic cost, taxes | ' | ' | 110 | 93 | |||
Transition obligation | ' | ' | 2 | 2 | |||
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | ' | ' | -237 | -171 | |||
Change in unrealized gain (loss) on cash flow hedges, taxes | ' | ' | -68 | 39 | |||
Change in unrealized gain (loss) on marketable securities, taxes | ' | ' | -1 | 0 | |||
Change in unrealized gain (loss) on equity investments taxes | ' | ' | 1 | 0 | |||
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 368 | [1] | 368 | [1] | ' | ' | |
OCI before reclassifications | ' | 29 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | -277 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | -248 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 120 | [1] | ' | ' | ||
Accumulated Net Unrealized Investment Gain Loss [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
OCI before reclassifications | ' | 2 | [1] | ' | ' | ||
Net current-period OCI | ' | 2 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 2 | [1] | ' | ' | ||
Accumulated Defined Benefit Plans Adjustment [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | -3,137 | [1] | -3,137 | [1] | ' | ' | |
OCI before reclassifications | ' | 669 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | 208 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | 877 | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | -2,260 | [1] | ' | ' | ||
Accumulated Translation Adjustment [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
OCI before reclassifications | ' | -10 | [1] | ' | ' | ||
Net current-period OCI | ' | -10 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | -10 | [1] | ' | ' | ||
Accumulated Equity Investment [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 2 | [1] | 2 | [1] | ' | ' | |
OCI before reclassifications | ' | 101 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | 5 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | 106 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 108 | [1] | ' | ' | ||
Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | -2,767 | [1] | -2,767 | [1] | ' | ' | |
OCI before reclassifications | ' | 791 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | -64 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | 727 | [1] | -317 | -27 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | -2,040 | [1] | -2,767 | [1] | ' | |
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | |||
Other comprehensive income, income taxes | ' | 468 | -41 | -221 | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 513 | 513 | ' | ' | |||
Net current-period OCI | ' | -299 | -402 | -98 | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 214 | 513 | ' | |||
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | |||
Change in unrealized gain (loss) on cash flow hedges, taxes | ' | -262 | -262 | -64 | |||
Change in unrealized gain (loss) on equity investments taxes | 72 | ' | -1 | ' | |||
Other comprehensive income, income taxes | ' | -261 | -64 | -102 | |||
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 512 | [1] | 512 | [1] | ' | ' | |
OCI before reclassifications | ' | 15 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | -413 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | -398 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 114 | [1] | ' | ' | ||
Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
OCI before reclassifications | ' | 2 | [1] | ' | ' | ||
Net current-period OCI | ' | 2 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 2 | [1] | ' | ' | ||
Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
OCI before reclassifications | ' | -10 | [1] | ' | ' | ||
Net current-period OCI | ' | -10 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | -10 | ' | ' | |||
Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 1 | [1] | 1 | [1] | ' | ' | |
OCI before reclassifications | ' | 102 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | 5 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | 107 | [1] | ' | ' | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 108 | [1] | ' | ' | ||
Exelon Generation Co L L C [Member] | Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 513 | [1] | 513 | [1] | ' | ' | |
OCI before reclassifications | ' | 109 | [1] | ' | ' | ||
Amounts reclassified from AOCI | ' | -408 | [1],[2] | ' | ' | ||
Net current-period OCI | ' | -299 | [1] | -402 | -98 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 214 | [1] | 513 | [1] | ' | |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Net current-period OCI | ' | 0 | 1 | 0 | |||
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | |||
Change in unrealized gain (loss) on marketable securities, taxes | ' | 0 | 0 | 0 | |||
Other comprehensive income, income taxes | ' | 0 | 0 | 3 | |||
Commonwealth Edison Co [Member] | Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Net current-period OCI | ' | ' | 1 | ' | |||
PECO Energy Co [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance | 1 | 1 | ' | ' | |||
Net current-period OCI | ' | 0 | 1 | 0 | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 1 | 1 | ' | |||
OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract | ' | ' | ' | ' | |||
Change in unrealized gain (loss) on marketable securities, taxes | ' | 0 | 0 | 0 | |||
Amortization of realized gain on settled cash flow swaps, taxes | ' | 0 | 0 | 0 | |||
Other comprehensive income, income taxes | ' | 0 | 1 | 0 | |||
PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain Loss [Member] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | 1 | [1] | ' | ' | ||
PECO Energy Co [Member] | Accumulated Other Comprehensive (Loss) Income, Net | ' | ' | ' | ' | |||
Accumulated Other Comprehensive Income Loss [Line Items] | ' | ' | ' | ' | |||
Net current-period OCI | ' | 0 | 1 | 0 | |||
Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance | ' | $1 | [1] | ' | ' | ||
[1] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||
[2] | See next table for details about these reclassifications. |
Changes_in_Accumulated_Other_C3
Changes in Accumulated Other Comprehensive Income (Reclassification out of Accumulated Other Comprehensive Income)(Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | $6,163 | $6,502 | $6,141 | $6,082 | $6,254 | $6,579 | $5,966 | $4,690 | $24,888 | $23,489 | $19,063 | |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 1,315 | 891 | 701 | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | -883 | -582 | -523 | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 2,773 | 1,798 | 3,956 | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,044 | 627 | 1,457 | |
Net income (loss) | 495 | 738 | 490 | -4 | 378 | 296 | 286 | 200 | 1,729 | 1,171 | 2,499 | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Prior service costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | -4 | |
Transition obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2 | 2 | |
Loss on equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 10 | -91 | -1 | |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | 461 | [1] | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -184 | [1] | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 64 | [1] | ' | ' |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Deferred compensation unit | ' | ' | ' | ' | ' | ' | ' | ' | -1 | [1],[2] | ' | ' |
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 277 | [1] | ' | ' |
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | 464 | [1] | ' | ' |
Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | -3 | [1] | ' | ' |
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Prior service costs | ' | ' | ' | ' | ' | ' | ' | ' | -2 | [1],[3] | ' | ' |
Actuarial gains/losses | ' | ' | ' | ' | ' | ' | ' | ' | -339 | [1],[3] | ' | ' |
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Plans Defined Benefit [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -342 | [1] | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 134 | [1] | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -208 | [1] | ' | ' |
Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member] | Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | -8 | [1] | ' | ' |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -8 | [1] | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 3 | [1] | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -5 | [1] | ' | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | 3,772 | 4,255 | 4,070 | 3,533 | 3,898 | 4,031 | 3,765 | 2,743 | 15,630 | 14,437 | 10,447 | |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 298 | 226 | 170 | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | 11 | -62 | -48 | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,675 | 1,058 | 2,827 | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 615 | 500 | 1,056 | |
Net income (loss) | 269 | 490 | 330 | -18 | 137 | 91 | 166 | 168 | 1,060 | 558 | 1,771 | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Loss on equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 10 | -91 | -1 | |
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | 683 | [1] | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 408 | [1] | ' | ' |
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -270 | [1] | ' | ' |
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 413 | [1] | ' | ' |
Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | 683 | [1] | ' | ' |
Exelon Generation Co L L C [Member] | Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member] | Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | ' | ' | ' | ' | ' | ' | ' | ' | -8 | [1] | ' | ' |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -8 | [1] | ' | ' |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 3 | [1] | ' | ' |
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -5 | [1] | ' | ' |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | 1,068 | 1,156 | 1,080 | 1,160 | 1,290 | 1,484 | 1,281 | 1,388 | 4,464 | 5,443 | 6,056 | |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 566 | 294 | 330 | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | -553 | -268 | -316 | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 401 | 618 | 666 | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 152 | 239 | 250 | |
Net income (loss) | 109 | 126 | 96 | -81 | 160 | 90 | 42 | 87 | 249 | 379 | 416 | |
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Loss on equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | 805 | 728 | 672 | 895 | 790 | 806 | 715 | 875 | 3,100 | 3,186 | 3,720 | |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 103 | 111 | 122 | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | -109 | -115 | -120 | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 557 | 508 | 535 | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 162 | 127 | 146 | |
Net income (loss) | 102 | 92 | 72 | 121 | 79 | 122 | 79 | 96 | 395 | 381 | 389 | |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |
Operating revenues | 794 | 737 | 653 | 880 | 703 | 720 | 616 | 697 | 3,065 | 2,735 | 3,068 | |
Interest Expense | ' | ' | ' | ' | ' | ' | ' | ' | 106 | 128 | 113 | |
Other income and deductions | ' | ' | ' | ' | ' | ' | ' | ' | -105 | -121 | -103 | |
Income before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 344 | 11 | 211 | |
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 134 | 7 | 75 | |
Net income (loss) | $47 | $50 | $22 | $77 | $15 | ($4) | $13 | ($33) | $210 | $4 | $136 | |
[1] | Amounts in parenthesis represent a decrease in net income. | |||||||||||
[2] | Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. | |||||||||||
[3] | This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see note 16 for additional details). |
Commitments_and_Contingencies_2
Commitments and Contingencies (Details) (USD $) | 1 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | 12 Months Ended | 1 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | 12 Months Ended | 12 Months Ended | 3 Months Ended | 12 Months Ended | 12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oct. 31, 2007 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Apr. 12, 2012 | Feb. 28, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jan. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jan. 31, 2005 | Feb. 09, 2007 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jul. 11, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Jun. 30, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Dec. 31, 2013 | Sep. 30, 2013 | Dec. 31, 2013 | |||||||||||||
T | Other Purchase Obligations [Member] | Maximum estimated damages per text message | Minimum estimated damages per text message | Cotter Corporation [Member] | Cotter Corporation [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Surety Bond [Member] | Property Lease Guarantee [Member] | Performance Guarantee [Member] | Energy Contract Guarantee [Member] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group LLC [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | Commonwealth Edison Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Baltimore Gas and Electric Company [Member] | Midwest Generation, LLC [Member] | Midwest Generation, LLC [Member] | Midwest Generation, LLC [Member] | ||||||||||||||||
