Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Jan. 31, 2015 | |
Entity Registrant Name | EXELON CORP | |
Entity Central Index Key | 1109357 | |
Document Type | 10-K | |
Document Period End Date | 31-Dec-14 | |
Amendment Flag | FALSE | |
Document Fiscal Year Focus | 2014 | |
Document Fiscal Period Focus | FY | |
Current Fiscal Year End Date | -19 | |
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 | 859,833,343 | |
Entity Public Float | $31,319,710,373 | |
Exelon Generation Co L L C [Member] | ||
Entity Registrant Name | EXELON GENERATION CO LLC | |
Entity Central Index Key | 1168165 | |
Entity Filer Category | Non-accelerated Filer | |
Commonwealth Edison Co [Member] | ||
Entity Registrant Name | COMMONWEALTH EDISON CO | |
Entity Central Index Key | 22606 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock Shares Outstanding | 127,016,950 | |
PECO Energy Co [Member] | ||
Entity Registrant Name | PECO ENERGY CO | |
Entity Central Index Key | 78100 | |
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 | 9466 | |
Entity Filer Category | Non-accelerated Filer | |
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, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Operating revenues [Abstract] | ||||||
Revenues | $27,429 | [1] | $24,888 | [1] | $23,489 | [1] |
Operating revenues from affiliates | 23 | 70 | 48 | |||
Operating expenses | ||||||
Purchased power and fuel | 12,472 | 9,468 | 9,121 | |||
Purchased power and fuel from affiliates | 531 | 1,256 | 1,036 | |||
Operating and maintenance | 8,568 | 7,270 | 7,961 | |||
Depreciation and amortization | 2,314 | 2,153 | 1,881 | |||
Taxes other than income | 1,154 | 1,095 | 1,019 | |||
Total operating expenses | 25,039 | 21,242 | 21,018 | |||
Equity in (losses) earnings of unconsolidated affiliates | -20 | 10 | -91 | |||
Gain (loss) on sales of assets | 437 | 13 | -7 | |||
Gain on consolidation and acquisition of businesses | 289 | 0 | 0 | |||
Operating Income (Loss) | 3,096 | 3,669 | 2,373 | |||
Other income and (deductions) | ||||||
Interest expense, net | -1,024 | -1,315 | -891 | |||
Interest expense to affiliates, net | -41 | -41 | -37 | |||
Other, net | 455 | 460 | 353 | |||
Total other income and (deductions) | -610 | -896 | -575 | |||
Income before income taxes | 2,486 | 2,773 | 1,798 | |||
Income before income taxes | 2,486 | 2,773 | 1,798 | |||
Income taxes | 666 | 1,044 | 627 | |||
Net income | 1,820 | 1,729 | 1,171 | |||
Net income attributable to noncontrolling interest, preferred security dividends and preference stock dividends | -197 | -10 | -11 | |||
Net income attributable to common shareholders | 1,623 | 1,719 | 1,160 | |||
Pension and non-pension postretirement benefit plans: | ||||||
Prior service benefit reclassified to periodic benefit cost, net of tax | -30 | 0 | 1 | |||
Actuarial loss reclassified to periodic cost, net of tax | 147 | 208 | 168 | |||
Transition obligation reclassified to periodic cost, net of tax | 0 | 0 | 2 | |||
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax | -497 | 669 | -371 | |||
Unrealized gain (loss) on cash flow hedges, net of taxes | -148 | -248 | -120 | |||
Unrealized gain (loss) on marketable securities, net of taxes | 1 | 2 | 2 | |||
Unrealized gain (loss) on equity investments, net of taxes | 8 | 106 | 1 | |||
Unrealized gain (loss) on foreign currency translation, net of taxes | -9 | -10 | 0 | |||
Reversal of CENG equity method AOCI, net of taxes | -116 | 0 | 0 | |||
Other comprehensive income (loss) | -644 | 727 | [2] | -317 | ||
Comprehensive income | 1,176 | 2,456 | 854 | |||
Average shares of common stock outstanding: | ||||||
Basic | 860 | 856 | 816 | |||
Diluted | 864 | 860 | 819 | |||
Earnings per average common share: | ||||||
Basic (in usd per share) | $1.89 | $2.01 | $1.42 | |||
Diluted (in usd per share) | $1.88 | $2 | $1.42 | |||
Dividends per common share (in usd per share) | $1.24 | $1.46 | $2.10 | |||
Exelon Generation Co L L C [Member] | ||||||
Operating revenues [Abstract] | ||||||
Revenues | 17,393 | 15,630 | 14,437 | |||
Operating revenues | 16,614 | 14,207 | 12,735 | |||
Operating revenues from affiliates | 779 | 1,423 | 1,702 | |||
Operating expenses | ||||||
Purchased power and fuel | 9,368 | 6,927 | 6,017 | |||
Purchased power and fuel from affiliates | 557 | 1,270 | 1,044 | |||
Operating and maintenance | 4,943 | 3,960 | 4,398 | |||
Operating and maintenance from affiliates | 623 | 574 | 630 | |||
Depreciation and amortization | 967 | 856 | 768 | |||
Taxes other than income | 465 | 389 | 369 | |||
Total operating expenses | 16,923 | 13,976 | 13,226 | |||
Equity in (losses) earnings of unconsolidated affiliates | -20 | 10 | -91 | |||
Gain (loss) on sales of assets | 437 | 13 | -7 | |||
Gain on consolidation and acquisition of businesses | 289 | 0 | 0 | |||
Operating Income (Loss) | 1,176 | 1,677 | 1,113 | |||
Other income and (deductions) | ||||||
Interest expense, net | -303 | -298 | -226 | |||
Interest expense to affiliates, net | -53 | -59 | -75 | |||
Other, net | 406 | 355 | 246 | |||
Total other income and (deductions) | 50 | -2 | -55 | |||
Income before income taxes | 1,226 | 1,675 | 1,058 | |||
Income taxes | 207 | 615 | 500 | |||
Net income | 1,019 | 1,060 | 558 | |||
Net income (loss) attributable to noncontrolling interests | 184 | -10 | -4 | |||
Net income attributable to membership interest | 835 | 1,070 | 562 | |||
Pension and non-pension postretirement benefit plans: | ||||||
Unrealized gain (loss) on cash flow hedges, net of taxes | -132 | -398 | -403 | |||
Unrealized gain (loss) on marketable securities, net of taxes | -1 | 2 | 0 | |||
Unrealized gain (loss) on equity investments, net of taxes | 8 | 107 | 1 | |||
Unrealized gain (loss) on foreign currency translation, net of taxes | -9 | -10 | 0 | |||
Reversal of CENG equity method AOCI, net of taxes | -116 | 0 | 0 | |||
Other comprehensive income (loss) | -250 | -299 | [2] | -402 | ||
Comprehensive income | 769 | 761 | 156 | |||
Commonwealth Edison Co [Member] | ||||||
Operating revenues [Abstract] | ||||||
Revenues | 4,564 | 4,464 | 5,443 | |||
Operating revenues | 4,560 | 4,461 | 5,441 | |||
Operating revenues from affiliates | 4 | 3 | 2 | |||
Operating expenses | ||||||
Purchased power and fuel | 1,001 | 662 | 1,518 | |||
Purchased power from affiliate | 176 | 512 | 789 | |||
Operating and maintenance | 1,263 | 1,211 | 1,182 | |||
Operating and maintenance from affiliates | 166 | 157 | 163 | |||
Depreciation and amortization | 687 | 669 | 610 | |||
Taxes other than income | 293 | 299 | 295 | |||
Total operating expenses | 3,586 | 3,510 | 4,557 | |||
Equity in (losses) earnings of unconsolidated affiliates | 0 | 0 | ||||
Gain (loss) on sales of assets | 2 | 0 | 0 | |||
Operating Income (Loss) | 980 | 954 | 886 | |||
Other income and (deductions) | ||||||
Interest expense, net | -308 | -566 | -294 | |||
Interest expense to affiliates, net | -13 | -13 | -13 | |||
Other, net | 17 | 26 | 39 | |||
Total other income and (deductions) | -304 | -553 | -268 | |||
Income before income taxes | 676 | 401 | 618 | |||
Income taxes | 268 | 152 | 239 | |||
Net income | 408 | 249 | 379 | |||
Pension and non-pension postretirement benefit plans: | ||||||
Unrealized gain (loss) on marketable securities, net of taxes | 0 | 0 | 1 | |||
Other comprehensive income (loss) | 0 | 0 | 1 | |||
Comprehensive income | 408 | 249 | 380 | |||
PECO Energy Co [Member] | ||||||
Operating revenues [Abstract] | ||||||
Revenues | 3,094 | 3,100 | 3,186 | |||
Operating revenues | 3,092 | 3,099 | 3,183 | |||
Operating revenues from affiliates | 2 | 1 | 3 | |||
Operating expenses | ||||||
Purchased power and fuel | 1,067 | 908 | 842 | |||
Purchased power from affiliate | 194 | 392 | 533 | |||
Operating and maintenance | 767 | 647 | 698 | |||
Operating and maintenance from affiliates | 99 | 101 | 111 | |||
Depreciation and amortization | 236 | 228 | 217 | |||
Taxes other than income | 159 | 158 | 162 | |||
Total operating expenses | 2,522 | 2,434 | 2,563 | |||
Equity in (losses) earnings of unconsolidated affiliates | 0 | 0 | 0 | |||
Operating Income (Loss) | 572 | 666 | 623 | |||
Other income and (deductions) | ||||||
Interest expense, net | -101 | -103 | -111 | |||
Interest expense to affiliates, net | -12 | -12 | -12 | |||
Other, net | 7 | 6 | 8 | |||
Total other income and (deductions) | -106 | -109 | -115 | |||
Income before income taxes | 466 | 557 | 508 | |||
Income taxes | 114 | 162 | 127 | |||
Net income | 352 | 395 | 381 | |||
Preferred security dividends and redemption | 0 | -7 | -4 | |||
Net income attributable to common shareholders | 352 | 388 | 377 | |||
Pension and non-pension postretirement benefit plans: | ||||||
Unrealized gain (loss) on marketable securities, net of taxes | 0 | 0 | 1 | |||
Other comprehensive income (loss) | 0 | 0 | 1 | |||
Comprehensive income | 352 | 395 | 382 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Operating revenues [Abstract] | ||||||
Revenues | 3,165 | 3,065 | 2,735 | |||
Operating revenues | 3,140 | 3,052 | 2,725 | |||
Operating revenues from affiliates | 25 | 13 | 10 | |||
Operating expenses | ||||||
Purchased power and fuel | 1,035 | 969 | 973 | |||
Purchased power from affiliate | 382 | 452 | 396 | |||
Operating and maintenance | 614 | 551 | 622 | |||
Operating and maintenance from affiliates | 103 | 83 | 106 | |||
Depreciation and amortization | 371 | 348 | 298 | |||
Taxes other than income | 221 | 213 | 208 | |||
Total operating expenses | 2,726 | 2,616 | 2,603 | |||
Equity in (losses) earnings of unconsolidated affiliates | 0 | 0 | 0 | |||
Operating Income (Loss) | 439 | 449 | 132 | |||
Other income and (deductions) | ||||||
Interest expense, net | -90 | -106 | -128 | |||
Interest expense to affiliates, net | -16 | -16 | -16 | |||
Other, net | 18 | 17 | 23 | |||
Total other income and (deductions) | -88 | -105 | -121 | |||
Income before income taxes | 351 | 344 | 11 | |||
Income taxes | 140 | 134 | 7 | |||
Net income | 211 | 210 | 4 | |||
Preferred security dividends and redemption | -13 | -13 | -13 | |||
Net income attributable to common shareholders | 198 | 197 | -9 | |||
Pension and non-pension postretirement benefit plans: | ||||||
Comprehensive income | $211 | $210 | $4 | |||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||
[2] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Consolidated_Statements_of_Ope1
Consolidated Statements of Operations and Comprehensive Income (Parenthetical) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax | $1 | ||
Commonwealth Edison Co [Member] | |||
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax | 0 | 0 | 0 |
PECO Energy Co [Member] | |||
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax | $0 | $0 | $0 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (Unaudited) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities | |||
Net income | $1,820 | $1,729 | $1,171 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 3,868 | 3,779 | 4,079 |
Impairment of long-lived assets | 687 | 171 | 284 |
Gain on consolidation and acquisition of businesses | -296 | 0 | 0 |
(Gain) loss on sales of assets | -437 | -13 | 7 |
(Gain) loss on sales of assets | -437 | -13 | 7 |
Deferred income taxes and amortization of investment tax credits | 502 | 119 | 615 |
Net fair value changes related to derivatives | 716 | -445 | -604 |
Net realized and unrealized gains on nuclear decommissioning trust fund investments | -210 | -170 | -157 |
Other non-cash operating activities | 1,054 | 718 | 1,364 |
Changes in assets and liabilities: | |||
Accounts receivable | -318 | -97 | 243 |
Inventories | -380 | -100 | 26 |
Accounts payable, accrued expenses and other current liabilities | 209 | -90 | -632 |
Option premiums received (paid), net | 38 | -36 | -114 |
Counterparty collateral (posted) received, net | -1,478 | 215 | 135 |
Income taxes | -143 | 883 | 544 |
Pension and non-pension postretirement benefit contributions | -617 | -422 | -462 |
Other assets and liabilities | -558 | 102 | -368 |
Net cash flows provided by operating activities | 4,457 | 6,343 | 6,131 |
Cash flows from investing activities | |||
Capital expenditures | -6,077 | -5,395 | -5,789 |
Proceeds from termination of direct financing lease investment | 335 | 0 | 0 |
Proceeds from nuclear decommissioning trust fund sales | 7,396 | 4,217 | 7,265 |
Investment in nuclear decommissioning trust funds | -7,551 | -4,450 | -7,483 |
Acquisitions of businesses | -386 | 0 | -21 |
Proceeds from sales of long-lived assets | 1,719 | 32 | 371 |
Proceeds from sales of investments | 7 | 22 | 28 |
Cash and restricted cash acquired from consolidations and acquisitions | 140 | 0 | 964 |
Purchases of investments | -3 | -4 | -13 |
Change in restricted cash | -104 | -43 | -34 |
Distribution from CENG | 13 | 115 | 0 |
Other investing activities | -88 | 112 | 136 |
Net cash flows used in investing activities | -4,599 | -5,394 | -4,576 |
Cash flows from financing activities | |||
Payment of accounts receivable agreement | 0 | -210 | -15 |
Changes in short-term borrowings | 122 | 332 | -197 |
Issuance of long-term debt | 3,463 | 2,055 | 2,027 |
Retirement of long-term debt | -1,545 | -1,589 | -1,145 |
Redemption of preferred securities | 0 | -93 | 0 |
Distribution to noncontrolling interest of consolidated VIE | -421 | 0 | 0 |
Dividends paid on common stock | -1,065 | -1,249 | -1,716 |
Proceeds from employee stock plans | 35 | 47 | 72 |
Other financing activities | -178 | -119 | -111 |
Net cash flows provided by (used in) financing activities | 411 | -826 | -1,085 |
Increase in cash and cash equivalents | 269 | 123 | 470 |
Cash and cash equivalents at beginning of period | 1,609 | 1,486 | 1,016 |
Cash and cash equivalents at end of period | 1,878 | 1,609 | 1,486 |
Exelon Generation Co L L C [Member] | |||
Cash flows from operating activities | |||
Net income | 1,019 | 1,060 | 558 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 2,519 | 2,559 | 2,966 |
Impairment of long-lived assets | 663 | 157 | 284 |
Gain on consolidation and acquisition of businesses | -296 | 0 | 0 |
(Gain) loss on sales of assets | -437 | -13 | 7 |
Deferred income taxes and amortization of investment tax credits | -198 | 315 | 408 |
Net fair value changes related to derivatives | 635 | -448 | -611 |
Net realized and unrealized gains on nuclear decommissioning trust fund investments | -210 | -170 | -157 |
Other non-cash operating activities | 346 | 270 | 518 |
Changes in assets and liabilities: | |||
Accounts receivable | -215 | 109 | 248 |
Receivables from and payables to affiliates, net | 15 | 2 | 39 |
Inventories | -359 | -88 | 31 |
Accounts payable, accrued expenses and other current liabilities | 94 | -109 | -499 |
Option premiums received (paid), net | 38 | -36 | -114 |
Counterparty collateral (posted) received, net | -1,507 | 162 | 95 |
Income taxes | 265 | 402 | 114 |
Pension and non-pension postretirement benefit contributions | -297 | -149 | -178 |
Other assets and liabilities | -249 | -136 | -128 |
Net cash flows provided by operating activities | 1,826 | 3,887 | 3,581 |
Cash flows from investing activities | |||
Capital expenditures | -3,012 | -2,752 | -3,554 |
Proceeds from nuclear decommissioning trust fund sales | 7,396 | 4,217 | 7,265 |
Investment in nuclear decommissioning trust funds | -7,551 | -4,450 | -7,483 |
Acquisitions of businesses | -386 | 0 | -21 |
Proceeds from sales of long-lived assets | 1,719 | 32 | 371 |
Cash and restricted cash acquired from consolidations and acquisitions | 140 | 0 | 708 |
Change in restricted cash | -87 | -64 | 4 |
Distribution from CENG | 13 | 115 | 0 |
Other investing activities | -43 | 30 | 81 |
Changes in Exelon intercompany money pool | 44 | -44 | 0 |