OpenClaims | Defendants | Defendants | States | Net Capacity Purchases [Member] | Power Purchases [Member] | Transmission Rights Purchases [Member] | Purchased Energy from Equity Investment [Member] | Total Unregulated Energy Commitments [Member] | Public Utilities, Inventory, Fuel [Member] | Solar Facility Construction [Member] | Other Purchase Obligations [Member] | Perryman Construction [Member] | Beebe Construction [Member] | FourmileConstructionMember [Member] | Midwest Generation Sites | Cotter Corporation [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Performance Guarantee [Member] | Energy Contract Guarantee [Member] | Sithe Guarantee [Member] | TEG And TEP Guarantee [Member] | Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | Customers | Defendants | DSP Program Electric Procurement Contracts [Member] | Renewable Energy Including Renewable Energy Credits [Member] | Other Purchase Obligations [Member] | Maximum estimated damages per text message | Minimum estimated damages per text message | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Surety Bond [Member] | Performance Guarantee [Member] | Trust Preferred Securities [Member] | MGPSites | DSP Program Electric Procurement Contracts [Member] | Alternative Energy Credits [Member] | Public Utilities, Inventory, Fuel [Member] | Other Purchase Obligations [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Surety Bond [Member] | Performance Guarantee [Member] | Trust Preferred Securities [Member] | Claiments | DSP Program Electric Procurement Contracts [Member] | Curtailment Services [Member] | Public Utilities, Inventory, Fuel [Member] | Other Purchase Obligations [Member] | Sixty-Eighth Street Dump [Member] | Rossville ash site [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Total Accrual For Environmental Loss Contingencies [Member] | Accrual For MGP Investigation And Remediation [Member] | Accrual For MGP Investigation And Remediation [Member] | Financial Standby Letter of Credit [Member] | Surety Bond [Member] | Performance Guarantee [Member] | Trust Preferred Securities [Member] | Midwest Generation Sites | ||||||||||||||||||||||||||||||||||||||||||
Reactors | Customers | Defendants | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
MGPSites | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition, Costs Recognized Post Merger [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
BGE rate credit of $100 per residential customer | ' | ' | $113,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $113,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | ' | ' | 113,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Charitable contributions at $7 million per year for 10 years | ' | ' | 70,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
State funding for offshore wind development projects | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Miscellaneous tax benefits | ' | ' | -2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total | ' | ' | 328,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 35,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 139,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Business Acquisition, Costs Recognized Post Merger Footnotes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Business Acquisition, Equity Contribution | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 66,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Commercial Commitments [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Guarantee Obligations Maximum Exposure | ' | 9,700,000,000 | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,520,000,000 | 339,000,000 | 44,000,000 | 1,107,000,000 | 3,161,000,000 | 3,529,000,000 | ' | ' | 6,195,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,477,000,000 | [2] | 357,000,000 | 832,000,000 | ' | ' | 3,529,000,000 | ' | 689,000,000 | ' | 228,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 9,000,000 | 200,000,000 | 200,000,000 | 203,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 3,000,000 | 178,000,000 | 178,000,000 | ' | 260,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 9,000,000 | 250,000,000 | 250,000,000 | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure next twelve months | ' | 5,029,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,217,000,000 | 301,000,000 | 0 | 350,000,000 | 3,161,000,000 | 0 | ' | ' | 2,349,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,174,000,000 | [2] | 343,000,000 | 832,000,000 | ' | ' | 0 | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | 9,000,000 | ' | ' | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 3,000,000 | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 9,000,000 | ' | ' | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure year two | ' | 300,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 298,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | 298,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 298,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure year three | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure year four | ' | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | 4,000,000 | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure year five | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||||
Guarantee obligations maximum exposure year six and beyond | ' | 4,355,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000,000 | 44,000,000 | 757,000,000 | ' | 3,529,000,000 | ' | ' | 3,543,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [2] | 14,000,000 | ' | ' | ' | 3,529,000,000 | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | 178,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 178,000,000 | ' | ' | 250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 250,000,000 | ' | ' | ' | ' | |||||||||||
Commercial Commitments Footnote [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Guarantees in support of equity investment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 211,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Estimated net exposure for commercial transaction obligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 463,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Estimated total assumed for commercial transaction obligations | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 749,000,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear Insurance [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear insurance liability limit per incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,600,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Required nuclear liability insurance per site | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 375,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total of U.S. licensed nuclear reactors | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 104 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear financial protection pool value | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Cost surcharge to Price-Anderson Act nuclear incident assessment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 127,300,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Maximum liability per nuclear incident | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,400,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear industry mutual insurance company distribution to members | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total retrospective premium obligation under insurance from a nuclear industry mutual insurance company | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 287,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total nuclear property insurance coverage | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear property insurance coverage limit per individual insured | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,250,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Additional nuclear property insurance purchased under single limit blanket property | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 850,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear insurance property damage maximum retrospective premium obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 229,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Nuclear outage replacement power cost insurance maximum annual retrospective premium obligation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 58,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Spent Nuclear Fuel Obligation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.001 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Estimate increase in nuclear ARO due to delay in DOE acceptance of spent nuclear fuel for date one | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 700,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Reimbursement for spent nuclear fuel costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 712,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Net reimbursement for spent nuclear fuel cost after co-owner deduction | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 601,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Requested SNF reimbursement costs from the DOE | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 71,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Requested SNF reimbursement cost owed to co-owners | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Department of Energy SNF one-time fee applicable to nuclear generation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 277,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
DOE SNF one-time fee with interest | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,021,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
13-week Treasury Rate used to calculate DOE SNF one-time fee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.05% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
LossContingencySettlementAbstract | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Receivable from affiliate | ' | ' | 2,039,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,469,000,000 | 2,039,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 447,000,000 | 360,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Guarantees Related To Indemnifications [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Acquisition of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Sale of interest in subsidiary | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 100.00% | 49.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
ProceedsFromDivestitureOfBusinessesNetOfCashDivested | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 95,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Accrual For Environmental Loss Contingencies [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Accrued environmental liabilities | ' | ' | ' | ' | ' | ' | ' | ' | ' | 338,000,000 | 351,000,000 | 273,000,000 | 298,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,000,000 | 42,000,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 234,000,000 | 261,000,000 | 229,000,000 | 254,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 47,000,000 | 47,000,000 | 44,000,000 | 44,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 1,000,000 | 0 | 0 | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Environmental Issues - MGP Site Contingency [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total number of MGP sites | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Approved clean-up | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Sites under study/remediation | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 26 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
MGP reserve update | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Environmental Issues - Water [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Low end of range of cooling tower cost | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 430,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Consent decree penalty | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Environmental loss contingencies | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total Conemaugh Station water discharge settlement to be paid by all responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 500,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Portion of Conemaugh Station water discharge settlement to be paid by Exelon | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Increase in accrual due to purchase accounting | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Increase in accrual due to an update of costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Environmental Issues - Air [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
States subject to the Cross State Air Pollution Rule | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Emissions allowance balance | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 56,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Net investment in long-term direct financing leases | ' | 698,000,000 | 685,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 693,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Coal Rail Car Lease Proof of Claims | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Probable contingency (liability) | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ||||||||||||
Midwest Generation's estimated environmental investigation and remediation costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 8,000,000 | ||||||||||||
Payments for operating leases | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Environmental Issues - Solid and Hazardous Waste [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
DOJ potential settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total cost of remediation to be shared by PRPs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 42,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Loss Contingency Number Of Defendants | ' | ' | ' | ' | ' | ' | ' | 14 | 15 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Loss Contingency Esitmate to close site | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
68th Street and Sauer Dumps [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Number of defendants in addition to BGE and Constellation Energy | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Minimum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,700,000 | ' | ' | ' | ' | ' | ' | 64,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Climate Change Regulation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Minimum GHG emissions by stationary sources to qualify for regulation | ' | 75,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Minimum additional GHG emissions by stationary sources after a modification | ' | 100,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Asbestos Loss Contingency [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Asbestos liability reserve | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 90,000,000 | 63,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 53,000,000 | ' | ' | ||||||||||||
Asbestos liability reserve related to open claims | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ||||||||||||
Open asbestos liability claims | ' | 224 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Asbestos liability reserve related to anticipated claims | ' | 71,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Increase (decrease) in the value of the asbestos liability reserve | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Asbestos reserve adjustment | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 19,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Number of claimants | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 486 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
US Department Of Energy Settlements [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Preacquisition contingency asset DOE settlement gain | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Funds received from DOE settlement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
FERC Settlement [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
FERC civil penalty | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
FERC disgorgement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 110,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
FERC settlement recorded in operation and maintenance expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 195,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
FERC settlement recorded as preacquisition contingency | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Dividend Payments Restrictions [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Total of common stock and retained earnings | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,100,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Continuous Power Interruption [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Minimum number of customers ComEd can be held liable to for power interruption | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Number of customers affected by a major storm | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 900,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Number of customers proposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 34,599 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Securities Class Action Suit [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Expected settlement amount to resolve class action suit | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Telephone Consumer Protection Act Lawsuit [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
PossibleDefendantsNumber | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
LossContingencyDamagesSought | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,500 | 500 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Unrecorded Unconditional Purchase Obligation [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Purchase Obligations, Due within One Year | ' | ' | ' | ' | 61,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 412,000,000 | [3] | 117,000,000 | [4] | 25,000,000 | [5] | 824,000,000 | 1,378,000,000 | 1,212,000,000 | 110,000,000 | 170,000,000 | ' | 50,000,000 | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 323,000,000 | 72,000,000 | 88,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 590,000,000 | 2,000,000 | 179,000,000 | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 783,000,000 | 45,000,000 | 129,000,000 | 44,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Due within Two Years | ' | ' | ' | ' | 34,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 367,000,000 | [3] | 110,000,000 | [4] | 13,000,000 | [5] | ' | 490,000,000 | 1,256,000,000 | ' | 131,000,000 | 80,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 136,000,000 | 74,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 91,000,000 | 2,000,000 | 112,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 400,000,000 | 40,000,000 | 59,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Due within Three Years | ' | ' | ' | ' | 32,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 284,000,000 | [3] | 76,000,000 | [4] | 2,000,000 | [5] | ' | 362,000,000 | 1,040,000,000 | ' | 45,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 137,000,000 | 76,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 98,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 73,000,000 | 34,000,000 | 57,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Due within Four Years | ' | ' | ' | ' | 31,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 223,000,000 | [3] | 25,000,000 | [4] | 2,000,000 | [5] | ' | 250,000,000 | 1,044,000,000 | ' | 42,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 140,000,000 | 77,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 37,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | 57,000,000 | 2,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Due within Five Years | ' | ' | ' | ' | 26,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 112,000,000 | [3] | 3,000,000 | [4] | 2,000,000 | [5] | ' | 117,000,000 | 763,000,000 | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 83,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 15,000,000 | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 51,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Due after Five Years | ' | ' | ' | ' | 78,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 414,000,000 | [3] | 3,000,000 | [4] | 32,000,000 | [5] | ' | 449,000,000 | 3,175,000,000 | ' | 86,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,207,000,000 | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | 66,000,000 | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 256,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Purchase Obligations, Total | ' | ' | ' | ' | 262,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,812,000,000 | [3] | 334,000,000 | [4] | 76,000,000 | [5] | 824,000,000 | 3,046,000,000 | 8,490,000,000 | ' | 504,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 736,000,000 | 1,589,000,000 | 122,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 681,000,000 | 14,000,000 | 507,000,000 | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,256,000,000 | 132,000,000 | 609,000,000 | 53,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Percentage of ownership interest in CENG (as a percent) | ' | ' | ' | ' | ' | 50.00% | 20.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50.01% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Operating Leases Future Minimum Payments Due Table [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Minimum future operating lease payments due in one year | ' | 103,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 12,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Minimum future operating lease payments due in two years | ' | 91,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Minimum future operating lease payments due in three years | ' | 89,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Minimum future operating lease payments due in four years | ' | 82,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 48,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 8,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Minimum future operating lease payments due in five years | ' | 63,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Minimum future operating lease payments due beyond five years | ' | 398,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 336,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||
Total minimum future operating lease payments | ' | 826,000,000 | [7] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 572,000,000 | [7] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 47,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,000,000 | [6] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 61,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||
Future Operating Lease Payments Indefinite Periods Footnote [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Future operating lease payments with indefinite periods due in one year | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Future operating lease payments with indefinite periods due in two years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Future operating lease payments with indefinite periods due in three years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Future operating lease payments with indefinite periods due in four years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Future operating lease payments with indefinite periods due in five years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Operating Leases Rent Expense [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Lease And Rental Expense | ' | 806,000,000 | 930,000,000 | 711,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 744,000,000 | [8] | 872,000,000 | [8] | 659,000,000 | [8] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | 18,000,000 | 18,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 21,000,000 | 27,000,000 | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 11,000,000 | 12,000,000 | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||||||
Operating Leases Rent Expense Footnote [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
Long Term Contract For Purchase Of Electric Power Capacity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $694,000,000 | $801,000,000 | $630,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||||||||||||
[1] | Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at December 31, 2013, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | The table excludes renewable energy purchases that are contingent in nature. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | B Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd's, PECObs and BGEbs annual obligation for these arrangements, included in each of the years 2014 - 2018, was $1 million, $3 million and $1 million respectively. (c)B B B B B B B B Includes all future lease payments on a 99 year real estate lease that expires in 2105. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Excludes Generation's PPAs and other capacity contracts that are accounted for as contingent operating lease payments. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Includes Generation's PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the energy commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation's PPAs and other capacity contracts totaled $694 million, $801 million and $630 million during 2013, 2012 and 2011, respectively. |
Supplemental_Financial_Informa2
Supplemental Financial Information -Operations (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Operating revenues [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total operating revenues | $6,163 | $6,502 | $6,141 | $6,082 | $6,254 | $6,579 | $5,966 | $4,690 | $24,888 | $23,489 | $19,063 | |||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Taxes other than income - utility | ' | ' | ' | ' | ' | ' | ' | ' | 449 | [1] | 463 | [1] | 443 | [1] |
Taxes other than income - real estate | ' | ' | ' | ' | ' | ' | ' | ' | 302 | 227 | 177 | |||
Taxes other than income - payroll | ' | ' | ' | ' | ' | ' | ' | ' | 159 | 131 | 123 | |||
Taxes other than income - other | ' | ' | ' | ' | ' | ' | ' | ' | 185 | 198 | 42 | |||
Total taxes other than income | ' | ' | ' | ' | ' | ' | ' | ' | 1,095 | 1,019 | 785 | |||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total income (loss) in equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 10 | -91 | -1 | |||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 256 | [2] | 189 | [2] | 177 | [2] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 77 | [2] | 102 | [2] | 45 | [2] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 406 | 386 | -74 | |||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | ' | ' | ' | ' | ' | ' | ' | ' | 146 | 105 | -4 | |||
Net unrealized income (losses) on pledged assets | ' | ' | ' | ' | ' | ' | ' | ' | 7 | 73 | 48 | |||
Regulatory offset to decommissioning trust fund-related activities | ' | ' | ' | ' | ' | ' | ' | ' | -546 | [3] | -530 | [3] | -130 | [3] |
Investment income | ' | ' | ' | ' | ' | ' | ' | ' | 8 | 20 | 10 | |||
Total decommissioning-related activities | ' | ' | ' | ' | ' | ' | ' | ' | 346 | 325 | 62 | |||
Long-term lease income | ' | ' | ' | ' | ' | ' | ' | ' | 28 | 29 | 28 | |||
Interest income related to uncertain income tax positions | ' | ' | ' | ' | ' | ' | ' | ' | 24 | 15 | 53 | |||
Income related to termination of a gas supply guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | |||
Losses on early retirement of debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | |||
Other-than-temporary impairment to Rabbi trust investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | |||
Credit facility termination fees | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -85 | ' | |||
AFUDC - equity | ' | ' | ' | ' | ' | ' | ' | ' | 22 | 17 | 17 | |||
Bargain purchase gain related to Wolf Hollow acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36 | |||
Realized gains on Rabbi Trust investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | |||
Other Income | ' | ' | ' | ' | ' | ' | ' | ' | 45 | 25 | ' | |||
Other Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -3 | |||
Other, net | ' | ' | ' | ' | ' | ' | ' | ' | 473 | 346 | 203 | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Operating revenues [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total operating revenues | 3,772 | 4,255 | 4,070 | 3,533 | 3,898 | 4,031 | 3,765 | 2,743 | 15,630 | 14,437 | 10,447 | |||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Taxes other than income - utility | ' | ' | ' | ' | ' | ' | ' | ' | 79 | [1] | 82 | 27 | ||
Taxes other than income - real estate | ' | ' | ' | ' | ' | ' | ' | ' | 205 | 189 | 146 | |||
Taxes other than income - payroll | ' | ' | ' | ' | ' | ' | ' | ' | 89 | 78 | 71 | |||
Taxes other than income - other | ' | ' | ' | ' | ' | ' | ' | ' | 16 | 20 | 20 | |||