Net cash flows used in investing activities | -1,767 | -2,916 | -2,629 |
Cash flows from financing activities | |||
Changes in short-term borrowings | 17 | 13 | -52 |
Issuance of long-term debt | 1,112 | 854 | 1,076 |
Retirement of long-term debt | -586 | -570 | -145 |
Distribution to noncontrolling interest of consolidated VIE | -421 | 0 | 0 |
Other financing activities | -67 | -82 | -78 |
Distribution to member | -645 | -625 | -1,626 |
Contribution from member | 53 | 26 | 48 |
Net cash flows provided by (used in) financing activities | -537 | -384 | -777 |
Increase in cash and cash equivalents | -478 | 587 | 175 |
Cash and cash equivalents at beginning of period | 1,258 | 671 | 496 |
Cash and cash equivalents at end of period | 780 | 1,258 | 671 |
Commonwealth Edison Co [Member] | |||
Cash flows from operating activities | |||
Net income | 408 | 249 | 379 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 687 | 669 | 610 |
(Gain) loss on sales of assets | -2 | 0 | 0 |
Deferred income taxes and amortization of investment tax credits | 433 | -57 | 270 |
Other non-cash operating activities | 255 | 28 | 252 |
Changes in assets and liabilities: | |||
Accounts receivable | -121 | -12 | 24 |
Receivables from and payables to affiliates, net | -11 | -12 | -18 |
Inventories | -16 | -18 | -11 |
Accounts payable, accrued expenses and other current liabilities | 53 | 74 | 59 |
Income taxes | -159 | 178 | 9 |
Pension and non-pension postretirement benefit contributions | -248 | -122 | -138 |
Other assets and liabilities | 45 | 241 | -102 |
Net cash flows provided by operating activities | 1,326 | 1,218 | 1,334 |
Cash flows from investing activities | |||
Capital expenditures | -1,689 | -1,433 | -1,246 |
Proceeds from sales of investments | 7 | 7 | 28 |
Purchases of investments | -3 | -4 | -13 |
Change in restricted cash | -2 | -2 | 0 |
Other investing activities | 32 | 45 | 19 |
Net cash flows used in investing activities | -1,655 | -1,387 | -1,212 |
Cash flows from financing activities | |||
Changes in short-term borrowings | 120 | 184 | 0 |
Issuance of long-term debt | 900 | 350 | 350 |
Retirement of long-term debt | -617 | -252 | -450 |
Dividends paid on common stock | -307 | -220 | -105 |
Other financing activities | -10 | -1 | -7 |
Contributions from parent | 273 | 0 | 0 |
Net cash flows provided by (used in) financing activities | 359 | 61 | -212 |
Increase in cash and cash equivalents | 30 | -108 | -90 |
Cash and cash equivalents at beginning of period | 36 | 144 | 234 |
Cash and cash equivalents at end of period | 66 | 36 | 144 |
PECO Energy Co [Member] | |||
Cash flows from operating activities | |||
Net income | 352 | 395 | 381 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 236 | 228 | 217 |
Deferred income taxes and amortization of investment tax credits | 88 | 20 | 37 |
Other non-cash operating activities | 92 | 108 | 125 |
Changes in assets and liabilities: | |||
Accounts receivable | -16 | -79 | -14 |
Receivables from and payables to affiliates, net | -6 | -18 | 13 |
Inventories | 2 | 2 | 21 |
Accounts payable, accrued expenses and other current liabilities | 54 | 41 | -47 |
Income taxes | -57 | 87 | 174 |
Pension and non-pension postretirement benefit contributions | -16 | -31 | -45 |
Other assets and liabilities | -17 | -6 | 16 |
Net cash flows provided by operating activities | 712 | 747 | 878 |
Cash flows from investing activities | |||
Capital expenditures | -661 | -537 | -422 |
Change in restricted cash | 0 | -2 | 2 |
Other investing activities | 12 | 8 | 10 |
Changes in Exelon intercompany money pool | 0 | 0 | 82 |
Net cash flows used in investing activities | -649 | -531 | -328 |
Cash flows from financing activities | |||
Changes in short-term borrowings | 0 | -210 | -15 |
Issuance of long-term debt | 300 | 550 | 350 |
Retirement of long-term debt | -250 | -300 | -375 |
Redemption of preferred securities | 0 | -93 | 0 |
Dividends paid on common stock | -320 | -332 | -343 |
Other financing activities | -4 | -2 | -4 |
Contributions from parent | 24 | 27 | 9 |
Dividends paid on preferred securities | 0 | -1 | -4 |
Net cash flows provided by (used in) financing activities | -250 | -361 | -382 |
Increase in cash and cash equivalents | -187 | -145 | 168 |
Cash and cash equivalents at beginning of period | 217 | 362 | 194 |
Cash and cash equivalents at end of period | 30 | 217 | 362 |
Baltimore Gas and Electric Company [Member] | |||
Cash flows from operating activities | |||
Net income | 211 | 210 | 4 |
Adjustments to reconcile net income to net cash flows provided by operating activities: | |||
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization | 371 | 348 | 298 |
Deferred income taxes and amortization of investment tax credits | 116 | 125 | 104 |
Other non-cash operating activities | 180 | 153 | 193 |
Changes in assets and liabilities: | |||
Accounts receivable | 46 | -127 | -45 |
Receivables from and payables to affiliates, net | -1 | -14 | 26 |
Inventories | -6 | 1 | 25 |
Accounts payable, accrued expenses and other current liabilities | -70 | -14 | -33 |
Counterparty collateral (posted) received, net | 27 | 0 | 0 |
Income taxes | 45 | -33 | 14 |
Pension and non-pension postretirement benefit contributions | -16 | -24 | -16 |
Other assets and liabilities | -163 | -64 | -85 |
Net cash flows provided by operating activities | 740 | 561 | 485 |
Cash flows from investing activities | |||
Capital expenditures | -620 | -587 | -582 |
Change in restricted cash | -22 | 2 | 0 |
Other investing activities | 20 | 14 | 9 |
Net cash flows used in investing activities | -622 | -571 | -573 |
Cash flows from financing activities | |||
Changes in short-term borrowings | -15 | 135 | 0 |
Issuance of long-term debt | 0 | 300 | 250 |
Retirement of long-term debt | -70 | -467 | -173 |
Other financing activities | 13 | -3 | -2 |
Contributions from parent | 0 | 0 | 66 |
Dividends paid on preferred securities | -13 | -13 | -13 |
Net cash flows provided by (used in) financing activities | -85 | -48 | 128 |
Increase in cash and cash equivalents | 33 | -58 | 40 |
Cash and cash equivalents at beginning of period | 31 | 89 | 49 |
Cash and cash equivalents at end of period | $64 | $31 | $89 |
Consolidated_Balance_Sheets_Un
Consolidated Balance Sheets (Unaudited) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Current assets | ||||
Cash and cash equivalents | $1,878 | $1,609 | ||
Cash and cash equivalents | 1,878 | 1,609 | ||
Restricted cash and cash equivalents | 271 | 167 | ||
Accounts receivable, net | ||||
Customer | 3,482 | 2,981 | ||
Other | 1,227 | 1,175 | ||
Mark-to-market derivative assets | 1,279 | 727 | ||
Unamortized energy contract assets | 254 | 374 | ||
Inventories, net | ||||
Fossil fuel | 579 | 276 | ||
Materials and supplies | 1,024 | 829 | ||
Deferred income taxes | 244 | 573 | ||
Regulatory assets | 847 | 760 | ||
Assets held for sale | 147 | 14 | ||
Other | 865 | 652 | ||
Total current assets | 12,097 | 10,137 | ||
Property, plant and equipment, net | 52,087 | 47,330 | ||
Deferred debits and other assets | ||||
Regulatory assets | 6,076 | 5,910 | ||
Nuclear decommissioning trust funds | 10,537 | 8,071 | ||
Investments | 544 | 1,187 | ||
Investment in CENG | 0 | 1,925 | ||
Goodwill | 2,672 | 2,625 | ||
Mark-to-market derivative assets | 773 | 607 | ||
Unamortized energy contract assets | 549 | 710 | ||
Pledged assets for Zion Station decommissioning | 319 | 458 | ||
Other | 1,160 | 964 | ||
Total deferred debits and other assets | 22,630 | 22,457 | ||
Total assets | 86,814 | [1] | 79,924 | [1] |
Current liabilities | ||||
Short-term borrowings | 460 | 341 | ||
Long-term debt due within one year | 1,802 | 1,509 | ||
Accounts payable | 3,048 | 2,484 | ||
Accrued expenses | 1,539 | 1,633 | ||
Payables to affiliates | 8 | 116 | ||
Mark-to-market derivative liabilities | 234 | 159 | ||
Unamortized energy contract liabilities | 238 | 261 | ||
Deferred income taxes | 0 | 40 | ||
Regulatory liabilities | 310 | 327 | ||
Other | 1,123 | 858 | ||
Total current liabilities | 8,762 | 7,728 | ||
Long-term debt | 19,362 | 17,623 | ||
Long-term debt to financing trusts | 648 | 648 | ||
Deferred credits and other liabilities | ||||
Deferred income taxes and unamortized investment tax credits | 13,019 | 12,905 | ||
Asset retirement obligations | 7,295 | 5,194 | ||
Pension obligations | 3,366 | 1,876 | ||
Non-pension postretirement benefit obligations | 1,742 | 2,190 | ||
Spent nuclear fuel obligation | 1,021 | 1,021 | ||
Regulatory liabilities | 4,550 | 4,388 | ||
Mark-to-market derivative liabilities | 403 | 300 | ||
Unamortized energy contract liabilities | 211 | 266 | ||
Payable for Zion Station decommissioning | 155 | 305 | ||
Other | 2,147 | 2,540 | ||
Total deferred credits and other liabilities | 33,909 | 30,985 | ||
Total liabilities | 62,681 | [1] | 56,984 | [1] |
Shareholders’ equity | ||||
Common stock | 16,709 | 16,741 | ||
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013) | -2,327 | -2,327 | ||
Retained earnings | 10,910 | 10,358 | ||
Accumulated other comprehensive loss, net | -2,684 | -2,040 | [2] | |
Total shareholders’ equity | 22,608 | 22,732 | ||
BGE preference stock not subject to mandatory redemption | 193 | 193 | ||
Noncontrolling interest | 1,332 | 15 | ||
Total equity | 24,133 | 22,940 | ||
Total liabilities and shareholders’ equity | 86,814 | 79,924 | ||
Member’s equity | ||||
Accumulated other comprehensive loss, net | -2,684 | -2,040 | [2] | |
Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member] | ||||
Deferred debits and other assets | ||||
Total assets | 8,160 | 1,755 | ||
Deferred credits and other liabilities | ||||
Total liabilities | 2,723 | 658 | ||
Exelon Generation Co L L C [Member] | ||||
Current assets | ||||
Cash and cash equivalents | 780 | 1,258 | ||
Cash and cash equivalents | 780 | 1,258 | ||
Restricted cash and cash equivalents | 158 | 71 | ||
Accounts receivable, net | ||||
Customer | 2,295 | 1,689 | ||
Other | 318 | 353 | ||
Mark-to-market derivative assets | 1,276 | 727 | ||
Receivables from affiliates | 113 | 108 | ||
Unamortized energy contract assets | 254 | 374 | ||
Inventories, net | ||||
Fossil fuel | 465 | 164 | ||
Materials and supplies | 847 | 671 | ||
Deferred income taxes | 327 | 475 | ||
Receivable from Exelon intercompany money pool | 0 | 44 | ||
Regulatory assets | 147 | 14 | ||
Other | 658 | 491 | ||
Total current assets | 7,638 | 6,439 | ||
Property, plant and equipment, net | 22,945 | 20,111 | ||
Deferred debits and other assets | ||||
Nuclear decommissioning trust funds | 10,537 | 8,071 | ||
Investments | 104 | 400 | ||
Investment in CENG | 0 | 1,925 | ||
Goodwill | 47 | 0 | ||
Mark-to-market derivative assets | 771 | 600 | ||
Prepaid pension asset | 1,704 | 1,873 | ||
Unamortized energy contract assets | 549 | 710 | ||
Deferred income taxes | 3 | |||
Pledged assets for Zion Station decommissioning | 319 | 458 | ||
Other | 731 | 645 | ||
Total deferred debits and other assets | 14,765 | 14,682 | ||
Total assets | 45,348 | [3] | 41,232 | [3] |
Current liabilities | ||||
Short-term borrowings | 36 | 22 | ||
Long-term debt due within one year | 58 | 561 | ||
Long-term debt to affiliates due within one year | 556 | 0 | ||
Accounts payable | 1,759 | 1,322 | ||
Accrued expenses | 886 | 976 | ||
Payables to affiliates | 107 | 181 | ||
Mark-to-market derivative liabilities | 214 | 142 | ||
Unamortized energy contract liabilities | 238 | 249 | ||
Deferred income taxes | 0 | 25 | ||
Other | 605 | 389 | ||
Total current liabilities | 4,459 | 3,867 | ||
Long-term debt | 6,709 | 5,645 | ||
Long-term debt to financing trusts | 943 | 1,523 | ||
Deferred credits and other liabilities | ||||
Deferred income taxes and unamortized investment tax credits | 6,034 | 6,295 | ||
Asset retirement obligations | 7,146 | 5,047 | ||
Non-pension postretirement benefit obligations | 915 | 850 | ||
Spent nuclear fuel obligation | 1,021 | 1,021 | ||
Payables to affiliates | 2,880 | 2,740 | ||
Mark-to-market derivative liabilities | 105 | 120 | ||
Unamortized energy contract liabilities | 211 | 266 | ||
Payable for Zion Station decommissioning | 155 | 305 | ||
Other | 719 | 811 | ||
Total deferred credits and other liabilities | 19,186 | 17,455 | ||
Total liabilities | 31,297 | [3] | 28,490 | [3] |
Shareholders’ equity | ||||
Accumulated other comprehensive loss, net | -36 | 214 | [2] | |
Noncontrolling interest | 1,333 | 17 | ||
Member’s equity | ||||
Membership interest | 8,951 | 8,898 | ||
Undistributed earnings | 3,803 | 3,613 | ||
Accumulated other comprehensive loss, net | -36 | 214 | [2] | |
Total member’s equity | 12,718 | 12,725 | ||
Total equity | 14,051 | 12,742 | ||
Total liabilities and equity | 45,348 | 41,232 | ||
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member] | ||||
Deferred debits and other assets | ||||
Total assets | 8,119 | 1,695 | ||
Deferred credits and other liabilities | ||||
Total liabilities | 2,507 | 362 | ||
Commonwealth Edison Co [Member] | ||||
Current assets | ||||
Cash and cash equivalents | 66 | 36 | ||
Restricted cash and cash equivalents | 4 | 2 | ||
Accounts receivable, net | ||||
Customer | 477 | 451 | ||
Other | 648 | 581 | ||
Receivables from affiliates | 14 | 3 | ||
Inventories, net | ||||
Inventories, net | 125 | 109 | ||
Regulatory assets | 349 | 329 | ||
Other | 40 | 29 | ||
Total current assets | 1,723 | 1,540 | ||
Property, plant and equipment, net | 15,793 | 14,666 | ||
Deferred debits and other assets | ||||
Regulatory assets | 852 | 933 | ||
Investments | 6 | 11 | ||
Goodwill | 2,625 | 2,625 | ||
Receivable from affiliates | 2,571 | 2,469 | ||
Prepaid pension asset | 1,551 | 1,583 | ||
Other | 271 | 291 | ||
Total deferred debits and other assets | 7,876 | 7,912 | ||
Total assets | 25,392 | 24,118 | ||
Current liabilities | ||||
Short-term borrowings | 304 | 184 | ||
Long-term debt due within one year | 260 | 617 | ||
Accounts payable | 598 | 449 | ||
Accrued expenses | 331 | 307 | ||
Payables to affiliates | 84 | 83 | ||
Mark-to-market derivative liabilities | 20 | 17 | ||
Deferred income taxes | 63 | 16 | ||
Customer deposits | 128 | 133 | ||
Regulatory liabilities | 125 | 170 | ||
Other | 73 | 72 | ||
Total current liabilities | 1,986 | 2,048 | ||
Long-term debt | 5,698 | 5,058 | ||
Long-term debt to financing trusts | 206 | 206 | ||
Deferred credits and other liabilities | ||||
Deferred income taxes and unamortized investment tax credits | 4,498 | 4,116 | ||
Asset retirement obligations | 103 | 99 | ||
Non-pension postretirement benefit obligations | 263 | 381 | ||
Regulatory liabilities | 3,655 | 3,512 | ||
Mark-to-market derivative liabilities | 187 | 176 | ||
Other | 889 | 994 | ||
Total deferred credits and other liabilities | 9,595 | 9,278 | ||
Total liabilities | 17,485 | 16,590 | ||
Shareholders’ equity | ||||
Common stock | 1,588 | 1,588 | ||
Other paid-in capital | 5,468 | 5,190 | ||
Retained earnings | 851 | 750 | ||
Total shareholders’ equity | 7,907 | 7,528 | ||
Total liabilities and shareholders’ equity | 25,392 | 24,118 | ||
PECO Energy Co [Member] | ||||
Current assets | ||||
Cash and cash equivalents | 30 | 217 | ||
Restricted cash and cash equivalents | 2 | 2 | ||
Accounts receivable, net | ||||
Customer | 320 | 360 | ||
Other | 141 | 104 | ||
Receivables from affiliates | 3 | 3 | ||
Inventories, net | ||||
Fossil fuel | 57 | 60 | ||
Materials and supplies | 22 | 21 | ||
Deferred income taxes | 69 | 83 | ||
Prepaid utility taxes | 10 | 3 | ||
Regulatory assets | 29 | 17 | ||
Other | 31 | 36 | ||
Total current assets | 714 | 906 | ||
Property, plant and equipment, net | 6,801 | 6,384 | ||
Deferred debits and other assets | ||||
Regulatory assets | 1,529 | 1,448 | ||
Investments | 31 | 31 | ||
Receivable from affiliates | 490 | 447 | ||
Prepaid pension asset | 344 | 363 | ||
Other | 34 | 38 | ||
Total deferred debits and other assets | 2,428 | 2,327 | ||
Total assets | 9,943 | 9,617 | ||
Current liabilities | ||||
Long-term debt due within one year | 0 | 250 | ||
Accounts payable | 337 | 285 | ||
Accrued expenses | 91 | 106 | ||
Payables to affiliates | 52 | 58 | ||
Customer deposits | 52 | 49 | ||
Regulatory liabilities | 90 | 106 | ||
Other | 31 | 37 | ||
Total current liabilities | 653 | 891 | ||
Long-term debt | 2,246 | 1,947 | ||
Long-term debt to financing trusts | 184 | [4] | 184 | [4] |
Deferred credits and other liabilities | ||||
Deferred income taxes and unamortized investment tax credits | 2,671 | 2,487 | ||
Asset retirement obligations | 29 | 29 | ||
Non-pension postretirement benefit obligations | 287 | 286 | ||
Regulatory liabilities | 657 | 629 | ||
Mark-to-market derivative liabilities | 14 | |||
Other | 95 | 99 | ||
Total deferred credits and other liabilities | 3,739 | 3,530 | ||
Total liabilities | 6,822 | 6,552 | ||
Shareholders’ equity | ||||
Common stock | 2,439 | 2,415 | ||
Retained earnings | 681 | 649 | ||
Accumulated other comprehensive loss, net | 1 | 1 | [2] | |
Total shareholders’ equity | 3,121 | 3,065 | ||
Total liabilities and shareholders’ equity | 9,943 | 9,617 | ||
Member’s equity | ||||
Accumulated other comprehensive loss, net | 1 | 1 | [2] | |
Baltimore Gas and Electric Company [Member] | ||||
Current assets | ||||
Cash and cash equivalents | 64 | 31 | ||
Restricted cash and cash equivalents | 50 | 28 | ||
Accounts receivable, net | ||||
Customer | 390 | 480 | ||
Other | 82 | 114 | ||
Income taxes receivable | 0 | 30 | ||
Inventories, net | ||||
Fossil fuel | 57 | 53 | ||
Materials and supplies | 30 | 28 | ||
Deferred income taxes | 6 | 2 | ||
Prepaid utility taxes | 59 | 57 | ||
Regulatory assets | 214 | 181 | ||
Other | 5 | 7 | ||
Total current assets | 957 | 1,011 | ||
Property, plant and equipment, net | 6,204 | 5,864 | ||
Deferred debits and other assets | ||||
Regulatory assets | 510 | 524 | ||
Investments | 12 | 13 | ||
Prepaid pension asset | 370 | 423 | ||
Other | 25 | 26 | ||
Total deferred debits and other assets | 917 | 986 | ||
Total assets | 8,078 | [5] | 7,861 | [5] |
Current liabilities | ||||
Short-term borrowings | 120 | 135 | ||
Long-term debt to affiliates due within one year | 75 | 70 | ||
Accounts payable | 215 | 270 | ||
Accrued expenses | 131 | 111 | ||
Payables to affiliates | 66 | 55 | ||
Deferred income taxes | 52 | 27 | ||
Customer deposits | 92 | 76 | ||
Regulatory liabilities | 44 | 48 | ||
Other | 51 | 35 | ||
Total current liabilities | 846 | 827 | ||
Long-term debt | 1,867 | 1,941 | ||
Long-term debt to financing trusts | 258 | 258 | ||
Deferred credits and other liabilities | ||||
Deferred income taxes and unamortized investment tax credits | 1,865 | 1,773 | ||
Asset retirement obligations | 17 | 19 | ||
Non-pension postretirement benefit obligations | 212 | 217 | ||
Regulatory liabilities | 200 | 204 | ||
Other | 60 | 67 | ||
Total deferred credits and other liabilities | 2,354 | 2,280 | ||
Total liabilities | 5,325 | [5] | 5,306 | [5] |
Shareholders’ equity | ||||
Common stock | 1,360 | 1,360 | ||
Retained earnings | 1,203 | 1,005 | ||
Total shareholders’ equity | 2,563 | 2,365 | ||
BGE preference stock not subject to mandatory redemption | 190 | 190 | ||
Total equity | 2,753 | 2,555 | ||
Total liabilities and shareholders’ equity | 8,078 | 7,861 | ||
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member] | ||||
Deferred debits and other assets | ||||
Total assets | 24 | 31 | ||
Deferred credits and other liabilities | ||||
Total liabilities | 197 | 269 | ||
Constellation Energy Group LLC [Member] | ||||
Deferred debits and other assets | ||||
Total assets | $189 | |||
[1] | Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. | |||
[2] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||
[3] | Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities. | |||
[4] | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. | |||
[5] | BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities. |
Consolidated_Balance_Sheets_Un1
Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 859,833,343 | 857,290,484 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
Commonwealth Edison Co [Member] | ||
Common stock, shares authorized | 250,000,000 | |
Common stock, shares outstanding | 127,016,947 | 127,016,896 |
PECO Energy Co [Member] | ||
Common stock, shares authorized | 500,000,000 | |
Common stock, shares outstanding | 170,478,507 | 170,478,507 |
Baltimore Gas and Electric Company [Member] | ||
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 [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Noncontrolling Interest [Member] | 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] | 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] | 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, unless otherwise specified | Accumulated Other Comprehensive Income (Loss) [Member] | Noncontrolling Interest [Member] | Membership Interest [Member] | Undistributed Earnings [Member] | Common Stock [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Other Paid-In Capital [Member] | Retained Deficit Unappropriated [Member] | Retained Earnings Appropriated [Member] | Common Stock [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock [Member] | Retained Earnings [Member] | Membership Interest [Member] | Preference Stock Not Subject To Mandatory Redemption [Member] | |||||||||||||
Beginning Balance at Dec. 31, 2011 | $14,388 | $9,107 | ($2,327) | $10,055 | ($2,450) | $3 | $2,301 | $1,294 | $817 | $2,111 | $190 | ||||||||||||||||||
Beginning Balance (in shares) at Dec. 31, 2011 | 698,112 | ||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2011 | 8,708 | 915 | 5 | 3,556 | 4,232 | ||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 1,171 | 1,160 | -3 | 14 | 558 | -4 | 562 | 379 | 379 | 381 | 381 | 4 | 4 | 4 | |||||||||||||||
Long-term incentive plan activity, shares | 2,432 | ||||||||||||||||||||||||||||
Long-term incentive plan activity | 126 | 126 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances | 26 | 26 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances, shares | 857 | ||||||||||||||||||||||||||||
Common stock dividends | -1,322 | -1,322 | -105 | -105 | -343 | -343 | |||||||||||||||||||||||
Common stock issuance Constellation merger, shares | 188,124 | ||||||||||||||||||||||||||||
Common stock issuance Constellation merger | 7,365 | 7,365 | 5,264 | 5,264 | |||||||||||||||||||||||||
Noncontrolling interest acquired | 114 | 8 | 106 | ||||||||||||||||||||||||||
BGE preference stock acquired | 193 | 193 | |||||||||||||||||||||||||||
Preferred and preference stock dividends | -14 | -14 | -4 | -4 | -13 | -13 | -13 | ||||||||||||||||||||||
Other comprehensive loss, net of income taxes | -317 | -402 | -402 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||
Allocation of tax benefit from parent | 48 | 9 | |||||||||||||||||||||||||||
Other comprehensive loss, net of income taxes | -317 | -317 | |||||||||||||||||||||||||||
Distribution to member | -1,626 | -1,626 | |||||||||||||||||||||||||||
Allocation of tax benefit from member | 48 | 48 | |||||||||||||||||||||||||||
Noncontrolling interest acquired | 115 | 107 | 8 | ||||||||||||||||||||||||||
Allocation of tax benefit from parent | 11 | 11 | 9 | 9 | |||||||||||||||||||||||||
Appropriation of retained earnings for future dividends | -379 | 379 | |||||||||||||||||||||||||||
Contribution from parent | 66 | 66 | 66 | ||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2012 | 7,323 | 1,588 | 5,014 | -1,639 | 2,360 | 2,982 | 2,388 | 593 | 1 | ||||||||||||||||||||
Ending Balance at Dec. 31, 2012 | 21,730 | 16,632 | -2,327 | 9,893 | -2,767 | 106 | 193 | 2,358 | 1,360 | 808 | 2,168 | 190 | |||||||||||||||||
Ending Balance (in shares) at Dec. 31, 2012 | 889,525 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2012 | 12,665 | 513 | 108 | 8,876 | 3,168 | ||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | -4 | [1] | -18 | -81 | 121 | 77 | |||||||||||||||||||||||
Ending Balance at Mar. 31, 2013 | |||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2012 | 21,730 | 16,632 | -2,327 | 9,893 | -2,767 | 106 | 193 | 2,358 | 808 | 2,168 | 190 | ||||||||||||||||||
Beginning Balance (in shares) at Dec. 31, 2012 | 889,525 | ||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2012 | 12,665 | 513 | 108 | 8,876 | 3,168 | ||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 1,729 | 1,719 | -10 | 20 | 1,060 | -10 | 1,070 | 249 | 249 | 395 | 395 | 210 | 210 | 210 | |||||||||||||||
Long-term incentive plan activity, shares | 1,445 | ||||||||||||||||||||||||||||
Long-term incentive plan activity | 81 | 81 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances | 28 | 28 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances, shares | 1,064 | ||||||||||||||||||||||||||||
Common stock dividends | -1,254 | -1,254 | -220 | -220 | -332 | -332 | |||||||||||||||||||||||
Common stock issuance Constellation merger | -19 | -18 | -1 | ||||||||||||||||||||||||||
Preferred and preference stock dividends | -14 | -14 | -1 | -1 | -13 | -13 | -13 | ||||||||||||||||||||||
Other comprehensive loss, net of income taxes | 727 | [2] | -299 | [2] | -299 | 0 | 0 | ||||||||||||||||||||||
Consolidated VIE dividend to noncontrolling interest | -63 | -63 | -63 | -63 | |||||||||||||||||||||||||
Deconsolidation of VIE | -18 | -18 | |||||||||||||||||||||||||||
Redemption of preferred securities | -6 | -6 | |||||||||||||||||||||||||||
Acquisition of noncontrolling interest | -3 | -3 | |||||||||||||||||||||||||||
Allocation of tax benefit from parent | 27 | 27 | |||||||||||||||||||||||||||
Other comprehensive loss, net of income taxes | 727 | 727 | |||||||||||||||||||||||||||
Distribution to member | -625 | -625 | |||||||||||||||||||||||||||
Allocation of tax benefit from member | 26 | 26 | |||||||||||||||||||||||||||
Allocation of tax benefit from parent | 176 | 176 | -6 | -6 | |||||||||||||||||||||||||
Appropriation of retained earnings for future dividends | -249 | 249 | |||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 22,732 | 7,528 | 1,588 | 0 | 5,190 | -1,639 | 2,389 | 3,065 | 2,415 | 649 | 1 | 2,365 | |||||||||||||||||
Ending Balance at Dec. 31, 2013 | 22,940 | 16,741 | -2,327 | 10,358 | -2,040 | 15 | 193 | 2,555 | 1,360 | 1,005 | 2,365 | 190 | |||||||||||||||||
Ending Balance (in shares) at Dec. 31, 2013 | 892,034 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 12,742 | 214 | 17 | 8,898 | 3,613 | ||||||||||||||||||||||||
Beginning Balance at Sep. 30, 2013 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 495 | 269 | 109 | 102 | 47 | ||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 22,732 | 7,528 | 1,588 | 0 | 3,065 | 1 | 2,365 | ||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 22,940 | -2,327 | 2,555 | 1,360 | 190 | ||||||||||||||||||||||||
Ending Balance (in shares) at Dec. 31, 2013 | 892,034 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2013 | 12,742 | ||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 90 | -185 | 98 | 89 | 85 | ||||||||||||||||||||||||
Ending Balance at Mar. 31, 2014 | |||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2013 | 16,741 | -2,327 | 1,360 | 190 | |||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Tax benefit on stock compensation | -8 | ||||||||||||||||||||||||||||
Ending Balance at Sep. 30, 2014 | |||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2013 | 22,940 | 16,741 | -2,327 | 10,358 | -2,040 | 15 | 193 | 2,555 | 1,360 | 1,005 | 2,365 | 190 | |||||||||||||||||
Beginning Balance (in shares) at Dec. 31, 2013 | 892,034 | ||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2013 | 12,742 | 214 | 17 | 8,898 | 3,613 | ||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 1,820 | 1,623 | 184 | 13 | 1,019 | 184 | 835 | 408 | 408 | 352 | 352 | 211 | 211 | 211 | |||||||||||||||
Long-term incentive plan activity, shares | 1,574 | ||||||||||||||||||||||||||||
Long-term incentive plan activity | 72 | 72 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances | 35 | 35 | |||||||||||||||||||||||||||
Employee stock purchase plan issuances, shares | 960 | ||||||||||||||||||||||||||||
Common stock dividends | -1,071 | -1,071 | -307 | -307 | -320 | -320 | |||||||||||||||||||||||
Noncontrolling interest acquired | 1,548 | 1,548 | |||||||||||||||||||||||||||
Preferred and preference stock dividends | -13 | -13 | -13 | -13 | -13 | ||||||||||||||||||||||||
Other comprehensive loss, net of income taxes | -644 | -250 | 0 | 0 | |||||||||||||||||||||||||
Consolidated VIE dividend to noncontrolling interest | -421 | -421 | 1,548 | 1,548 | |||||||||||||||||||||||||
Deconsolidation of VIE | -421 | -421 | |||||||||||||||||||||||||||
Tax benefit on stock compensation | -8 | ||||||||||||||||||||||||||||
Acquisition of noncontrolling interest | 4 | -2 | 6 | 5 | 5 | ||||||||||||||||||||||||
Fair value of financing contract payments | -131 | -131 | |||||||||||||||||||||||||||
Transfer of CENG pension and non-pension postretirement benefit obligations | 2 | 2 | |||||||||||||||||||||||||||
Reversal of CENG equity method AOCI, net of income taxes | -116 | -116 | |||||||||||||||||||||||||||
Other comprehensive loss, net of income taxes | -528 | -528 | -134 | -134 | |||||||||||||||||||||||||
Distribution to member | 53 | 53 | |||||||||||||||||||||||||||
Allocation of tax benefit from member | -645 | -645 | |||||||||||||||||||||||||||
Noncontrolling interest acquired | -116 | -116 | |||||||||||||||||||||||||||
Allocation of tax benefit from parent | 5 | 5 | 24 | 24 | |||||||||||||||||||||||||
Appropriation of retained earnings for future dividends | -408 | 408 | |||||||||||||||||||||||||||
Contribution from parent | 273 | 273 | |||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | 22,608 | 7,907 | 1,588 | 0 | 5,468 | -1,639 | 2,490 | 3,121 | 2,439 | 681 | 1 | 2,563 | |||||||||||||||||
Ending Balance at Dec. 31, 2014 | 24,133 | 16,709 | -2,327 | 10,910 | -2,684 | 1,332 | 193 | 2,753 | 1,360 | 1,203 | 2,563 | 190 | |||||||||||||||||
Ending Balance (in shares) at Dec. 31, 2014 | 894,568 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | 14,051 | -36 | 1,333 | 8,951 | 3,803 | ||||||||||||||||||||||||
Beginning Balance at Sep. 30, 2014 | |||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||
Net income | 18 | [3] | -91 | 73 | 98 | 52 | |||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | 22,608 | 7,907 | 1,588 | 0 | 3,121 | 1 | 2,563 | ||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | 24,133 | -2,327 | 2,753 | 1,360 | 190 | ||||||||||||||||||||||||
Ending Balance (in shares) at Dec. 31, 2014 | 894,568 | ||||||||||||||||||||||||||||
Ending Balance at Dec. 31, 2014 | $14,051 | ||||||||||||||||||||||||||||
[1] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||||||||||||
[2] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | ||||||||||||||||||||||||||||
[3] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. |
Consolidated_Statement_of_Chan1
Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2012 |
Other comprehensive income, income taxes | $192 |
Exelon Generation Co L L C [Member] | |
Other comprehensive income, income taxes | 263 |
PECO Energy Co [Member] | |
Other comprehensive income, income taxes | 0 |
Commonwealth Edison Co [Member] | |
Other comprehensive income, income taxes | $0 |
Significant_Accounting_Policie
Significant Accounting Policies | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||
Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE) | 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 — Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction. | |||||||||||||||||||||
On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further information regarding the integration 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, 2014, 2013 and 2012 and the financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2014. | |||||||||||||||||||||
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, 2014 and December 31, 2013, 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 of 99% for certain periods of time, and CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for these certain subsidiaries. | |||||||||||||||||||||
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 additional12.5% 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, 2014 and December 31, 2013, 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 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. | |||||||||||||||||||||
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, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||
Certain prior year amounts in the registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, financial positions, or cash flows from operating activities. | |||||||||||||||||||||
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 or revenue 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 Constellation 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 Other income and deductions (interest income) on their Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||
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 Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2014 and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers. | |||||||||||||||||||||
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2014 and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2014, 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 customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change in estimate, refer to Note 6 — Accounts Receivable. | |||||||||||||||||||||
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. 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 disclose (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 disclosed, 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, coal 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 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 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 construction-related direct labor and material costs. ComEd, PECO and BGE also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. 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. | |||||||||||||||||||||
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 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. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. 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, 2014 and 2013, there were not 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 $13 million, $10 million and $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, 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 (a) | Generation (a) | ComEd | PECO | BGE | ||||||||||||||||
December 31, 2014 | $ | 596 | $ | 193 | $ | 133 | $ | 84 | $ | 163 | |||||||||||
December 31, 2013 | 479 | 129 | 101 | 71 | 155 | ||||||||||||||||
Amortization of capitalized software costs | Exelon (a) (b) | Generation (a) (b) | ComEd | PECO | BGE (b) | ||||||||||||||||
2014 | $ | 186 | $ | 59 | $ | 45 | $ | 28 | $ | 43 | |||||||||||
2013 | 198 | 67 | 52 | 33 | 36 | ||||||||||||||||
2012 | 208 | 81 | 56 | 30 | 32 | ||||||||||||||||
_______________________ | |||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | ||||||||||||||||||||
(b) | 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 year ended December 31, 2012. | ||||||||||||||||||||
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 oil and gas reserves are based on internal calculations. | |||||||||||||||||||||
Amortization of regulatory assets and liabilities are recorded over the recovery or refund 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 or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, generally, 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. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, 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. | |||||||||||||||||||||
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 throughout 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 and Comprehensive Income 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)(b) | Generation(a)(b) | ComEd | PECO | BGE (b) | |||||||||||||||||
2014 | Total incurred interest (c) | $ | 1,144 | $ | 419 | $ | 323 | $ | 115 | $ | 118 | ||||||||||
Capitalized interest | 63 | 63 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 37 | — | 5 | 8 | 24 | ||||||||||||||||
2013 | Total incurred interest (c) | $ | 1,423 | $ | 411 | $ | 584 | $ | 117 | $ | 129 | ||||||||||
Capitalized interest | 54 | 54 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 35 | — | 16 | 6 | 13 | ||||||||||||||||
2012 | Total incurred interest (c) | $ | 1,003 | $ | 368 | $ | 310 | $ | 125 | $ | 149 | ||||||||||
Capitalized interest | 67 | 67 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 25 | — | 9 | 6 | 15 | ||||||||||||||||
_______________________ | |||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | ||||||||||||||||||||
(b) | 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 year ended December 31, 2012. | ||||||||||||||||||||
(c) | 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. Indicators of impairment may include a deteriorating business climate, including, but not limited to, current energy prices and market conditions, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. 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 less costs to sell. | |||||||||||||||||||||
Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows from contracts that are accounted for as intangible contract assets and liabilities recorded 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). 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, Generation'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 other than 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. 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 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 Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivatives executed to hedge economic risk related to 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 July 14, 2014, Exelon became the sponsor of all of CENG's pension and other postretirement benefit 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, 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. | |||||||||||||||||||||
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 management believes may significantly affect 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. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows. | |||||||||||||||||||||
Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force) | |||||||||||||||||||||
In November 2014, the FASB issued authoritative guidance that allows acquired entities to apply pushdown accounting (i.e., reflecting the acquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SEC rescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made it optional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the most recent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financial statements of the Registrants; however, the Registrants will assess the potential impact of the guidance on future acquisitions. | |||||||||||||||||||||
The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants. | |||||||||||||||||||||
Revenue from Contracts with Customers | |||||||||||||||||||||
In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new guidance replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying | |||||||||||||||||||||
principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016. Early adoption is not permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. |
Variable_Interest_Entities_Exe
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||
Variable Interest Entity [Abstract] | ||||||||||||||||||||||||||
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE) | 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 affect the entity’s economic performance. | ||||||||||||||||||||||||||
At December 31, 2014 and 2013, Exelon, Generation, and BGE collectively consolidated six and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of December 31, 2014 and 2013, the Registrants had significant interests in six and eight other VIEs, respectively, for which the Registrants do not have the power to direct the entities’ activities 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, 2014 and 2013 are as follows: | ||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||
Exelon (a) (b) | Generation (b) | BGE | Exelon (a) | Generation | BGE | |||||||||||||||||||||
Current assets | $ | 1,271 | $ | 1,242 | $ | 21 | $ | 484 | $ | 446 | $ | 28 | ||||||||||||||
Noncurrent assets | 7,580 | 7,566 | 3 | 1,905 | 1,884 | 3 | ||||||||||||||||||||
Total assets | $ | 8,851 | $ | 8,808 | $ | 24 | $ | 2,389 | $ | 2,330 | $ | 31 | ||||||||||||||
Current liabilities | $ | 611 | $ | 526 | $ | 77 | $ | 566 | $ | 481 | $ | 74 | ||||||||||||||
Noncurrent liabilities | 2,730 | 2,600 | 120 | 774 | 562 | 195 | ||||||||||||||||||||
Total liabilities | $ | 3,341 | $ | 3,126 | $ | 197 | $ | 1,340 | $ | 1,043 | $ | 269 | ||||||||||||||
_______________________ | ||||||||||||||||||||||||||
(a) | Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||||||||||||||||||||||||
(b) | Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||||||||||||||||||||||
Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be settled using VIE resources. | ||||||||||||||||||||||||||
Exelon, Generation and BGE's consolidated VIEs consist of: | ||||||||||||||||||||||||||
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 2014, 2013, and 2012, BGE remitted $85 million, $83 million, and $85 million, respectively, to BondCo. | ||||||||||||||||||||||||||
BGE did not provide any additional financial support to BondCo during 2014. 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 | |||||||||||||||||||||||||
• | Generation provides 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 242-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 operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $642 million, as of December 31, 2014, 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 Companies. In March 2014, Generation began consolidating retail power VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $5 million in credit support for the retail power companies. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs does not have a material impact on Generation’s financial results or financial condition. | ||||||||||||||||||||||||||
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 with 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 the risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have noncontrolling equity 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 generation facilities. While Generation owns 100% of the majority of the wind project entities, nine of the projects have noncontrolling equity interests of 1% held by third parties. Generation’s current economic interests in eight of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current 99% economic interests in the projects. However, no additional support to these projects beyond what was contractually required has been provided during 2014. As of December 31, 2014, 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 relates to the wind generating assets, PPA intangible assets and working capital amounts. | ||||||||||||||||||||||||||
CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF Inc. (EDFI) (a subsidiary of EDF) and was governed by a board of ten directors, five of which were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDFI through the Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; therefore, CENG was not subject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equity method investment. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, CENG now qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the financial position and results of operations of CENG. On April 1, 2014, Exelon and Generation derecognized Generation’s equity method investment in CENG and reflected all assets, liabilities, and the EDFI noncontrolling interest in CENG at fair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. For additional information on this transaction refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC. | ||||||||||||||||||||||||||
Generation and Exelon, where indicated, provide the following support to CENG (See Note 25 — Related Party Transactions and Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information regarding Generation and Exelon’s transactions with CENG): | ||||||||||||||||||||||||||
• | under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI, | |||||||||||||||||||||||||
• | under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants, | |||||||||||||||||||||||||
• | under power purchase agreements with CENG, Generation purchased 85% of the available output generated by the CENG nuclear plants through the end of 2014 and will purchase 50.01% from 2015 through the end of the operating life of each respective plant, | |||||||||||||||||||||||||
• | Generation provided a $400 million loan to CENG (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC for more details), | |||||||||||||||||||||||||
• | Generation executed an Indemnity Agreement pursuant to which Generation agreed to 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 guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22 — Commitments and Contingencies for more details), | |||||||||||||||||||||||||
• | in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid from 2013 through 2016. As of December 31, 2014, the remaining obligation is approximately $3 million, | |||||||||||||||||||||||||
• | Generation and EDFI share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance (See Note 22 — Commitments and Contingencies for more details), | |||||||||||||||||||||||||
• | Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDFI executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee, | |||||||||||||||||||||||||
• | Generation and EDFI are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 22 — Commitments and Contingencies for more details), and | |||||||||||||||||||||||||
• | Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries. | |||||||||||||||||||||||||
For each of the consolidated VIEs, except as otherwise noted: | ||||||||||||||||||||||||||
• | The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE; | |||||||||||||||||||||||||
• | Exelon, Generation and BGE did not provide any additional material financial support to the VIEs; | |||||||||||||||||||||||||
• | Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and | |||||||||||||||||||||||||
• | the creditors of the VIEs did not have recourse to Exelon’s, Generation’s or BGE’s general credit. | |||||||||||||||||||||||||
As of December 31, 2014 and 2013, ComEd and PECO did not have any material consolidated VIEs. | ||||||||||||||||||||||||||
Assets and Liabilities of Consolidated VIEs | ||||||||||||||||||||||||||