Total taxes other than income | ' | ' | ' | ' | ' | ' | ' | ' | 389 | 369 | 264 | |||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total income (loss) in equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 10 | -91 | -1 | |||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 256 | [2] | 189 | [2] | 177 | [2] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 77 | [2] | 102 | [2] | 45 | [2] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | ' | ' | ' | ' | ' | ' | ' | ' | 406 | 386 | -74 | |||
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | ' | ' | ' | ' | ' | ' | ' | ' | 146 | 105 | -4 | |||
Net unrealized income (losses) on pledged assets | ' | ' | ' | ' | ' | ' | ' | ' | 7 | ' | 48 | |||
Regulatory offset to decommissioning trust fund-related activities | ' | ' | ' | ' | ' | ' | ' | ' | -546 | [3] | -530 | [3] | -130 | [3] |
Investment income | ' | ' | ' | ' | ' | ' | ' | ' | -1 | 3 | 1 | |||
Total decommissioning-related activities | ' | ' | ' | ' | ' | ' | ' | ' | 346 | 325 | 62 | |||
Interest income related to uncertain income tax positions | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 2 | 31 | |||
Income related to termination of a gas supply guarantee | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | |||
Losses on early retirement of debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | |||
Credit facility termination fees | ' | ' | ' | ' | ' | ' | ' | ' | 0 | -85 | ' | |||
Bargain purchase gain related to Wolf Hollow acquisition | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 36 | |||
Other Income | ' | ' | ' | ' | ' | ' | ' | ' | 19 | -6 | ' | |||
Other Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -8 | |||
Other, net | ' | ' | ' | ' | ' | ' | ' | ' | 368 | 239 | 122 | |||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Operating revenues [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total operating revenues | 1,068 | 1,156 | 1,080 | 1,160 | 1,290 | 1,484 | 1,281 | 1,388 | 4,464 | 5,443 | 6,056 | |||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Taxes other than income - utility | ' | ' | ' | ' | ' | ' | ' | ' | 241 | [1] | 239 | [1] | 243 | [1] |
Taxes other than income - real estate | ' | ' | ' | ' | ' | ' | ' | ' | 24 | 22 | 22 | |||
Taxes other than income - payroll | ' | ' | ' | ' | ' | ' | ' | ' | 27 | 26 | 25 | |||
Taxes other than income - other | ' | ' | ' | ' | ' | ' | ' | ' | 7 | 8 | 6 | |||
Total taxes other than income | ' | ' | ' | ' | ' | ' | ' | ' | 299 | 295 | 296 | |||
Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total income (loss) in equity method investments | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Investment income | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 1 | 1 | |||
Interest income related to uncertain income tax positions | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 20 | 14 | |||
Other-than-temporary impairment to Rabbi trust investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | |||
AFUDC - equity | ' | ' | ' | ' | ' | ' | ' | ' | 11 | 6 | 8 | |||
Realized gains on Rabbi Trust investments | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | |||
Other Income | ' | ' | ' | ' | ' | ' | ' | ' | 15 | 12 | -6 | |||
Other, net | ' | ' | ' | ' | ' | ' | ' | ' | 26 | 39 | 29 | |||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Operating revenues [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total operating revenues | 805 | 728 | 672 | 895 | 790 | 806 | 715 | 875 | 3,100 | 3,186 | 3,720 | |||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Taxes other than income - utility | ' | ' | ' | ' | ' | ' | ' | ' | 129 | [1] | 141 | [1] | 173 | [1] |
Taxes other than income - real estate | ' | ' | ' | ' | ' | ' | ' | ' | 14 | 13 | 9 | |||
Taxes other than income - payroll | ' | ' | ' | ' | ' | ' | ' | ' | 13 | 12 | 13 | |||
Taxes other than income - other | ' | ' | ' | ' | ' | ' | ' | ' | 2 | -4 | 10 | |||
Total taxes other than income | ' | ' | ' | ' | ' | ' | ' | ' | 158 | 162 | 205 | |||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Investment income | ' | ' | ' | ' | ' | ' | ' | ' | -1 | 2 | 3 | |||
Interest income related to uncertain income tax positions | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 1 | |||
AFUDC - equity | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 4 | 9 | |||
Other Income | ' | ' | ' | ' | ' | ' | ' | ' | 3 | 2 | -1 | |||
Other, net | ' | ' | ' | ' | ' | ' | ' | ' | 6 | 8 | 14 | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Operating revenues [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Total operating revenues | 794 | 737 | 653 | 880 | 703 | 720 | 616 | 697 | 3,065 | 2,735 | 3,068 | |||
Taxes Excluding Income And Excise Taxes [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Taxes other than income - utility | ' | ' | ' | ' | ' | ' | ' | ' | 82 | 75 | 79 | |||
Taxes other than income - real estate | ' | ' | ' | ' | ' | ' | ' | ' | 112 | 111 | 107 | |||
Taxes other than income - payroll | ' | ' | ' | ' | ' | ' | ' | ' | 15 | 18 | 17 | |||
Taxes other than income - other | ' | ' | ' | ' | ' | ' | ' | ' | 4 | 4 | 4 | |||
Total taxes other than income | ' | ' | ' | ' | ' | ' | ' | ' | 213 | 208 | 207 | |||
Decommissioning-Related Activities [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||
Investment income | ' | ' | ' | ' | ' | ' | ' | ' | 9 | [4] | 11 | [4] | 13 | [4] |
AFUDC - equity | ' | ' | ' | ' | ' | ' | ' | ' | 7 | 10 | 15 | |||
Other Income | ' | ' | ' | ' | ' | ' | ' | ' | 1 | 2 | ' | |||
Other Expense | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -2 | |||
Other, net | ' | ' | ' | ' | ' | ' | ' | ' | $17 | $23 | $26 | |||
[1] | Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGEbs utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations | |||||||||||||
[2] | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||||||||||
[3] | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 - Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. | |||||||||||||
[4] | (c)B B B B B B B B Relates to the cash return on BGEbs rate stabilization deferral. See Note 3 b Regulatory Matters for additional information regarding the rate stabilization deferral. |
Supplemental_Financial_Informa3
Supplemental Financial Information - Cash Flow (Details) (USD $) | 12 Months Ended | 37 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2012 | |||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ' | ' | |||
Property, plant and equipment | $1,893 | $1,712 | $1,284 | ' | |||
Regulatory assets | 212 | 129 | 63 | ' | |||
Amortization of intangible assets, net | 48 | 40 | ' | ' | |||
Amortization of energy contract assets and liabilities | 430 | 1,110 | ' | ' | |||
Nuclear fuel | 921 | [1] | 848 | [1] | 755 | [1] | ' |
Asset retirement obligation accretion | 275 | [2] | 240 | [2] | 214 | [2] | ' |
Total depreciation, amortization and accretion | 3,779 | 4,079 | 2,316 | ' | |||
Cash Paid Refunded During Year [Abstract] | ' | ' | ' | ' | |||
Interest (net of amount capitalized) | 866 | 761 | 649 | ' | |||
Income taxes (net of refunds) | 112 | -171 | -457 | ' | |||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ' | ' | |||
Pension and non-pension postretirement benefits costs | 825 | 820 | 542 | ' | |||
Provision for uncollectible accounts | 101 | 164 | 121 | ' | |||
Provision for Obsolete Inventory | 9 | ' | ' | ' | |||
Stock-based compensation costs | 120 | 94 | 67 | ' | |||
Other Decommissioning Related Activity | 169 | 145 | -16 | ' | |||
Energy-related options | 104 | [3] | 160 | [3] | 137 | [3] | ' |
ARO adjustment | ' | 0 | 0 | ' | |||
Amortization of regulatory asset related to debt costs | 12 | 18 | 21 | ' | |||
Amortization of rate stabilization deferral | 66 | 57 | ' | ' | |||
Amortization of debt fair value adjustment | 34 | -34 | ' | ' | |||
Accrual for Illinois utility distribution tax refund | ' | ' | 0 | ' | |||
Uncollectible accounts recovery | ' | ' | 14 | ' | |||
APR SO2 allowances impairment | ' | 0 | 0 | ' | |||
Discrete impacts from 2010 Rate Case Order | ' | ' | 32 | [4] | ' | ||
Bargain purchase gain | ' | ' | -36 | ' | |||
Discrete impacts from EIMA | -271 | [5] | 96 | [5] | 82 | ' | |
Merger related commitments | 0 | [6] | 141 | [6] | ' | ' | |
Severance Costs | 0 | 99 | ' | ' | |||
Gain (loss) on equity method investments | -10 | 91 | 1 | ' | |||
Impairment in investment of direct financing leases | 14 | [7] | ' | ' | ' | ||
Impairment Of Long Lived Asets Held For Use | 149 | [8] | ' | ' | ' | ||
Amortization of debt costs | -18 | 19 | ' | ' | |||
Other | -58 | -11 | 2 | ' | |||
Total other noncash operating activities | -876 | -1,383 | -770 | ' | |||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ' | ' | |||
Under/over-recovered energy and transmission costs | 12 | 71 | -45 | ' | |||
Other regulatory assets and liabilities | -64 | -404 | ' | ' | |||
Other current assets and liabilities | -165 | 213 | -101 | ' | |||
Other noncurrent assets and liabilities | 319 | -248 | 122 | ' | |||
Total changes in other assets and liabilities | 102 | -368 | -24 | ' | |||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ' | ' | |||
Change in ARC | -128 | 781 | 186 | ' | |||
Capital expenditures not paid | -38 | 160 | 96 | ' | |||
Purchase accounting adjustments | ' | 0 | ' | ' | |||
Merger with Constellation, common stock issued | ' | 7,365 | ' | ' | |||
Consolidated VIE dividend to non-controlling interest | 63 | ' | ' | ' | |||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ' | ' | |||
Amount included in capital expenditures | 74 | 103 | ' | ' | |||
Smart Grid Grant Reimbursements | 95 | 113 | ' | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | |||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ' | ' | |||
Property, plant and equipment | 813 | 733 | 570 | ' | |||
Regulatory assets | 0 | 0 | 0 | ' | |||
Amortization of intangible assets, net | 43 | 35 | ' | ' | |||
Amortization of energy contract assets and liabilities | 507 | 1,110 | ' | ' | |||
Nuclear fuel | 921 | [1] | 848 | [1] | 755 | [1] | ' |
Asset retirement obligation accretion | 275 | [2] | 240 | [2] | 214 | [2] | ' |
Total depreciation, amortization and accretion | 2,559 | 2,966 | 1,539 | ' | |||
Cash Paid Refunded During Year [Abstract] | ' | ' | ' | ' | |||
Interest (net of amount capitalized) | 291 | 286 | 158 | ' | |||
Income taxes (net of refunds) | -18 | 175 | 347 | ' | |||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ' | ' | |||
Pension and non-pension postretirement benefits costs | 345 | 341 | 249 | ' | |||
Provision for uncollectible accounts | 10 | 22 | 0 | ' | |||
Provision for Obsolete Inventory | 9 | 6 | ' | 18 | |||
Other Decommissioning Related Activity | 169 | 145 | -16 | ' | |||
Energy-related options | 104 | [3] | 160 | [3] | 137 | [3] | ' |
ARO adjustment | ' | 0 | 0 | ' | |||
Amortization of debt fair value adjustment | 34 | -34 | ' | ' | |||
APR SO2 allowances impairment | ' | 0 | 0 | ' | |||
Bargain purchase gain | ' | ' | -36 | ' | |||
Merger related commitments | 0 | 32 | [6] | ' | ' | ||
Severance Costs | 0 | 34 | ' | ' | |||
Gain (loss) on equity method investments | -10 | 91 | 1 | ' | |||
Impairment Of Long Lived Asets Held For Use | 149 | [8] | ' | ' | ' | ||
Amortization of debt costs | -10 | 11 | ' | ' | |||
Other | 0 | 19 | 55 | ' | |||
Total other noncash operating activities | -414 | -537 | -421 | ' | |||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ' | ' | |||
Other current assets and liabilities | -151 | -30 | -23 | ' | |||
Other noncurrent assets and liabilities | 15 | -98 | -34 | ' | |||
Total changes in other assets and liabilities | -136 | -128 | -57 | ' | |||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ' | ' | |||
Change in ARC | -128 | 781 | 186 | ' | |||
Capital expenditures not paid | -107 | [9] | 103 | [10] | 125 | ' | |
Purchase accounting adjustments | ' | 0 | ' | ' | |||
Merger with Constellation, common stock issued | ' | 5,264 | ' | ' | |||
Consolidated VIE dividend to non-controlling interest | -63 | ' | ' | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | |||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ' | ' | |||
Property, plant and equipment | 545 | 525 | 502 | ' | |||
Regulatory assets | 119 | 80 | 52 | ' | |||
Amortization of intangible assets, net | 5 | 5 | ' | ' | |||
Nuclear fuel | 0 | 0 | 0 | ' | |||
Asset retirement obligation accretion | 0 | 0 | [2] | 0 | [2] | ' | |
Total depreciation, amortization and accretion | 669 | 610 | 554 | ' | |||
Cash Paid Refunded During Year [Abstract] | ' | ' | ' | ' | |||
Interest (net of amount capitalized) | 283 | 288 | 296 | ' | |||
Income taxes (net of refunds) | 33 | -42 | -676 | ' | |||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ' | ' | |||
Pension and non-pension postretirement benefits costs | 308 | 282 | 213 | ' | |||
Provision for uncollectible accounts | -15 | 42 | 57 | ' | |||
Provision for Obsolete Inventory | 0 | 1 | ' | ' | |||
ARO adjustment | ' | 0 | 0 | ' | |||
Amortization of regulatory asset related to debt costs | 9 | 13 | 18 | ' | |||
Accrual for Illinois utility distribution tax refund | ' | ' | 0 | ' | |||
Uncollectible accounts recovery | ' | ' | 14 | ' | |||
Discrete impacts from 2010 Rate Case Order | ' | ' | 32 | [4] | ' | ||
Discrete impacts from EIMA | -271 | [5] | 96 | [5] | 82 | ' | |
Merger related commitments | 0 | [6] | ' | ' | ' | ||
Gain (loss) on equity method investments | 0 | 0 | 0 | ' | |||
Amortization of debt costs | -1 | 5 | ' | ' | |||
Other | -4 | 5 | -4 | ' | |||
Total other noncash operating activities | -28 | -252 | -184 | ' | |||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ' | ' | |||
Under/over-recovered energy and transmission costs | -35 | 28 | -49 | ' | |||
Other regulatory assets and liabilities | -43 | -68 | 44 | ' | |||
Other current assets and liabilities | -2 | -7 | -14 | ' | |||
Other noncurrent assets and liabilities | 268 | -95 | 64 | ' | |||
Total changes in other assets and liabilities | 188 | -142 | 45 | ' | |||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ' | ' | |||
Change in ARC | 0 | 2 | ' | ' | |||
Capital expenditures not paid | -8 | 15 | 7 | ' | |||
Allocation Of Tax Benefit From Parent | 176 | 11 | 11 | ' | |||
Indemnification of like-kind exchange position | -176 | ' | ' | ' | |||
PECO Energy Co [Member] | ' | ' | ' | ' | |||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ' | ' | |||
Property, plant and equipment | 219 | 207 | 191 | ' | |||
Regulatory assets | 9 | 10 | 11 | ' | |||
Nuclear fuel | 0 | 0 | 0 | ' | |||
Asset retirement obligation accretion | 0 | 0 | [2] | 0 | [2] | ' | |
Total depreciation, amortization and accretion | 228 | 217 | 202 | ' | |||
Cash Paid Refunded During Year [Abstract] | ' | ' | ' | ' | |||
Interest (net of amount capitalized) | 95 | 113 | 128 | ' | |||
Income taxes (net of refunds) | 70 | -64 | -65 | ' | |||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ' | ' | |||
Pension and non-pension postretirement benefits costs | 43 | 50 | 32 | ' | |||
Provision for uncollectible accounts | 61 | 60 | 64 | ' | |||
ARO adjustment | ' | 0 | 0 | ' | |||
Amortization of regulatory asset related to debt costs | 3 | 3 | 3 | ' | |||
Amortization of debt costs | -2 | 3 | ' | ' | |||
Other | -1 | 9 | 1 | ' | |||
Total other noncash operating activities | -108 | -125 | -100 | ' | |||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ' | ' | |||
Under/over-recovered energy and transmission costs | 9 | 20 | 4 | ' | |||
Other regulatory assets and liabilities | -16 | 18 | 26 | ' | |||
Other current assets and liabilities | 13 | -12 | ' | ' | |||
Other noncurrent assets and liabilities | -12 | -10 | -4 | ' | |||
Total changes in other assets and liabilities | -6 | 16 | 14 | ' | |||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ' | ' | |||
Capital expenditures not paid | 13 | 26 | -35 | ' | |||
Allocation Of Tax Benefit From Parent | 27 | 9 | 18 | ' | |||
Indemnification of like-kind exchange position | -27 | -9 | -18 | ' | |||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ' | ' | |||
Amount included in capital expenditures | 27 | 56 | ' | ' | |||
Smart Grid Grant Reimbursements | 37 | 66 | ' | ' | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | |||
Depreciation, Amortization and Accretion [Abstract] | ' | ' | ' | ' | |||
Property, plant and equipment | 264 | 245 | 224 | ' | |||
Regulatory assets | 84 | 53 | 50 | ' | |||
Total depreciation, amortization and accretion | 348 | 298 | 274 | ' | |||
Cash Paid Refunded During Year [Abstract] | ' | ' | ' | ' | |||
Interest (net of amount capitalized) | 130 | 136 | 122 | ' | |||
Income taxes (net of refunds) | 42 | -112 | -54 | ' | |||
Other Non-Cash Operating Activities [Abstract] | ' | ' | ' | ' | |||
Pension and non-pension postretirement benefits costs | 56 | 57 | 51 | ' | |||
Provision for uncollectible accounts | 44 | 44 | 44 | ' | |||
Amortization of regulatory asset related to debt costs | ' | 2 | 2 | ' | |||
Amortization of rate stabilization deferral | 66 | 67 | 57 | ' | |||
Deferral of storm costs | -16 | ' | 16 | ' | |||
Merger related commitments | ' | 27 | [6] | ' | ' | ||
Amortization of debt costs | -2 | 2 | ' | ' | |||
Other | -15 | -6 | -9 | ' | |||
Total other noncash operating activities | -153 | -193 | -129 | ' | |||
Changes In Other Assets and Liabilities [Abstract] | ' | ' | ' | ' | |||
Under/over-recovered energy and transmission costs | 38 | 26 | -52 | ' | |||
Other regulatory assets and liabilities | -71 | -112 | 10 | ' | |||
Other current assets and liabilities | -8 | -7 | -88 | ' | |||
Other noncurrent assets and liabilities | -23 | 8 | -31 | ' | |||
Total changes in other assets and liabilities | -64 | -85 | -161 | ' | |||
Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract] | ' | ' | ' | ' | |||
Change in ARC | ' | 4 | ' | ' | |||
Capital expenditures not paid | -48 | -4 | -7 | ' | |||
Indemnification of like-kind exchange position | 0 | -66 | 0 | ' | |||
DOE Smart Grid Investment Grant [Abstract] | ' | ' | ' | ' | |||
Amount included in capital expenditures | 47 | 47 | ' | ' | |||
Smart Grid Grant Reimbursements | $58 | $47 | ' | ' | |||
[1] | Included in revenues or fuel expense, or operating revenues on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||
[2] | Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income. | ||||||
[3] | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | ||||||
[4] | In May 2011, as a result of the 2010 Rate Case order, ComEd recorded one-time benefits to reestablish previously expensed plant balances and to recover previously incurred costs related to Exelon's 2009 restructuring plan. See Note 3 - Regulatory Matters for more information. | ||||||
[5] | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 b Regulatory Matters for more information. | ||||||
[6] | Relates to the integration costs to achieve distribution synergies related to the merger transaction. See Note 4 b Mergers and Acquisitions for more information on merger-related commitments. | ||||||
[7] | Relates to an other than temporary decline in the estimated residual value of one of Exelonbs direct financing leases. See Note 8 b Impairment of Long-Lived Assets for more information. | ||||||
[8] | Relates to the cancellation of uprate projects and write down of certain wind projects at Generation. See Note 8 b Impairment of Long-Lived Assets for more information. | ||||||
[9] | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | ||||||
[10] | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. |
Supplemental_Financial_Informa4
Supplemental Financial Information - Balance Sheet (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2011 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | $1,925,000,000 | $1,849,000,000 | ||
Total Equity Method Investments | ' | 2,324,000,000 | 2,270,000,000 | ||
Other Investments [Abstract] | ' | ' | ' | ||
Total investments | ' | 3,112,000,000 | 3,055,000,000 | ||
Supplemental Financial Information Textuals [Abstract] | ' | ' | ' | ||
Payment to IRS | 302,000,000 | ' | ' | ||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ||
Estimated residual value of leased assets | ' | 1,465,000,000 | 1,492,000,000 | ||
Less: unearned income | ' | -767,000,000 | -807,000,000 | ||
Net investment in long-term leases | ' | 698,000,000 | 685,000,000 | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Compensation-related accruals | ' | 683,000,000 | [1] | 708,000,000 | [1] |
Taxes accrued | ' | 315,000,000 | 353,000,000 | ||
Interest accrued | ' | 234,000,000 | 232,000,000 | ||
Severance accrued | ' | 66,000,000 | 91,000,000 | ||
Other accrued expenses | ' | 335,000,000 | [2] | 412,000,000 | [2] |
Total accrued expenses | ' | 1,633,000,000 | 1,796,000,000 | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables | ' | 19,000,000 | 18,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 13,713,000,000 | [3] | 12,184,000,000 | [3] |
Accumulated amortization of nuclear fuel | ' | 2,371,000,000 | ' | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | -272,000,000 | -293,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | -2,040,000,000 | -2,767,000,000 | ||
Capital Leases Net Investment In Direct Financing Leases [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 698,000,000 | 685,000,000 | ||
Trust For Benefit Of Employees [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 90,000,000 | [4] | 100,000,000 | [4] |
Financing Trusts [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 22,000,000 | [5] | 22,000,000 | [5] |
Keystone Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 32,000,000 | 38,000,000 | ||
Conemaugh Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 21,000,000 | 26,000,000 | ||
CENG [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 1,925,000,000 | 1,849,000,000 | ||
Safe Harbor [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 285,000,000 | 293,000,000 | ||
Malacha [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 8,000,000 | 8,000,000 | ||
Sacramento Solar [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 31,000,000 | 34,000,000 | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 1,925,000,000 | 1,849,000,000 | ||
Total Equity Method Investments | ' | 2,302,000,000 | 2,247,000,000 | ||
Other Investments [Abstract] | ' | ' | ' | ||
Total investments | ' | 2,325,000,000 | 2,269,000,000 | ||
Capital Leases, Net Investment in Direct Financing Leases [Abstract] | ' | ' | ' | ||
Net investment in long-term leases | ' | 693,000,000 | ' | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Compensation-related accruals | ' | 337,000,000 | [1] | 371,000,000 | [1] |
Taxes accrued | ' | 212,000,000 | 247,000,000 | ||
Interest accrued | ' | 72,000,000 | 60,000,000 | ||
Severance accrued | ' | 31,000,000 | 42,000,000 | ||
Other accrued expenses | ' | 324,000,000 | [2] | 396,000,000 | [2] |
Total accrued expenses | ' | 976,000,000 | 1,116,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 7,034,000,000 | [6] | 6,014,000,000 | [6] |
Accumulated amortization of nuclear fuel | ' | ' | 2,078,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | -57,000,000 | -84,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | 214,000,000 | 513,000,000 | ||
Exelon Generation Co L L C [Member] | Trust For Benefit Of Employees [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 23,000,000 | [4] | 22,000,000 | [4] |
Exelon Generation Co L L C [Member] | Financing Trusts [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | ' | 0 | [5] | |
Exelon Generation Co L L C [Member] | Keystone Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 32,000,000 | 38,000,000 | ||
Exelon Generation Co L L C [Member] | Conemaugh Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 21,000,000 | 26,000,000 | ||
Exelon Generation Co L L C [Member] | CENG [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 1,925,000,000 | 1,849,000,000 | ||
Exelon Generation Co L L C [Member] | Safe Harbor [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 285,000,000 | 293,000,000 | ||
Exelon Generation Co L L C [Member] | Malacha [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 8,000,000 | 8,000,000 | ||
Exelon Generation Co L L C [Member] | Sacramento Solar [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 31,000,000 | 33,000,000 | ||
Commonwealth Edison Co [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Total Equity Method Investments | ' | 6,000,000 | 6,000,000 | ||
Other Investments [Abstract] | ' | ' | ' | ||
Total investments | ' | 11,000,000 | 14,000,000 | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Compensation-related accruals | ' | 135,000,000 | [1] | 125,000,000 | [1] |
Taxes accrued | ' | 62,000,000 | 61,000,000 | ||
Interest accrued | ' | 95,000,000 | 96,000,000 | ||
Severance accrued | ' | 3,000,000 | 4,000,000 | ||
Other accrued expenses | ' | 12,000,000 | 9,000,000 | ||
Total accrued expenses | ' | 307,000,000 | 295,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 3,184,000,000 | 2,998,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | -62,000,000 | -70,000,000 | ||
Commonwealth Edison Co [Member] | Trust For Benefit Of Employees [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 5,000,000 | [4] | 8,000,000 | [4] |
Commonwealth Edison Co [Member] | Financing Trusts [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 6,000,000 | [5] | 6,000,000 | [5] |
Commonwealth Edison Co [Member] | Keystone Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | ' | 0 | ||
Commonwealth Edison Co [Member] | Conemaugh Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | ' | 0 | ||
PECO Energy Co [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Total Equity Method Investments | ' | 8,000,000 | 8,000,000 | ||
Other Investments [Abstract] | ' | ' | ' | ||
Total investments | ' | 31,000,000 | 30,000,000 | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Compensation-related accruals | ' | 47,000,000 | [1] | 45,000,000 | [1] |
Taxes accrued | ' | 24,000,000 | 3,000,000 | ||
Interest accrued | ' | 32,000,000 | 32,000,000 | ||
Severance accrued | ' | 1,000,000 | 1,000,000 | ||
Other accrued expenses | ' | 2,000,000 | 1,000,000 | ||
Total accrued expenses | ' | 106,000,000 | 82,000,000 | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | ' | -18,000,000 | -15,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 2,935,000,000 | 2,797,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | -107,000,000 | -99,000,000 | ||
Accumulated Other Comprehensive Income (Loss) [Abstract] | ' | ' | ' | ||
Accumulated other comprehensive income (loss), net | ' | 1,000,000 | 1,000,000 | ||
PECO Energy Co [Member] | Low Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables uncollectible accounts reserve | ' | -1,000,000 | -1,000,000 | ||
PECO Energy Co [Member] | Medium Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables | ' | 4,000,000 | 3,000,000 | ||
PECO Energy Co [Member] | High Risk [Member] | ' | ' | ' | ||
Financing Receivable Recorded Investment [Line Items] | ' | ' | ' | ||
Installment plan receivables | ' | 13,000,000 | 11,000,000 | ||
PECO Energy Co [Member] | Trust For Benefit Of Employees [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 23,000,000 | [4] | 22,000,000 | [4] |
PECO Energy Co [Member] | Financing Trusts [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | 8,000,000 | [5] | 8,000,000 | [5] |
PECO Energy Co [Member] | Keystone Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | ' | 0 | ||
PECO Energy Co [Member] | Conemaugh Fuels [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | ' | 0 | ||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Total Equity Method Investments | ' | 8,000,000 | 8,000,000 | ||
Other Investments [Abstract] | ' | ' | ' | ||
Total investments | ' | 13,000,000 | 13,000,000 | ||
Accrued Liabilities Current [Abstract] | ' | ' | ' | ||
Compensation-related accruals | ' | 55,000,000 | [1] | 38,000,000 | [1] |
Taxes accrued | ' | 16,000,000 | 22,000,000 | ||
Interest accrued | ' | 29,000,000 | 37,000,000 | ||
Severance accrued | ' | 4,000,000 | 5,000,000 | ||
Other accrued expenses | ' | ' | 0 | ||
Total accrued expenses | ' | 111,000,000 | 102,000,000 | ||
Property, Plant And Equipment [Abstract] | ' | ' | ' | ||
Accumulated depreciation | ' | 2,702,000,000 | 2,595,000,000 | ||
Accounts receivable, net | ' | ' | ' | ||
Allowance for uncollectible accounts | ' | -46,000,000 | -40,000,000 | ||
Baltimore Gas and Electric Company [Member] | Trust For Benefit Of Employees [Member] | ' | ' | ' | ||
Other Investments [Abstract] | ' | ' | ' | ||
Other Investments | ' | 5,000,000 | 5,000,000 | [4] | |