Included within the consolidated VIE table above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2014 and 2013, these assets and liabilities primarily consisted of the following: | ||||||||||||||||||||||||||
December 31, 2014 | December 31, 2013 | |||||||||||||||||||||||||
Exelon | Generation | BGE | Exelon | Generation | BGE | |||||||||||||||||||||
Cash and cash equivalents | $ | 392 | $ | 392 | $ | — | $ | 62 | $ | 62 | $ | — | ||||||||||||||
Restricted cash | 117 | 96 | 21 | 80 | 52 | 28 | ||||||||||||||||||||
Accounts receivable, net | ||||||||||||||||||||||||||
Customer | 297 | 297 | — | 260 | 260 | — | ||||||||||||||||||||
Other | 57 | 57 | — | — | — | — | ||||||||||||||||||||
Mark-to-market derivatives assets | 171 | 171 | — | 21 | 21 | — | ||||||||||||||||||||
Inventory | ||||||||||||||||||||||||||
Materials and supplies | 172 | 172 | — | — | — | — | ||||||||||||||||||||
Other current assets | 33 | 26 | — | 34 | 23 | — | ||||||||||||||||||||
Total current assets | 1,239 | 1,211 | 21 | 457 | 418 | 28 | ||||||||||||||||||||
Property, plant and equipment, net | 4,638 | 4,638 | — | 1,171 | 1,171 | — | ||||||||||||||||||||
Nuclear decommissioning trust funds | 2,097 | 2,097 | — | — | — | — | ||||||||||||||||||||
Goodwill | 47 | 47 | — | — | — | — | ||||||||||||||||||||
Mark-to-market derivatives assets | 44 | 44 | — | — | — | — | ||||||||||||||||||||
Other noncurrent assets | 95 | 82 | 3 | 127 | 106 | 3 | ||||||||||||||||||||
Total noncurrent assets | 6,921 | 6,908 | 3 | 1,298 | 1,277 | 3 | ||||||||||||||||||||
Total assets | $ | 8,160 | $ | 8,119 | $ | 24 | $ | 1,755 | $ | 1,695 | $ | 31 | ||||||||||||||
Long-term debt due within one year | $ | 87 | $ | 5 | $ | 75 | $ | 85 | $ | 5 | $ | 70 | ||||||||||||||
Accounts payable | 292 | 292 | — | 170 | 170 | — | ||||||||||||||||||||
Accrued expenses | 111 | 108 | 2 | 26 | 22 | 4 | ||||||||||||||||||||
Mark-to-market derivative liabilities | 24 | 24 | — | 29 | 29 | — | ||||||||||||||||||||
Unamortized energy contract liabilities | 22 | 22 | — | 5 | 5 | — | ||||||||||||||||||||
Other current liabilities | 25 | 25 | — | 5 | 5 | — | ||||||||||||||||||||
Total current liabilities | 561 | 476 | 77 | 320 | 236 | 74 | ||||||||||||||||||||
Long-term debt | 212 | 81 | 120 | 298 | 86 | 195 | ||||||||||||||||||||
Asset retirement obligations | 1,763 | 1,763 | — | — | — | — | ||||||||||||||||||||
Pension obligation(a) | 9 | 9 | — | — | — | — | ||||||||||||||||||||
Unamortized energy contract liabilities | 51 | 51 | — | 28 | 28 | — | ||||||||||||||||||||
Other noncurrent liabilities | 127 | 127 | — | 12 | 12 | — | ||||||||||||||||||||
Noncurrent liabilities | 2,162 | 2,031 | 120 | 338 | 126 | 195 | ||||||||||||||||||||
Total liabilities | $ | 2,723 | $ | 2,507 | $ | 197 | $ | 658 | $ | 362 | $ | 269 | ||||||||||||||
___________ | ||||||||||||||||||||||||||
(a) | Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details. | |||||||||||||||||||||||||
Unconsolidated Variable Interest Entities | ||||||||||||||||||||||||||
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments and Other assets. 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, 2014 and 2013, Exelon and Generation had significant unconsolidated variable interests in six and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of Generation's ownership interest in four unconsolidated VIEs in 2014, offset by the execution of an energy purchase and sale agreement with an unconsolidated VIE and an equity investment in another unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities: | ||||||||||||||||||||||||||
31-Dec-14 | Commercial | Equity | Total | |||||||||||||||||||||||
Agreement | Investment | |||||||||||||||||||||||||
VIEs | VIEs | |||||||||||||||||||||||||
Total assets(a) | $ | 506 | $ | 91 | $ | 597 | ||||||||||||||||||||
Total liabilities(a) | 237 | 49 | 286 | |||||||||||||||||||||||
Exelon's ownership interest in VIE(a) | — | 9 | 9 | |||||||||||||||||||||||
Other ownership interests in VIE(a) | 269 | 33 | 302 | |||||||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||||
Carrying amount of equity method investments | — | 13 | 13 | |||||||||||||||||||||||
Contract intangible asset | 9 | — | 9 | |||||||||||||||||||||||
Debt and payment guarantees | — | 3 | 3 | |||||||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 27 | — | 27 | |||||||||||||||||||||||
31-Dec-13 | Commercial | Equity | Total | |||||||||||||||||||||||
Agreement | Investment | |||||||||||||||||||||||||
VIEs | VIEs | |||||||||||||||||||||||||
Total assets(a) | $ | 128 | $ | 332 | $ | 460 | ||||||||||||||||||||
Total liabilities(a) | 17 | 123 | 140 | |||||||||||||||||||||||
Exelon's ownership interest in VIE(a) | — | 86 | 86 | |||||||||||||||||||||||
Other ownership interests in VIE(a) | 111 | 123 | 234 | |||||||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||||
Carrying amount of equity method investments | 7 | 67 | 74 | |||||||||||||||||||||||
Contract intangible asset | 9 | — | 9 | |||||||||||||||||||||||
Debt and payment guarantees | — | 5 | 5 | |||||||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 44 | — | 44 | |||||||||||||||||||||||
___________________ | ||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||
(b) | 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 $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. | |||||||||||||||||||||||||
For each unconsolidated VIE, Exelon and Generation assessed 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. Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance. | ||||||||||||||||||||||||||
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 and 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 and Energy Generating Facilities. Generation has several equity investments in energy development projects and 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 the entity has an insufficient amount of equity at risk to finance its activities, 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 that most significantly impact the VIEs economic performance. | ||||||||||||||||||||||||||
ComEd, PECO and BGE | ||||||||||||||||||||||||||
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. |
Regulatory_Matters_Exelon_Gene
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||||
The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants. | ||||||||||||||||||||||||||||||||
Illinois Regulatory Matters | ||||||||||||||||||||||||||||||||
Energy Infrastructure Modernization Act (Exelon and ComEd). | ||||||||||||||||||||||||||||||||
Background | ||||||||||||||||||||||||||||||||
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 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, 2014, and December 31, 2013, ComEd had a regulatory asset associated with the distribution formula rate of $371 million and $463 million, respectively. The regulatory asset associated with distribution true-up is amortized to Operating revenues as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||||
Annual Reconciliation | ||||||||||||||||||||||||||||||||
2014 Filing. On April 16, 2014, ComEd filed its annual distribution formula rate to request a total increase to the revenue requirement of $269 million. On December 11, 2014, the ICC issued its final order which increased the revenue requirement by $232 million, reflecting an increase of $160 million for the initial revenue requirement for 2014 and an increase of $72 million related to the annual reconciliation for 2013. Approximately $23 million of the total $37 million revenue requirement disallowance is recoverable through other rider-based mechanisms. The rate increase was set using an allowed return on capital of 7.06% (inclusive of an allowed return on common equity of 9.25% for 2014 less a performance metrics penalty of 5 basis points for the 2013 reconciliation). The rates took effect in January 2015. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC on January 28, 2015. | ||||||||||||||||||||||||||||||||
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. 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 final revenue requirement reflected the impacts of Senate Bill 9, which became effective in May 2013 and clarified the intent of EIMA on three issues: 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. 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, which was subsequently withdrawn. | ||||||||||||||||||||||||||||||||
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, reflecting 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. The Illinois Appellate Court upheld the ICC's decision on the issues on appeal. 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. 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. The Illinois Appellate Court reaffirmed the ICC's order. | ||||||||||||||||||||||||||||||||
Formula Rate Structure Investigation | ||||||||||||||||||||||||||||||||
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 reduced 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. | ||||||||||||||||||||||||||||||||
Appeal of Initial Formula Rate Tariff | ||||||||||||||||||||||||||||||||
On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd’s appeal of the ICC’s order relating to ComEd’s initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order. | ||||||||||||||||||||||||||||||||
ComEd asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. On June 4, 2014, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court solely on the issue of allocation between FERC and ICC jurisdictional costs. On July 2, 2014, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate. Under the procedural rules of the Illinois Supreme Court, ComEd is not allowed to reply to the ICC filing. There is no set time by which the Court must rule on the Petition. ComEd cannot predict whether the Court will grant the appeal, or if it does, the ultimate outcome. | ||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||
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 on their AMI implementation progress. In March 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI meters. On June 11, 2014, the ICC approved ComEd's accelerated deployment plan which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 550,000 smart meters have been installed in the Chicago area. | ||||||||||||||||||||||||||||||||
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 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 approximately $37 million, including interest. On September 18, 2014, the ICC issued an order requiring the refund to occur in November 2014, rather than the eight month period previously approved. The refund was included with the Rider AMP refund discussed below. Former ComEd customers were eligible for a refund. ComEd was fully reserved for this liability at December 31, 2013. As of December 31, 2014 ComEd had refunded substantially all amounts to customers. | ||||||||||||||||||||||||||||||||
Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd’s 2007 Rate Case, the ICC approved recovery of costs associated with ComEd’s Rider SMP for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through December 31, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates. | ||||||||||||||||||||||||||||||||
Several parties, including the Illinois Attorney General, appealed the ICC’s orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC’s approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied. | ||||||||||||||||||||||||||||||||
In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP. During the second quarter of 2014, ComEd reached a tentative agreement to jointly resolve the disputed refund claim. On September 18, 2014, the ICC approved a refund of $9.5 million plus interest to be issued to current customers in November 2014. Former ComEd customers also were eligible for a refund. As of December 31, 2014 ComEd had refunded substantially all amounts to customers. | ||||||||||||||||||||||||||||||||
Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objection of numerous landowners and the City of Elgin. Four parties filed timely applications for rehearing before the ICC. On November 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but granted rehearing on the application of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line in Kane County. The rehearing proceeding is currently pending and the ICC must enter a final order on rehearing by April 24, 2015. On December 10, 2014, the ICC denied the remaining two applications for rehearing. On January 15, 2015, those two parties, the City of Elgin and the SKP landowner group and Utility Risk Management Corporation (collectively, the SKP/URMC party), each filed a Notice of Appeal with the Second District Appellate Court. On February 3, 2015, the ICC filed motions with the Second District Appellate Court seeking to extend the time for the ICC to file the record on appeal until after the ICC issues its Order on rehearing. The ICC also filed a motion to consolidate those appeals. ComEd expects to begin construction of the line in the second quarter of 2015 with an in-service date expected in the second quarter of 2017. | ||||||||||||||||||||||||||||||||
Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). ComEd is 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, 2014, the balance of purchased accounts receivable was $139 million. ComEd recovers from RES and customers the costs for implementing and operating the program under an ICC approved tariff. 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, 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. | ||||||||||||||||||||||||||||||||
ComEd is required to purchase an increasing percentage of the electricity 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. All associated costs are recoverable from customers. | ||||||||||||||||||||||||||||||||
On December 18, 2013, the ICC approved the IPA’s 2014-2019 procurement plan, which provided for two separate energy procurements during 2014 to address potential fluctuations in energy due to customers switching between ComEd and competitive electric generation suppliers. During May and September 2014, ComEd conducted energy procurements to meet the IPA’s 2014-2019 procurement plan. On December 17, 2014, the ICC approved the IPA’s 2015-2020 procurement plan. See Note 22 — Commitments and Contingencies for additional information on ComEd’s energy commitments. | ||||||||||||||||||||||||||||||||
FutureGen Industrial Alliance, Inc (Exelon and ComEd). 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 ComEd and Ameren 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 ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, 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 July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. A decision from the Illinois Appellate Court is expected in late 2015. | ||||||||||||||||||||||||||||||||
A significant portion of the cost of the development of FutureGen was being funded by the DOE under the American Recovery and Reinvestment Act of 2009. In early February 2015, the DOE suspended funding for the project until further clarity could be obtained on certain significant hurdles facing the project, including the outcome of the litigation described above. Whether or not the DOE funding will be reinstated at some later date is unknown at this time. | ||||||||||||||||||||||||||||||||
ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014. Depending on 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). 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 January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. The plans are designed to meet Illinois' energy efficiency and demand response goals through May 2017, 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 through 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 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. | ||||||||||||||||||||||||||||||||
Illinois utilities are 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 by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois 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 during 2015 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 — Income Taxes 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 procured 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. PECO entered into contracts with PAPUC approved bidders, including Generation, for its five competitive procurements. 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 submit a plan to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning in April 2014. On May 1, 2013, PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in 2015. | ||||||||||||||||||||||||||||||||
On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. On August 28, 2014, PECO filed a Joint Petition for Partial Settlement, which affirmed PECO’s procurement plan for Residential and Small Commercial customers. On December 4, 2014, the PAPUC approved PECO's third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separate from the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO will purchase electric supply for default service customers. PECO will procure electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. | ||||||||||||||||||||||||||||||||
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 electric 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 all of the remaining smart meters, for a total of 1.7 million smart meters, on an accelerated basis by the second quarter of 2015. In total, PECO currently expects to spend up to $583 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million has been funded by SGIG as discussed below. As of December 31, 2014, PECO has spent $540 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received. | ||||||||||||||||||||||||||||||||
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 were used by PECO to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of the third quarter of 2014, PECO received all of the $200 million, including $4 million for sub-recipients, in reimbursements. On October 15, 2014, the DOE issued a Close Out of Post-Award Project Cost Verification Audit, in which it was determined that PECO fully met its required cost share, and the audit was closed with no further action required. | ||||||||||||||||||||||||||||||||
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 remained 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. 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. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations. On March 14, 2014, PECO filed its quarterly smart meter recovery surcharge with the PAPUC which included PECO’s proposed treatment of the final agreement with the vendor. On March 27, 2014, the PAPUC approved the surcharge as proposed by PECO. | ||||||||||||||||||||||||||||||||
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. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO's EE&C Plan subsequent to its Phase II Plan. | ||||||||||||||||||||||||||||||||
On February 28, 2014, 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, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. The Order became final on May 5, 2014. | ||||||||||||||||||||||||||||||||
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 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. | ||||||||||||||||||||||||||||||||
Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electricity 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. Through various orders, the PAPUC issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedings discussed above for additional details. | ||||||||||||||||||||||||||||||||
In early 2014, the extreme weather in PECO's service territory resulted in increased electricity commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated switching by the December 15, 2014 deadline. | ||||||||||||||||||||||||||||||||
On September 12, 2013, the PAPUC issued an Order that initiated an investigation into Pennsylvania’s natural gas retail market, including the role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Order directing the Office of Competitive Market Oversight to continue its investigation, confirming that natural gas distribution companies should remain with the default service model for the time being and directing establishment of a working group to examine other competitive issues. Comments on the Final Order were due on February 2, 2015. PECO will continue to monitor the Order and assess compliance, as necessary. | ||||||||||||||||||||||||||||||||
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. On February 5, 2015, PECO filed a petition to modify its approved Gas LTIIP with the PAPUC. If approved, the modification would allow PECO to further accelerate the replacement of existing gas mains and also included a plan for the relocation of meters from indoors to outside in accordance with a recent PAPUC rulemaking. | ||||||||||||||||||||||||||||||||
Maryland Regulatory Matters | ||||||||||||||||||||||||||||||||
2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, and as amended on September 15, 2014, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $99 million and $68 million, respectively. | ||||||||||||||||||||||||||||||||
On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20 million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electric and gas distribution rates became effective for services rendered on or after December 15, 2014. | ||||||||||||||||||||||||||||||||
2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, 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 (the "ERI initiative") in response to a MDPSC order through a surcharge separate from base rates. | ||||||||||||||||||||||||||||||||
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, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. The ERI initiative surcharge became effective June 1, 2014. On November 3, 2014, BGE filed a surcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its work plan and cost estimates for 2015, to be included in the 2015 surcharge. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE's 2014 annual report, 2015 work plan and the 2015 surcharge. | ||||||||||||||||||||||||||||||||
In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE's 2013 electric and gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC's approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. BGE cannot predict the outcome of this appeal. If the residential consumer advocate's appeal is successful, BGE could recover ERI expenditures through other regulatory mechanisms. | ||||||||||||||||||||||||||||||||
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 for increases in annual distribution service revenue of $81 million and $32 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. The 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 the merger integration costs, including severance, incurred during the test year for the Exelon and Constellation merger. 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. | ||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was recovered through a grant from the DOE. 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, 2014 and December 31, 2013, BGE recorded a regulatory asset of $128 million and $66 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE's 2014 electric and gas distribution rate case discussed above, the cost of the retired non-AMI meters will be amortized over 10 years. | ||||||||||||||||||||||||||||||||
On February 26, 2014, the MDPSC issued an order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out of BGE's smart meter installation program, effective the later of the first full billing cycle following July 1, 2014, or the AMI installation date in a customer's community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. On November 25, 2014, the MDPSC issued a decision approving BGE's proposal to automatically enroll unresponsive customers into the opt-out program and to charge those customers opt-out fees after BGE has exhausted attempts to schedule a meter installation. The ultimate impact of opt-out 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. | ||||||||||||||||||||||||||||||||
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 700MW 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, 2014, 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 challenged 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. During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants on behalf of the MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times of restoration as well as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly and transparently align reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. The MDPSC held hearings in September 2014. 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. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of costs estimates included in the 2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing was approved with a revised surcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE's 2015 project list and the proposed surcharge for 2015. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of December 31, 2014. | ||||||||||||||||||||||||||||||||
In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE's infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court, however, a procedural schedule for the matter has not yet been set. | ||||||||||||||||||||||||||||||||
New York Regulatory Matters | ||||||||||||||||||||||||||||||||
Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). Ginna Nuclear Power Plant's (Ginna) prior period fixed-price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the agreement, Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginna management would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable. A formal study conducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain the reliability of the transmission grid in the Rochester region through 2018 when planned transmission system upgrades are expected to be completed. In November, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support Services Agreement (RSSA). On February 13, 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with FERC for their approval. While the RSSA is expected to be approved, in absence of such an agreement and in the event the plant was retired before the current license term ends in 2029, Exelon's and Generation's results of operations could be adversely affected by increased depreciation rates, impairment charges, severance costs, and accelerated future decommissioning costs, among other items. However, it is not expected that such impacts would be material to Exelon's or Generation's results of operations. | ||||||||||||||||||||||||||||||||
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 and BGE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The 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 in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of December 31, 2014, and 2013, ComEd had a regulatory asset associated with the transmission formula rate of $21 million and $17 million, respectively, and BGE had a net regulatory asset associated with the transmission formula rate of $1 million and a net regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates. | ||||||||||||||||||||||||||||||||
In April 2014, ComEd filed its annual 2014 formula rate update with the FERC, reflecting an increased revenue requirement of $22 million, including an increase of $36 million for the initial revenue requirement, offset by a decrease of $14 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2014. ComEd’s 2014 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. The time period for any challenges to ComEd's annual 2014 formula rate update expired in October 2014 with no challenges submitted. | ||||||||||||||||||||||||||||||||
In April 2013, ComEd filed its annual 2013 formula rate update with the FERC, reflecting an increased revenue requirement of $68 million, including an increase of $38 million for the initial revenue requirement and an increase of $30 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2013. ComEd’s 2013 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.70%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.91% average debt and equity return previously authorized. The time period for any challenges to ComEd's annual 2013 formula rate update expired in October 2013 with no challenges submitted. | ||||||||||||||||||||||||||||||||
As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. | ||||||||||||||||||||||||||||||||
In April 2014, BGE filed its 2014 formula rate update with the FERC reflecting an increased revenue requirement of $14 million, including an increase of $9 million for the initial revenue requirement and an increase of $5 million related to the annual reconciliation. The annual update established the revenue requirement used to set rates that took effect in June 2014. The time period for any challenges to BGE's annual update expired in October 2014 with no challenges submitted. | ||||||||||||||||||||||||||||||||
BGE’s 2014 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE’s 2005 transmission rate case in 2006, the 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) and a 50 basis point incentive for participating in PJM (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 revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE 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. | ||||||||||||||||||||||||||||||||
On August 21, 2014, FERC issued an order in the BGE and PHI companies' proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlement discussions under the guidance of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judge informed FERC and the Chief Judge that the parties had reached an impasse and determined that a settlement was not possible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015. | ||||||||||||||||||||||||||||||||
On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regarding the base ROE of the transmission business seeking a reduction from 10.8% to 8.8%. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants' requested refund effective date of December 8, 2014. | ||||||||||||||||||||||||||||||||
Based on the current status of the complaint filings, BGE believes it is probable that BGE's base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the two maximum fifteen month periods will be required. However, BGE is unable to estimate the most likely refund amount for either complaint at this time, and has therefore established a reserve, which is not material, representing the low end of a reasonably possible estimated range of loss. Additionally, management is unable to estimate the maximum exposure of a potential refund at this time, which may have a material impact on BGE's results of operations and cash flows. The estimated annual ongoing reduction in revenues if FERC approved the ROEs requested by the parties in their filings is approximately $11 million. If FERC were to order a reduction of BGE’s base ROE to 8.7% as sought in the first complaint (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result of the first fifteen month refund window would be a refund to customers of approximately $13 million. If FERC were to order a reduction in BGE’s base ROE to 8.8% as sought in the second complaint (while retaining 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment) and the refund period extended for a full fifteen months, the result would be a refund to customers of approximately $14 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 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. On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV and above. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the issue of the cost allocation for facilities 500 kV and above. The hearing only concerns new facilities approved by the PJM Board prior to February 1, 2013. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s 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 any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations, cash flows or financial position. | ||||||||||||||||||||||||||||||||