Baltimore Gas and Electric Company [Member] | Financing Trusts [Member] | ' | ' | ' | ||
Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract] | ' | ' | ' | ||
Equity Method Investments | ' | $8,000,000 | [5] | $8,000,000 | [5] |
[1] | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. | ||||
[2] | Includes $228 million and $327 million for amounts accrued related to Antelope Valley as of December 31, 2013 and December 31, 2012, respectively. | ||||
[3] | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. | ||||
[4] | The Registrants' investments in these marketable securities are recorded at fair market value. | ||||
[5] | Includes investments in financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in affiliates on the Consolidated Balance Sheets. See Note 1 - Significant Accounting Policies for additional information. | ||||
[6] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million and $2,078 million as of December 31, 2013 and 2012, respectively. |
Segment_Information_Details
Segment Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | $6,163,000,000 | $6,502,000,000 | $6,141,000,000 | $6,082,000,000 | $6,254,000,000 | $6,579,000,000 | $5,966,000,000 | $4,690,000,000 | $24,888,000,000 | $23,489,000,000 | $19,063,000,000 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 48,000,000 | 9,000,000 | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 2,773,000,000 | 1,798,000,000 | 3,956,000,000 | |||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 2,153,000,000 | 1,881,000,000 | 1,347,000,000 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 21,242,000,000 | 21,018,000,000 | 14,583,000,000 | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 1,356,000,000 | 928,000,000 | 726,000,000 | |||||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,044,000,000 | 627,000,000 | 1,457,000,000 | |||||
Net income (loss) | 495,000,000 | 738,000,000 | 490,000,000 | -4,000,000 | 378,000,000 | 296,000,000 | 286,000,000 | 200,000,000 | 1,729,000,000 | 1,171,000,000 | 2,499,000,000 | |||||
Equity in earnings (losses) of unconsolidated affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | -91,000,000 | -1,000,000 | |||||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 5,395,000,000 | 5,789,000,000 | 4,042,000,000 | |||||
Total assets | 79,924,000,000 | ' | ' | ' | 78,561,000,000 | ' | ' | ' | 79,924,000,000 | 78,561,000,000 | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Number of reportable segments | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | 449,000,000 | [1] | 463,000,000 | [1] | 443,000,000 | [1] | ||
Unrealized Gain (Loss) on Derivatives | ' | ' | ' | ' | ' | ' | ' | ' | 445,000,000 | 604,000,000 | -291,000,000 | |||||
Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 14,000,000 | 6,000,000 | 9,000,000 | |||||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -14,000,000 | ' | -9,000,000 | |||||
PECO Energy Co Affiliate [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | [2] | 6,000,000 | [2] | 9,000,000 | [2] | ||
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Number of reportable segments | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | 79,000,000 | 82,000,000 | 27,000,000 | |||||
Exelon Generation Co L L C [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,660,000,000 | 1,161,000,000 | |||||
Exelon Generation Co L L C [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 15,630,000,000 | 14,437,000,000 | 10,447,000,000 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 1,367,000,000 | ' | ' | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,675,000,000 | [3] | 1,058,000,000 | [3] | 2,827,000,000 | [3] | ||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 856,000,000 | 768,000,000 | 570,000,000 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 13,976,000,000 | 13,226,000,000 | 7,571,000,000 | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 357,000,000 | [3] | 301,000,000 | [3] | 170,000,000 | [3] | ||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 615,000,000 | [3] | 500,000,000 | [3] | 1,056,000,000 | [3] | ||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 1,060,000,000 | [3] | 558,000,000 | [3] | 1,771,000,000 | [3] | ||
Equity in earnings (losses) of unconsolidated affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | -91,000,000 | -1,000,000 | |||||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 2,752,000,000 | 3,554,000,000 | 2,491,000,000 | |||||
Total assets | 41,232,000,000 | [3] | ' | ' | ' | 40,681,000,000 | [3] | ' | ' | ' | 41,232,000,000 | [3] | 40,681,000,000 | [3] | ' | |
Generation Mid Atlantic [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 5,204,000,000 | 5,038,000,000 | 4,052,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 3,273,290,670.04 | 3,477,000,000 | 3,350,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -3,290,670.04 | -44,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 3,270,000,000 | 3,433,000,000 | 3,350,000,000 | |||||
Generation Mid Atlantic [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | -44,000,000 | ' | |||||
Generation Mid Atlantic [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 5,182,000,000 | 5,082,000,000 | 4,052,000,000 | |||||
Generation Midwest [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 4,270,000,000 | 4,848,000,000 | 5,445,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 2,585,039,304.94 | 2,974,000,000 | 3,547,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | 960,695.06 | 24,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 2,586,000,000 | 2,998,000,000 | 3,547,000,000 | |||||
Generation Midwest [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -10,000,000 | 24,000,000 | ' | |||||
Generation Midwest [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 4,280,000,000 | 4,824,000,000 | 5,445,000,000 | |||||
Generation Midwest [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Unrealized Gain (Loss) on Derivatives | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | |||||
Generation New England [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,237,000,000 | 1,093,000,000 | 11,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 216,782,130.36 | 151,000,000 | 9,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -31,782,130.36 | 45,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 185,000,000 | 196,000,000 | 9,000,000 | |||||
Generation New England [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -8,000,000 | 45,000,000 | ' | |||||
Generation New England [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,245,000,000 | 1,048,000,000 | 11,000,000 | |||||
Generation New York [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 714,000,000 | 557,000,000 | 0 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 14,398,673.46 | 101,000,000 | ' | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -18,398,673.46 | -25,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | -4,000,000 | 76,000,000 | ' | |||||
Generation New York [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -21,000,000 | -25,000,000 | ' | |||||
Generation New York [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 735,000,000 | 582,000,000 | 0 | |||||
Generation ERCOT [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,216,000,000 | 1,367,000,000 | 575,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 604,261,280.16 | 403,000,000 | 84,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -168,261,280.16 | 2,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 436,000,000 | 405,000,000 | 84,000,000 | |||||
Generation ERCOT [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -6,000,000 | 2,000,000 | ' | |||||
Generation ERCOT [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,222,000,000 | 1,365,000,000 | 575,000,000 | |||||
Generation Other Regions [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 968,000,000 | 833,000,000 | 201,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 333,648,771.48 | [4] | 53,000,000 | [4] | -14,000,000 | [4] | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -132,648,771.48 | [4] | 78,000,000 | ' | ||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 201,000,000 | [4] | 131,000,000 | [4] | -14,000,000 | [4] | ||
Generation Other Regions [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | 78,000,000 | ' | |||||
Generation Other Regions [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 946,000,000 | 755,000,000 | 201,000,000 | |||||
Generation Reportable Segments Total [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 13,609,000,000 | 13,736,000,000 | 10,284,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 7,027,420,830.44 | 7,159,000,000 | 6,976,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | -353,420,830.44 | 80,000,000 | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 6,674,000,000 | 7,239,000,000 | 6,976,000,000 | |||||
Generation Reportable Segments Total [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | 80,000,000 | ' | |||||
Generation Reportable Segments Total [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 13,610,000,000 | 13,656,000,000 | 10,284,000,000 | |||||
Generation Total Consolidated Group [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 15,630,000,000 | 14,437,000,000 | 10,447,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 7,433,011,008.07 | 7,376,000,000 | 6,858,000,000 | |||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | |||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 7,432,611,007.56 | 7,376,000,000 | 6,858,000,000 | |||||
Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | ' | |||||
Generation Total Consolidated Group [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 15,630,000,000 | 14,437,000,000 | 10,447,000,000 | |||||
Generation All Other Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 2,021,000,000 | 701,000,000 | 163,000,000 | |||||
Revenue net of purchased power and fuel expense from external customers | ' | ' | ' | ' | ' | ' | ' | ' | 405,590,177.63 | [5] | 217,000,000 | [5] | -118,000,000 | [5] | ||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | ' | ' | ' | ' | ' | ' | ' | ' | 353,020,829.93 | [5] | -80,000,000 | ' | ||||
Revenue net of purchased power and fuel expense, Total | ' | ' | ' | ' | ' | ' | ' | ' | 758,611,007.56 | [5] | 137,000,000 | [5] | -118,000,000 | [5] | ||
Generation All Other Segments [Member] | Other Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 2,020,000,000 | ' | ' | |||||
Generation All Other Segments [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | |||||
Generation All Other Segments [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 781,000,000 | 163,000,000 | |||||
Generation All Other Segments [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | -80,000,000 | ' | |||||
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | ' | 239,000,000 | 243,000,000 | |||||
Commonwealth Edison Co [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | 2,000,000 | |||||
Commonwealth Edison Co [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 4,464,000,000 | 5,443,000,000 | 6,056,000,000 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | ' | ' | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 401,000,000 | 618,000,000 | 666,000,000 | |||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 669,000,000 | 610,000,000 | 554,000,000 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 3,510,000,000 | 4,557,000,000 | 5,074,000,000 | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 579,000,000 | 307,000,000 | 345,000,000 | |||||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 152,000,000 | 239,000,000 | 250,000,000 | |||||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 249,000,000 | 379,000,000 | 416,000,000 | |||||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 1,433,000,000 | 1,246,000,000 | 1,028,000,000 | |||||
Total assets | 24,118,000,000 | ' | ' | ' | 22,905,000,000 | ' | ' | ' | 24,118,000,000 | 22,905,000,000 | ' | |||||
Commonwealth Edison Co [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | 241,000,000 | ' | ' | |||||
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | 129,000,000 | 141,000,000 | 173,000,000 | |||||
PECO Energy Co [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3,000,000 | 5,000,000 | |||||
PECO Energy Co [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 3,100,000,000 | 3,186,000,000 | 3,720,000,000 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | ' | ' | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 557,000,000 | 508,000,000 | 535,000,000 | |||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 228,000,000 | 217,000,000 | 202,000,000 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 2,434,000,000 | ' | 3,065,000,000 | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 115,000,000 | 123,000,000 | 134,000,000 | |||||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 162,000,000 | 127,000,000 | 146,000,000 | |||||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 395,000,000 | 381,000,000 | 389,000,000 | |||||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 537,000,000 | 422,000,000 | 481,000,000 | |||||
Total assets | 9,617,000,000 | ' | ' | ' | 9,353,000,000 | ' | ' | ' | 9,617,000,000 | 9,353,000,000 | ' | |||||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | 210,000,000 | [6] | -31,000,000 | ' | ||||
Segment Reporting Additional Information [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Utility taxes | ' | ' | ' | ' | ' | ' | ' | ' | 82,000,000 | ' | ' | |||||
Baltimore Gas and Electric Company [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9,000,000 | 0 | |||||
Baltimore Gas and Electric Company [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 3,065,000,000 | 2,091,000,000 | 0 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 344,000,000 | [6] | -54,000,000 | [6] | ' | |||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 348,000,000 | 238,000,000 | 0 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 2,616,000,000 | 2,053,000,000 | ' | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 122,000,000 | [6] | 111,000,000 | [6] | ' | |||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 134,000,000 | [6] | -23,000,000 | [6] | ' | |||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 587,000,000 | 500,000,000 | ' | |||||
Total assets | 7,861,000,000 | [6] | ' | ' | ' | 7,506,000,000 | [6] | ' | ' | ' | 7,861,000,000 | [6] | 7,506,000,000 | [6] | ' | |
Corporate and Other [Member] | Other Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | 1,241,000,000 | 1,396,000,000 | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,381,000,000 | 831,000,000 | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -191,000,000 | [7] | -325,000,000 | [7] | -59,000,000 | [7] | ||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 52,000,000 | 48,000,000 | 21,000,000 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | 1,324,000,000 | 1,662,000,000 | 863,000,000 | |||||
Interest Revenue (Expense), Net | ' | ' | ' | ' | ' | ' | ' | ' | 183,000,000 | [7] | 86,000,000 | [7] | 77,000,000 | [7] | ||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -20,000,000 | [7] | -215,000,000 | [7] | 9,000,000 | [7] | ||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | -171,000,000 | -110,000,000 | -68,000,000 | |||||
Capital expenditures | ' | ' | ' | ' | ' | ' | ' | ' | 86,000,000 | 67,000,000 | 42,000,000 | |||||
Total assets | 8,317,000,000 | ' | ' | ' | 10,432,000,000 | ' | ' | ' | 8,317,000,000 | 10,432,000,000 | ' | |||||
Corporate and Other [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 830,000,000 | |||||
Corporate and Other [Member] | Operating Segments [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | 1,237,000,000 | ' | ' | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,563,000,000 | ' | |||||
Segment Elimination [Member] | Intersegment Eliminations [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Segment Reporting Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | |||||
Revenues | ' | ' | ' | ' | ' | ' | ' | ' | -2,612,000,000 | -3,064,000,000 | -1,990,000,000 | |||||
Operating revenues from affiliates | ' | ' | ' | ' | ' | ' | ' | ' | -2,607,000,000 | -3,049,000,000 | -1,990,000,000 | |||||
Income (loss) from continuing operations before income taxes | ' | ' | ' | ' | ' | ' | ' | ' | -13,000,000 | -7,000,000 | -13,000,000 | |||||
Depreciation and amortization | ' | ' | ' | ' | ' | ' | ' | ' | 0 | 0 | 0 | |||||
Operating Expenses | ' | ' | ' | ' | ' | ' | ' | ' | -2,618,000,000 | -3,043,000,000 | -1,990,000,000 | |||||
Income taxes | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | -1,000,000 | -4,000,000 | |||||
Net income (loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6,000,000 | ' | |||||
Total assets | ($11,221,000,000) | ' | ' | ' | ($12,316,000,000) | ' | ' | ' | ($11,221,000,000) | ($12,316,000,000) | ' | |||||
[1] | Generation's utility tax represents gross receipts tax related to its retail operations and ComEd's, PECO's and BGEbs utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants' Consolidated Statements of Operations | |||||||||||||||
[2] | The intersegment profit associated with the sale of certain products and services by and between Exelonbs segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3 - Regulatory Matters for additional information. | |||||||||||||||
[3] | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the year ended December 31, 2013 include revenue from sales to PECO of $405 and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012 include revenue from sales to PECO of $543 and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended 2011 intersegment revenues for Generation include revenue from sales to PECO of $508 million in the Mid-Atlantic region, and sales to ComEd of $653 million in the Midwest region. | |||||||||||||||
[4] | Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||||
[5] | Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $767 million and $1,505 million for the years ended December 31, 2013 and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||
[6] | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2013. | |||||||||||||||
[7] | Other primarily includes Exelonbs corporate operations, shared service entities and other financing and investment activities. |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | |||
CENG | $123 | $73 | ' | |||
Amortization of basis difference in CENG | -114 | -172 | ' | |||
Total equity investment earnings (losses) - CENG | 9 | -99 | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | ' | 48 | 9 | |||
Total fuel purchases from related parties | 1,256 | 1,036 | 137 | |||
Charitable contributions to Exelon Foundation | 0 | [1] | 0 | [1] | 0 | [1] |
Total interest expense to affiliates, net | 41 | 37 | 25 | |||
Total income (loss) in equity method investments | 10 | -91 | -1 | |||
Cash dividends paid to parent | 1,249 | 1,716 | 1,393 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | ' | 2,039 | ' | |||
Investments in affiliates | 22 | 22 | ' | |||
Total payables to affiliates (current) | ' | 112 | ' | |||
Long-term debt to financing trusts | 648 | 648 | ' | |||
Equity Method Investment Summarized Financial Information[Abstract] | ' | ' | ' | |||
Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent) | 85.00% | ' | ' | |||
Purchase of nuclear output of CENG (as a percent) | 50.01% | ' | ' | |||
Purchase of nuclear output by EDF (as a percent) | 49.99% | ' | ' | |||
Amortization of energy contract assets and liabilities | 430 | 1,110 | ' | |||
Minimum [Member] | ' | ' | ' | |||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | |||
Percentage of ownership interest in CENG (as a percent) | 20.00% | ' | ' | |||
Maximum [Member] | ' | ' | ' | |||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | |||
Percentage of ownership interest in CENG (as a percent) | 50.00% | ' | ' | |||
ComEd Financing Three Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 6 | 6 | ' | |||
Total payables to affiliates (current) | 4 | ' | ' | |||
Long-term debt to financing trusts | 206 | 206 | ' | |||
Conemaugh Fuels LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total fuel purchases from related parties | 98 | 101 | 69 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 9 | 9 | ' | |||
Exelon Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | ' | 2 | ' | |||
Keystone Fuels LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total fuel purchases from related parties | 144 | 119 | 68 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 12 | 11 | ' | |||
NuStart Energy Development LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 0 | 0 | ' | |||
Constellation Energy Nuclear Group Llc Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 56 | [2] | 42 | [2] | ' | |
Total fuel purchases from related parties | 992 | [2] | 793 | [2] | ' | |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | 3 | [2] | 16 | [2] | ' | |
Total payables to affiliates (current) | 85 | [2] | 83 | [2] | ' | |
CENG Equity Investment Income Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 9 | -99 | ' | |||
Amortization Of Basis Difference In Ceng Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 0 | [2] | 0 | [2] | ' | |
Other Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 1 | 8 | -1 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 1 | 0 | ' | |||
PECO Energy Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 10 | [3] | 6 | [3] | 9 | [3] |
PECO Energy Capital Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 4 | 4 | ' | |||
PECO Trust Three Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 1 | 1 | ' | |||
Long-term debt to financing trusts | 81 | 81 | ' | |||
PECO Trust Four Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 4 | 4 | ' | |||
Total payables to affiliates (current) | 0 | 0 | ' | |||
Long-term debt to financing trusts | 103 | 103 | ' | |||
BGE Capital Trust II [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 8 | 8 | ' | |||
Total payables to affiliates (current) | 4 | 4 | ' | |||
Long-term debt to financing trusts | 258 | 258 | ' | |||
SafeHarborWaterPowerCorp [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Purchased power from affiliate | 22 | 23 | ' | |||
Exelon Generation Co L L C [Member] | ' | ' | ' | |||
Schedule of Equity Method Investments [Line Items] | ' | ' | ' | |||
Percentage of ownership interest in CENG (as a percent) | 50.01% | ' | ' | |||
Basis difference in investment in CENG | 204 | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 1,423 | 1,702 | 1,161 | |||
Total fuel purchases from related parties | 1,270 | 1,044 | 138 | |||
Operating and maintenance from affiliate | 574 | 630 | 321 | |||
Total interest expense to affiliates, net | 59 | 75 | ' | |||
Total income (loss) in equity method investments | 10 | -91 | -1 | |||
Cash distribution paid to member | 625 | 1,626 | 172 | |||
Contributions from member | 26 | 48 | 30 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets with affiliates | ' | 226 | ' | |||
Total receivables from affiliates (current) | 108 | 141 | ' | |||
Total receivable from affiliates (noncurrent) | 22 | 22 | ' | |||
Total payables to affiliates (current) | 181 | 213 | ' | |||
Total payables to affiliates (noncurrent) | 2,740 | 2,397 | ' | |||
Equity Method Investment Summarized Financial Information[Abstract] | ' | ' | ' | |||
Purchase of nuclear output by EDF (as a percent) | 49.99% | ' | ' | |||
Amortization of energy contract assets and liabilities | 507 | 1,110 | ' | |||
Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 1 | 0 | 0 | |||
Operating and maintenance from affiliate | 571 | [4] | 625 | [4] | 314 | [4] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 66 | [4] | 77 | [4] | ' | |
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 506 | [5] | 795 | [5] | 653 | [5] |
Total fuel purchases from related parties | 1 | 0 | 0 | |||
Operating and maintenance from affiliate | 2 | [6] | 2 | [6] | 2 | [6] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Mark-to-market derivative assets with affiliates | 0 | [7] | 226 | [7] | ' | |
Total receivables from affiliates (current) | 38 | [5],[8] | 54 | [5],[8] | ' | |
Mark-to-market derivative assets with affiliate (noncurrent assets) | 0 | [7] | 0 | [7] | ' | |
Total payables to affiliates (noncurrent) | 2,293 | [9] | 2,037 | [9] | ' | |
Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total fuel purchases from related parties | 98 | 101 | 69 | |||
Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total interest expense to affiliates, net | 59 | 75 | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 0 | 1 | ' | |||
Total payables to affiliates (current) | 7 | [10] | 33 | [10] | ' | |
Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total fuel purchases from related parties | 144 | 119 | 68 | |||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 56 | [2] | 42 | [2] | ' | |
Total fuel purchases from related parties | 992 | [2] | 793 | [2] | ' | |
Operating and maintenance from affiliate | 0 | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 85 | [2] | 83 | [2] | ' | |
Exelon Generation Co L L C [Member] | CENG Equity Investment Income Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 9 | -99 | ' | |||
Exelon Generation Co L L C [Member] | Amortization Of Basis Difference In Ceng Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 0 | [2] | 0 | [2] | ' | |
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 405 | [11] | 543 | [11] | 508 | [11] |
Total fuel purchases from related parties | 0 | 0 | 1 | |||
Operating and maintenance from affiliate | 1 | [6] | 3 | [6] | 5 | [6] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | 38 | [11] | 56 | [11] | ' | |
Total payables to affiliates (noncurrent) | 447 | [9] | 360 | [9] | ' | |
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 455 | [12] | 322 | [12] | ' | |
Total fuel purchases from related parties | 13 | 8 | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | 27 | [12] | 31 | [12] | ' | |
Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total income (loss) in equity method investments | 1 | 8 | -1 | |||
Exelon Generation Co L L C [Member] | SafeHarborWaterPowerCorp [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Purchased power from affiliate | 22 | 23 | ' | |||
Commonwealth Edison Co [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 3 | 2 | 2 | |||
Purchased power from affiliate | 512 | 789 | 653 | |||
Operating and maintenance from affiliate | 157 | 163 | 158 | |||
Total interest expense to affiliates, net | 13 | 13 | 15 | |||
Total income (loss) in equity method investments | 0 | 0 | 0 | |||
Cash dividends paid to parent | 220 | 105 | 300 | |||
Contributions from parent | 176 | ' | ' | |||
Non-cash contribution to equity | ' | 11 | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | 3 | 3 | ' | |||
Total receivable from affiliates (noncurrent) | 2,469 | 2,039 | ' | |||
Prepaid voluntary employee beneficiary association trust | 13 | [13] | 10 | [13] | ' | |
Investments in affiliates | 6 | 6 | ' | |||
Total payables to affiliates (current) | 83 | 97 | ' | |||
Mark-to-market derivative liabilities with affiliate (current liabilities) | 0 | 226 | ' | |||
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities) | 0 | 0 | ' | |||
Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating and maintenance from affiliate | 157 | [14] | 163 | [14] | 158 | [14] |
Capitalized Costs | 69 | [14] | 92 | [14] | 85 | [14] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 30 | [14] | 35 | [14] | ' | |
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 6 | 6 | ' | |||
Total payables to affiliates (current) | 4 | 4 | ' | |||
Long-term debt to financing trusts | 206 | 206 | ' | |||
Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | ' | 0 | ' | |||
Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 3 | 2 | 2 | |||
Purchased power from affiliate | 512 | [15] | 789 | [15] | 653 | [15] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 2,293 | [16] | 2,037 | [16] | ' | |
Total payables to affiliates (current) | 38 | [15],[17] | 54 | [15],[17] | ' | |
Mark-to-market derivative liabilities with affiliate (current liabilities) | 0 | [18] | 226 | [18] | ' | |
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities) | 0 | [18] | 0 | [18] | ' | |
Commonwealth Edison Co [Member] | Other Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 176 | 2 | ' | |||