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 | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||||||||||||
ComEd | $ | 335 | $ | 150 | $ | 172 | $ | 5 | $ | 4 | $ | 4 | ||||||||||||||||||||
PECO | 100 | 32 | 31 | 25 | 8 | 4 | ||||||||||||||||||||||||||
BGE | 351 | 77 | 104 | 77 | 57 | 36 | ||||||||||||||||||||||||||
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 FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014. | ||||||||||||||||||||||||||||||||
Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM. | ||||||||||||||||||||||||||||||||
Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE). On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (“D.C. Circuit Decision”). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective. | ||||||||||||||||||||||||||||||||
In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decision for both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement the decision. FERC and several other parties sought rehearing of the D.C. Circuit Decision, which was denied in September 2014. In addition, on September 22, 2014, FERC and another party sought to stay the issuance of the D.C. Circuit Court's mandate so that FERC may appeal the decision to the U.S. Supreme Court. The stay was granted with respect to the FERC’s request only. In January 2015, the FERC sought to appeal the decision to the U.S. Supreme Court. Thus, the stay will be extended at least until the U.S. Supreme Court determines whether to allow the appeal. In addition, contemporaneously with the D.C. Circuit Court's decision on May 23, 2014, First Energy filed a complaint at FERC asking FERC to direct PJM to remove all PJM Tariff provisions that allow or require PJM to compensate demand response providers as a form of supply in the PJM capacity market effective May 23, 2014. FirstEnergy also asked FERC to declare the results of PJM's May 2014 Base Residual Auction for the 2017/2018 Delivery Year, void and illegal to the extent that demand response resources cleared that auction. On November 14, 2014, the New England Power Generators Association, Inc. ("NEPGA") filed a similar complaint at FERC asking FERC to disqualify demand response from the upcoming capacity auction in New England and to revise the New England tariff to remove demand response from participation in the capacity market. FERC's response to the FirstEnergy complaint and the NEPGA complaint and its response to address the D.C. Circuit Court's decision in all markets could preclude demand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations. In addition, there is uncertainty as to how FERC might treat already settled capacity market auctions as well as future auctions, both for demand response resources and generation resources. FERC could grant all or a portion of the relief requested by FirstEnergy and may grant relief retroactively or only prospectively. FERC could also pursue alternative means for allowing demand response to effectively participate in capacity markets it regulates. Due to these uncertainties, the Registrants are unable to predict the outcome of these proceedings, and the final outcome is not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE’s results of operations and cash flows. | ||||||||||||||||||||||||||||||||
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. On June 29, 2012, Generation, ComEd, PECO and BGE filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012. On December 21, 2012, Generation, ComEd, PECO, and BGE filed their updated market power analysis for the SPP region, which the FERC accepted on October 8, 2013. On December 30, 2013, Generation, ComEd, PECO and BGE filed its updated analysis for the Northeast Region, based on 2012 historic test period data which the FERC accepted on August 5, 2014. On December 23, 2014, Generation filed its updated market power analysis for the Southeast Region and the FERC has not yet acted on the filing. | ||||||||||||||||||||||||||||||||
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, 2018 occurred in May 2014. | ||||||||||||||||||||||||||||||||
New England Capacity Market Results (Exelon and Generation). Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with this requirement, on February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE's filings became effective by operation of law pursuant to a notice issued by the FERC's secretary on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the U.S. DC Circuit Court of Appeals. It is not clear whether such appeal would be effective as there is no action by the Commission to be considered. Nonetheless, while we think any change in the auction results to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerning the results of that auction, but any court action could be material to Exelon’s and Generation's expected revenues from the capacity auction. | ||||||||||||||||||||||||||||||||
License Renewals (Exelon and Generation). 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”) recognized 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. On August 26, 2014, the NRC Commissioners approved the issuance of a revised rule codifying the NRC's generic determinations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor's licensed operating life and removed the hold on final licensing decision as of the effective date of the final rule. On September 19, 2014, the NRC issued the Continued Storage Rule, which became effective on October 20, 2014. On October 24, 2014, New York, Vermont, and Connecticut filed a petition for review in federal court which alleges that the Continued Storage Rule violates various federal laws and regulations. The petition additionally challenges the Continued Storage Rule's supporting generic environmental impact statement (GEIS) as well as the August 26, 2014 NRC order lifting the suspension of all final licensing decisions for affected applications in view of the rule and GEIS. | ||||||||||||||||||||||||||||||||
On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2, which are currently set to expire in 2024 and 2026, respectively, and Braidwood Units 1 and 2, currently set to expire in 2026 and 2027, respectively, by 20 years. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until late 2015 at the earliest. | ||||||||||||||||||||||||||||||||
On October 20, 2014, the NRC approved Generation's request to extend the operating licenses of Limerick Units 1 and 2 by 20 years to 2044 and 2049, respectively. | ||||||||||||||||||||||||||||||||
On December 9, 2014, Generation submitted applications to the NRC to extend the operating licenses of LaSalle Units 1 and 2 by 20 years, which are currently set to expire in 2022 and 2023, respectively. Generation does not expect the NRC to issue license renewals for LaSalle until 2016 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. | ||||||||||||||||||||||||||||||||
Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Generation 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. MDE indicated that it believed it did not have sufficient information to process Generation's application. As a result, on December 5, 2014, Generation withdrew its pending application for a water quality certification. FERC policy requires that an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, Generation is working with MDE to coordinate the refiling of its application for certification within the 90-day period. In addition, Generation has entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Exelon has agreed to contribute up to $3.5 million to fund the additional study. Resolution of these issues relating to Conowingo may have a material effect on Exelon's and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs. | ||||||||||||||||||||||||||||||||
On June 3, 2014, subsequently amended December 9, 2014, the PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects. | ||||||||||||||||||||||||||||||||
The FERC licenses for Muddy Run and Conowingo were set to expire on August 31, 2014 and September 1, 2014 respectively. FERC is required to issue annual licenses for the facilities until the new licenses are issued. On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of the expiration of the previous licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renew automatically. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of December 31, 2014, $39 million of direct costs associated with licensing 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, 2014 and 2013. | ||||||||||||||||||||||||||||||||
December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 247 | $ | 3,009 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Deferred income taxes | 6 | 1,536 | — | 64 | — | 1,400 | 6 | 72 | ||||||||||||||||||||||||
AMI programs | 25 | 271 | 10 | 81 | 15 | 62 | — | 128 | ||||||||||||||||||||||||
Under-recovered distribution service costs | 251 | 120 | 251 | 120 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 8 | 49 | 6 | 47 | 2 | 2 | 1 | 8 | ||||||||||||||||||||||||
Fair value of BGE long-term debt | 7 | 183 | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 4 | 8 | — | — | — | — | 4 | 8 | ||||||||||||||||||||||||
Asset retirement obligations | 1 | 115 | 1 | 73 | — | 26 | — | 16 | ||||||||||||||||||||||||
MGP remediation costs | 36 | 221 | 30 | 189 | 6 | 31 | — | 1 | ||||||||||||||||||||||||
Under-recovered uncollectible accounts | — | 67 | — | 67 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy | 20 | 187 | 20 | 187 | — | — | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 37 | 11 | 26 | 7 | — | — | 11 | 4 | ||||||||||||||||||||||||
Deferred storm costs | 1 | 2 | — | — | — | — | 1 | 2 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 10 | 20 | — | — | — | — | 10 | 20 | ||||||||||||||||||||||||
Rate stabilization deferral | 75 | 85 | — | — | — | — | 75 | 85 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 89 | 159 | — | — | — | — | 89 | 159 | ||||||||||||||||||||||||
Merger integration costs | 2 | 6 | — | — | — | — | 2 | 6 | ||||||||||||||||||||||||
Conservation voltage reduction | 1 | 1 | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||
Under-recovered electric revenue decoupling | 7 | — | — | — | 7 | — | ||||||||||||||||||||||||||
Other (a) | 20 | 26 | 5 | 17 | 6 | 8 | 7 | — | ||||||||||||||||||||||||
Total regulatory assets | $ | 847 | $ | 6,076 | $ | 349 | $ | 852 | $ | 29 | $ | 1,529 | $ | 214 | $ | 510 | ||||||||||||||||
December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 51 | $ | 37 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Nuclear decommissioning | — | 2,879 | — | 2,389 | — | 490 | — | — | ||||||||||||||||||||||||
Removal costs | 118 | 1,448 | 94 | 1,249 | — | — | 24 | 199 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 25 | 2 | 25 | — | — | 2 | — | — | ||||||||||||||||||||||||
DLC program costs | — | 10 | — | — | — | 10 | — | — | ||||||||||||||||||||||||
Energy efficiency phase II | — | 32 | — | — | — | 32 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 8 | 94 | — | — | 8 | 94 | — | — | ||||||||||||||||||||||||
Gas distribution tax repairs | 20 | 29 | — | — | 20 | 29 | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 68 | 16 | 3 | 16 | 58 | — | 7 | — | ||||||||||||||||||||||||
Over-recovered electric universal service fund costs | 2 | — | — | — | 2 | — | — | — | ||||||||||||||||||||||||
Revenue subject to refund | 3 | — | 3 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered gas revenue decoupling | 12 | — | — | — | — | — | 12 | — | ||||||||||||||||||||||||
Other | 3 | 3 | — | 1 | 2 | — | 1 | 1 | ||||||||||||||||||||||||
Total regulatory liabilities | $ | 310 | $ | 4,550 | $ | 125 | $ | 3,655 | $ | 90 | $ | 657 | $ | 44 | $ | 200 | ||||||||||||||||
December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 221 | $ | 2,794 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | — | 1,317 | 8 | 77 | ||||||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | — | 58 | — | 66 | ||||||||||||||||||||||||
AMI meter events | — | 5 | — | — | — | 5 | — | — | ||||||||||||||||||||||||
Under-recovered distribution service costs | 178 | 285 | 178 | 285 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | ||||||||||||||||||||||||
Fair value of BGE long-term debt | — | 219 | — | — | — | — | — | — | ||||||||||||||||||||||||
Fair value of BGE supply contracts | 12 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 16 | 12 | 12 | — | — | — | 4 | 12 | ||||||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | — | 25 | — | 10 | ||||||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | ||||||||||||||||||||||||
RTO start-up costs | 2 | — | 2 | — | — | — | — | — | ||||||||||||||||||||||||
Under-recovered uncollectible accounts | — | 48 | — | 48 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | — | — | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 53 | 9 | 52 | 6 | — | — | 1 | 3 | ||||||||||||||||||||||||
Deferred storm costs | 3 | 3 | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 13 | 30 | — | — | — | — | 13 | 30 | ||||||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | — | — | — | — | 71 | 154 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 73 | 148 | — | — | — | — | 73 | 148 | ||||||||||||||||||||||||
Merger integration costs | 2 | 9 | — | — | — | — | 2 | 9 | ||||||||||||||||||||||||
Other (a) | 31 | 30 | 18 | 20 | 8 | 7 | 4 | 3 | ||||||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | ||||||||||||||||
December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Nuclear decommissioning | — | 2,740 | — | 2,293 | — | 447 | — | — | ||||||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | — | — | 21 | 204 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 53 | — | 45 | — | 8 | — | — | — | ||||||||||||||||||||||||
DLC Program Costs | 1 | 10 | — | — | 1 | 10 | — | — | ||||||||||||||||||||||||
Energy efficiency phase II | — | 21 | — | — | — | 21 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | — | — | 20 | 114 | — | — | ||||||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | — | — | 8 | 37 | ||||||||||||||||||||||||||
Energy and transmission programs | 78 | — | 9 | — | 58 | — | 11 | — | ||||||||||||||||||||||||
Over-recovered gas universal service fund costs | 8 | — | — | — | 8 | — | — | — | ||||||||||||||||||||||||
Revenue subject to refund | 38 | — | 38 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered electric and gas revenue decoupling | 16 | — | — | — | — | — | 16 | — | ||||||||||||||||||||||||
Other | 4 | — | — | — | 3 | — | — | — | ||||||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | ||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||
(a) | For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively. | |||||||||||||||||||||||||||||||