Total payables to affiliates (current) | 2 | 2 | ' | |||
Commonwealth Edison Co [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | ' | 3 | ' | |||
Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivables from affiliates (current) | 3 | ' | ' | |||
PECO Energy Co [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 1 | 3 | 5 | |||
Purchased power from affiliate | 392 | 533 | 495 | |||
Operating and maintenance from affiliate | 101 | 111 | 96 | |||
Total interest expense to affiliates, net | 12 | 12 | 12 | |||
Cash dividends paid to parent | 332 | 343 | 348 | |||
Contributions from parent | 27 | 9 | 18 | |||
Repayment of receivable from parent | 0 | 0 | 0 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 447 | 360 | ' | |||
Prepaid voluntary employee beneficiary association trust | 3 | [19] | 2 | [19] | ' | |
Investments in affiliates | 8 | 8 | ' | |||
Total payables to affiliates (current) | 58 | 76 | ' | |||
Mark-to-market derivative liabilities with affiliate (current liabilities) | 0 | 0 | ' | |||
Mark-to-market derivative liabilities with affiliate (noncurrent liabilities) | 0 | 0 | ' | |||
Long-term debt to financing trusts | 184 | 184 | ' | |||
Shareholders' equity - receivable from parent | 0 | 0 | ' | |||
PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating and maintenance from affiliate | 98 | [20] | 107 | [20] | 92 | [20] |
Capitalized Costs | 46 | [20] | 54 | [20] | 60 | [20] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 17 | [20] | 18 | [20] | ' | |
PECO Energy Co [Member] | Exelon Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 2 | 1 | ' | |||
PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 1 | [21] | 3 | [21] | 5 | [21] |
Purchased power from affiliate | 392 | [22] | 533 | [22] | 495 | [22] |
Operating and maintenance from affiliate | 3 | 4 | 4 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 447 | [23] | 360 | [23] | ' | |
Total payables to affiliates (current) | 38 | [22] | 56 | [22] | ' | |
Mark-to-market derivative liabilities with affiliate (current liabilities) | 0 | 0 | ' | |||
PECO Energy Co [Member] | PECO Energy Capital Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 4 | 4 | ' | |||
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 1 | 1 | ' | |||
Long-term debt to financing trusts | 81 | 81 | ' | |||
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 4 | 4 | ' | |||
Long-term debt to financing trusts | 103 | 103 | ' | |||
PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total receivable from affiliates (noncurrent) | 3 | 2 | ' | |||
Baltimore Gas and Electric Company [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 13 | 10 | 8 | |||
Purchased power from affiliate | 452 | 396 | 348 | |||
Operating and maintenance from affiliate | 83 | 106 | 150 | |||
Total interest expense to affiliates, net | 16 | 16 | 16 | |||
Cash dividends paid to parent | 0 | 0 | ' | |||
Contributions from parent | 0 | 66 | 0 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Prepaid voluntary employee beneficiary association trust | 1 | ' | ' | |||
Investments in affiliates | 8 | 8 | ' | |||
Total payables to affiliates (current) | 55 | 69 | ' | |||
Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating and maintenance from affiliate | 83 | [24] | 106 | [24] | 150 | [24] |
Capitalized Costs | 15 | [24] | 21 | [24] | 29 | [24] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 20 | [24] | 12 | ' | ||
Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 0 | 3 | ' | |||
Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 1 | [25] | 17 | ' | ||
Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Operating revenues from affiliates | 13 | [26] | 10 | [26] | 8 | [26] |
Purchased power from affiliate | 452 | [27] | 396 | [27] | 348 | [27] |
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 27 | [27] | 31 | [27] | ' | |
Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member] | ' | ' | ' | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Total payables to affiliates (current) | 3 | 2 | ' | |||
Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member] | ' | ' | ' | |||
Related Party Income Statement Activity [Abstract] | ' | ' | ' | |||
Total interest expense to affiliates, net | 16 | 16 | 16 | |||
Related Party Balance Sheet [Abstract] | ' | ' | ' | |||
Investments in affiliates | 8 | ' | ' | |||
Total payables to affiliates (current) | 4 | 4 | ' | |||
Long-term debt to financing trusts | $258 | ' | ' | |||
[1] | Exelon Foundation is a nonconsolidated not-for-profit Illinois corporation. The Exelon Foundation was established in 2007 to serve educational and environmental philanthropic purposes and does not serve a direct business or political purpose of Exelon | |||||
[2] | Exelon has a shared services agreement (SSA) with CENG, which expires in 2017. Pursuant to an agreement between Exelon and EDF, the pricing in the SSA for services reflect actual costs determined on the same basis that BSC charges its affiliates for similar services subject to an annual cap for most SSA services provided. In addition to the SSA, Generation has a power services agency agreement (PSAA) with the CENG plants, which expires on December 31, 2014. The PSAA is a five-year agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. At the closing, as described under the Master Agreement, the PSAA will be amended and extended until the complete and permanent cessation of operation of the CENG generation plants. For further information regarding the Investment in CENG see Note 5 b Investment in Constellation Energy Nuclear Group, LLC | |||||
[3] | The intersegment profit associated with the sale of certain products and services by and between Exelonbs segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3 - Regulatory Matters for additional information. | |||||
[4] | Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | |||||
[5] | Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3 - Regulatory Matters for additional information. | |||||
[6] | Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. | |||||
[7] | Represents the fair value of Generation's five-year financial swap contract with ComEd, which ended in 2013. | |||||
[8] | Generation had a $53 million receivable from ComEd at December 31, 2012 associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | |||||
[9] | Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15 - Asset Retirement Obligations. | |||||
[10] | As of December 31, 2013 and 2012, the balance consists of interest owed to Exelon Corporation related to the senior unsecured notes. In addition, the balance at December 31, 2012, includes expense related to certain invoices Exelon Corporation processed on behalf of Generation. | |||||
[11] | Generation provides electric supply to PECO under contracts executed through PECObs competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information. | |||||
[12] | Generation provides a portion of BGEbs energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information. | |||||
[13] | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd's contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets. | |||||
[14] | ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | |||||
[15] | ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation established as part of the Illinois Settlement Legislation. See NoteB 3 - Regulatory Matters and Note 12 - Derivative Financial Instruments for additional information. | |||||
[16] | ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd's customers. | |||||
[17] | ComEd had a $53 million payable to Generation at December 31, 2012, associated with the completed portion of the financial swap contract entered into as part of the Illinois Settlement Legislation. See Note 3 - Regulatory Matters and Note 12 - Derivative Financial Information for additional information. | |||||
[18] | To fulfill a requirement of the Illinois Settlement Legislation, ComEd entered into a five-year financial swap with Generation, which ended in 2013. | |||||
[19] | The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the operating segments. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO's contributions to the plans, being higher than actual claim expense incurred by the plans over time. | |||||
[20] | PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | |||||
[21] | PECO provides energy to Generation for Generation's own use. | |||||
[22] | PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3 - Regulatory Matters for additional information on AECs. | |||||
[23] | PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO's customers. | |||||
[24] | BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. | |||||
[25] | BGE receives a variety of corporate support services from Exelon Corporate, including payroll and benefits services. | |||||
[26] | BGE provides energy to Generation for Generation's own use. | |||||
[27] | BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3 - Regulatory Matters for additional information |
Quarterly_Data_Details
Quarterly Data (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
Share data in Millions, except Per Share data, unless otherwise specified | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Sep. 30, 2012 | Jun. 30, 2012 | Mar. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 |
Earnings Per Share Basic [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Average common shares outstanding - basic | 856 | 857 | 856 | 855 | 854 | 854 | 853 | 705 | 856 | 816 | 663 |
Earnings Per Share, Basic | $0.60 | $0.86 | $0.57 | ($0.01) | $0.44 | $0.35 | $0.34 | $0.28 | ' | ' | ' |
Earnings Per Share Diluted | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Average common shares outstanding - diluted | 860 | 860 | 860 | 855 | 857 | 857 | 856 | 707 | 860 | 819 | 665 |
Earnings Per Share, Diluted | $0.59 | $0.86 | $0.57 | ($0.01) | $0.44 | $0.35 | $0.33 | $0.28 | $2 | $1.42 | $3.75 |
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | $6,163,000,000 | $6,502,000,000 | $6,141,000,000 | $6,082,000,000 | $6,254,000,000 | $6,579,000,000 | $5,966,000,000 | $4,690,000,000 | $24,888,000,000 | $23,489,000,000 | $19,063,000,000 |
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 3,656,000,000 | 2,380,000,000 | 4,479,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 495,000,000 | 738,000,000 | 490,000,000 | -4,000,000 | 378,000,000 | 296,000,000 | 286,000,000 | 200,000,000 | 1,729,000,000 | 1,171,000,000 | 2,499,000,000 |
Operating Income Loss Quarter | 889,000,000 | 1,254,000,000 | 1,005,000,000 | 508,000,000 | 704,000,000 | 603,000,000 | 714,000,000 | 359,000,000 | ' | ' | ' |
Share Price And Dividend [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
High Price | 30.59 | 32.42 | 37.8 | 34.56 | 37.5 | 39.82 | 39.37 | 43.7 | 30.59 | 37.5 | ' |
Low Price | 26.64 | 29.42 | 29.84 | 29.1 | 28.4 | 34.54 | 36.27 | 38.31 | 26.64 | 28.4 | ' |
Close | $27.39 | $29.64 | $30.88 | $34.48 | $29.74 | $35.58 | $37.62 | $39.21 | $27.39 | $29.74 | ' |
Dividends | $0.31 | $0.31 | $0.31 | $0.53 | $0.53 | $0.53 | $0.53 | $0.53 | $0.31 | $0.53 | ' |
Exelon Generation Co L L C [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | 3,772,000,000 | 4,255,000,000 | 4,070,000,000 | 3,533,000,000 | 3,898,000,000 | 4,031,000,000 | 3,765,000,000 | 2,743,000,000 | 15,630,000,000 | 14,437,000,000 | 10,447,000,000 |
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 1,664,000,000 | 1,120,000,000 | 2,875,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 269,000,000 | 490,000,000 | 330,000,000 | -18,000,000 | 137,000,000 | 91,000,000 | 166,000,000 | 168,000,000 | 1,060,000,000 | 558,000,000 | 1,771,000,000 |
Operating Income Loss Quarter | 405,000,000 | 721,000,000 | 603,000,000 | -64,000,000 | 290,000,000 | 174,000,000 | 384,000,000 | 272,000,000 | ' | ' | ' |
Commonwealth Edison Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | 1,068,000,000 | 1,156,000,000 | 1,080,000,000 | 1,160,000,000 | 1,290,000,000 | 1,484,000,000 | 1,281,000,000 | 1,388,000,000 | 4,464,000,000 | 5,443,000,000 | 6,056,000,000 |
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 954,000,000 | 886,000,000 | 982,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 109,000,000 | 126,000,000 | 96,000,000 | -81,000,000 | 160,000,000 | 90,000,000 | 42,000,000 | 87,000,000 | 249,000,000 | 379,000,000 | 416,000,000 |
Operating Income Loss Quarter | 236,000,000 | 278,000,000 | 232,000,000 | 209,000,000 | 300,000,000 | 218,000,000 | 142,000,000 | 226,000,000 | ' | ' | ' |
PECO Energy Co [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | 805,000,000 | 728,000,000 | 672,000,000 | 895,000,000 | 790,000,000 | 806,000,000 | 715,000,000 | 875,000,000 | 3,100,000,000 | 3,186,000,000 | 3,720,000,000 |
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 666,000,000 | 623,000,000 | 655,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 102,000,000 | 92,000,000 | 72,000,000 | 121,000,000 | 79,000,000 | 122,000,000 | 79,000,000 | 96,000,000 | 395,000,000 | 381,000,000 | 389,000,000 |
Operating Income Loss Quarter | 168,000,000 | 155,000,000 | 138,000,000 | 203,000,000 | 117,000,000 | 178,000,000 | 151,000,000 | 177,000,000 | ' | ' | ' |
Baltimore Gas and Electric Company [Member] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Selected Quarterly Financial Information [Line Items] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revenues | 794,000,000 | 737,000,000 | 653,000,000 | 880,000,000 | 703,000,000 | 720,000,000 | 616,000,000 | 697,000,000 | 3,065,000,000 | 2,735,000,000 | 3,068,000,000 |
Operating Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | 449,000,000 | 132,000,000 | 314,000,000 |
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 47,000,000 | 50,000,000 | 22,000,000 | 77,000,000 | 15,000,000 | -4,000,000 | 13,000,000 | -33,000,000 | 210,000,000 | 4,000,000 | 136,000,000 |
Operating Income Loss Quarter | $101,000,000 | $114,000,000 | $69,000,000 | $163,000,000 | $61,000,000 | $30,000,000 | $52,000,000 | ($11,000,000) | ' | ' | ' |
Subsequent_Event_Details
Subsequent Event (Details) (PECO Energy Co [Member]) | Dec. 31, 2013 |
Customers | |
PECO Energy Co [Member] | ' |
Storm Damage Impact [Abstract] | ' |
Customers impacted from storm damage | 715,000 |