Pension and other postretirement benefits. As of December 31, 2014, Exelon had regulatory assets of $3,256 million and regulatory liabilities of $88 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 Constellation 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 Constellation 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 was 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. For PECO, this amount includes the impacts of electric and gas distribution repairs in the deductibility pursuant to PUC’s 2010 rate case settlement agreement. 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 through May 31, 2014, and January 1, 2020, respectively. As of December 31, 2014 and December 31, 2013, ComEd had regulatory assets of $88 million and $35 million, respectively, 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 regulatory asset. 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 recovery of those costs commenced with the new rates approved and implemented with the MDPSC order in BGE's 2014 electric and gas distribution case. | ||||||||||||||||||||||||||||||||
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 not 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 deferred these costs on Exelon’s and PECO’s Consolidated Balance Sheet, beginning in 2012. PECO did not earn a return on the recovery of these costs. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations. | ||||||||||||||||||||||||||||||||
Under-recovered distribution services costs. Under EIMA, 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 was recovered through rates over a one-year period that began in January 2014. The under recovery associated with the 2013 reconciliation will be recovered through rates over a one-year period beginning in January 2015. 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, 2014, the regulatory asset was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events. In addition to $66 million in deferred storm costs, net of amortization, the December 31, 2014 balance related to significant one-time events contains $19 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. As of December 31, 2013, the regulatory asset was comprised of $377 million for the applicable annual reconciliations 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 Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. See Note 4 — Mergers, Acquisitions, and Dispositions 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 Constellation 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 and is not earning a return on the recovery of these costs. | ||||||||||||||||||||||||||||||||
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 Constellation merger date based on the MDPSC practice to allow BGE to recover its supply contracts through rates. Exelon amortized the regulatory asset and the associated fair value through December 31, 2014 and was not earning a return on the recovery of these contracts. | ||||||||||||||||||||||||||||||||
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, and such costs were fully recovered as of December 31, 2014. ComEd did not earn 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 through December 31, 2013. 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. ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. 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. 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. 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, 2014, PECO was under-recovered for its gas program and over-recovered for its electric program. Whereas, 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. | ||||||||||||||||||||||||||||||||
Under (Over)-recovered uncollectible accounts. ComEd adjusts its rates annually to reflect the increases and decreases in annual uncollectible accounts costs. The recovery or refund of the difference in the uncollectible accounts costs takes 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. | ||||||||||||||||||||||||||||||||
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. 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. As of December 31, 2014, ComEd's regulatory asset of $33 million included $4 million related to under-recovered energy costs for non-hourly customers, $22 million associated with transmission costs recoverable through its FERC-approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2014, ComEd's regulatory liability of $19 million included $3 million related to over-recovered energy costs for hourly customers and $16 million associated with revenues received for renewable energy requirements. As of December 31, 2013, ComEd's regulatory asset of $58 million included $35 million related to under-recovered energy costs for hourly and non-hourly customers, $17 million associated with transmission costs recoverable through its FERC-approved formula rate, and $6 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2013, ComEd's regulatory liability of $9 million related to revenues received for renewable energy requirements. | ||||||||||||||||||||||||||||||||
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. See discussion below of each program. 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, 2014, PECO had a regulatory liability that included $39 million related to the DSP program, $16 million related to over-recovered natural gas supply costs under the PGC and $3 million related to over-recovered electric transmission costs. As of December 31, 2013, PECO had a regulatory liability that included $34 million related to the DSP program, $8 million related the over-recovered electric transmission costs and $16 million related to over-recovered natural gas supply costs under the PGC. | ||||||||||||||||||||||||||||||||
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. 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. These costs are included within the energy and transmission programs line item. | ||||||||||||||||||||||||||||||||
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, 2014, BGE's regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE's regulatory liability of $7 million related to over-recovered natural gas supply costs. As of December 31, 2013, BGE's regulatory asset of $4 million included $3 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2013, BGE's regulatory liability of $11 million related to over-recovered natural gas supply costs. | ||||||||||||||||||||||||||||||||
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 was $28 million as of December 31, 2014, and $37 million as of December 31, 2013. 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 2014 and 2013, BGE recovered $65 million and $66 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 recovers these costs 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 Constellation 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, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling. 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. | ||||||||||||||||||||||||||||||||
Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units 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-recovered 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 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. These costs are included within the energy and transmission programs line item. | ||||||||||||||||||||||||||||||||
Revenue subject to refund. These amounts represent refunds and associated interest ComEd owes to customers primarily related to the treatment of the post-test year accumulated depreciation issue in the 2007 Rate Case. As of December 31, 2014, and December 31, 2013, ComEd owed $3 million and $37 million with $1 million of interest, respectively. 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, 2014 and 2013. | ||||||||||||||||||||||||||||||||
As of December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 290 | $ | 139 | $ | 76 | $ | 75 | ||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | (42 | ) | (21 | ) | (8 | ) | (13 | ) | ||||||||||||||||||||||||
Purchased receivables, net | $ | 248 | $ | 118 | $ | 68 | $ | 62 | ||||||||||||||||||||||||
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 | ||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||
(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. |
Mergers_Acquisitions_and_Dispo
Mergers, Acquisitions and Dispositions (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Business Combinations [Abstract] | ||||||||||||||||
Mergers, Acquisitions and Dispositions | Mergers, Acquisitions, and Dispositions | |||||||||||||||
Proposed Merger with Pepco Holdings, Inc. (Exelon) | ||||||||||||||||
Description of Transaction | ||||||||||||||||
On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $126 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI as of December 31, 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. The preferred securities are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. Exelon expects total cash required to fund the acquisition of common stock and preferred securities plus other related acquisition costs to total approximately $7.2 billion. As part of the applications for approval of the merger, Exelon and PHI proposed a package of benefits to the PHI utilities’ respective customers, providing for direct investment of more than $100 million with the actual amount and timing of any related payments dependent upon settlement discussions in merger regulatory approval proceedings and the terms of regulatory orders approving the merger. | ||||||||||||||||
To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses. On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. | ||||||||||||||||
Completion of the transaction also remains conditioned upon approval by the Public Services Commissions of the District of Columbia, Delaware and Maryland. Procedural schedules have been set in these commission proceedings and final approval decisions are expected in the first half of 2015. | ||||||||||||||||
On October 9, 2014, PHI and Exelon each received a request for additional information from the DOJ. The request had the effect of extending the DOJ review period until 30 days after PHI and Exelon each has certified that it had substantially complied with the request. On November 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Exelon and PHI will continue to work cooperatively with the DOJ regarding the proposed merger. | ||||||||||||||||
Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015. | ||||||||||||||||
Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. In September 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposed settlement is not expected to occur until the second quarter of 2015, at the earliest. Exelon has also been named in a federal court case with similar claims and is in the process of negotiating a settlement. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s results of operations. | ||||||||||||||||
Through December 31, 2014, Exelon has incurred approximately $179 million of expense associated with the proposed merger, primarily $48 million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement also provides for termination rights on behalf of both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHI described above, through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock. | ||||||||||||||||
Merger Financing | ||||||||||||||||
Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1.0 billion in cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). On June 11, 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share in connection with forward sales agreements and $1.2 billion of junior subordinated notes in the form of 23 million equity units. In addition, Exelon signed a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to a $3.2 billion facility as a result of the execution of the debt and equity security issuances and the net after-tax cash proceeds from generating asset divestitures during the second half of 2014. See Note 13 — Debt and Credit Agreements and Note 19 — Common Stock for more information. | ||||||||||||||||
Acquisitions (Exelon and Generation) | ||||||||||||||||
Acquisition of Integrys Energy Services, Inc. (Exelon and Generation) | ||||||||||||||||
On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. As of December 31, 2014, Generation had remitted $319 million to Integrys Energy Group, Inc. and the remaining balance of $13 million, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets, will be paid during the first or second quarter of 2015. The generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature. | ||||||||||||||||
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. | ||||||||||||||||
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the Integrys acquisition by Generation: | ||||||||||||||||
Total consideration transferred | $ | 332 | ||||||||||||||
Identifiable assets acquired and liabilities assumed | ||||||||||||||||
Working capital assets | $ | 389 | ||||||||||||||
Mark-to-market derivative assets | 185 | |||||||||||||||
Unamortized energy contract assets | 115 | |||||||||||||||
Customer relationships | 48 | |||||||||||||||
Working capital liabilities | (195 | ) | ||||||||||||||
Mark-to-market derivative liabilities | (57 | ) | ||||||||||||||
Unamortized energy contract liabilities | (109 | ) | ||||||||||||||
Deferred tax liability | (16 | ) | ||||||||||||||
Total net identifiable assets, at fair value | $ | 360 | ||||||||||||||
Bargain purchase gain (after-tax) | $ | 28 | ||||||||||||||
The purchase accounting is preliminary, and although not expected, may be further adjusted from what is shown above. | ||||||||||||||||
The after-tax bargain purchase gain of $28 million is primarily the result of IES executing additional contract volumes between the date the acquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of the acquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||
IES's operating revenue and net loss included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the period from November 1, 2014 to December 31, 2014 were approximately $386 million and $(42) million, respectively. The net loss includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase gain of $28 million. Exelon and Generation incurred approximately $7 million of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||
Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||
Description of Constellation Merger 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 from the Constellation Merger | ||||||||||||||||
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 | BGE | Generation | Exelon | Statement of | |||||||||||
Period | Operations | |||||||||||||||
Location | ||||||||||||||||
BGE rate credit of $100 per | Q2 2012 | $ | 113 | $ | — | $ | 113 | Revenues | ||||||||
residential customer (a) | ||||||||||||||||
Customer investment fund to invest | 2012 to 2014 | — | — | 114 | O&M Expense | |||||||||||
in energy efficiency and low-income energy assistance to BGE customers | ||||||||||||||||
Contribution for renewable energy, | 2012 to 2014 | — | — | 2 | O&M Expense | |||||||||||
energy efficiency or related projects in Baltimore | ||||||||||||||||
Charitable contributions at $7 million | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | |||||||||||
per year for 10 years | ||||||||||||||||
State funding for offshore wind | Q2 2012 | — | — | 32 | O&M Expense | |||||||||||
development projects | ||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | (2 | ) | — | (2 | ) | Taxes Other Than Income | |||||||||
Total | $ | 139 | $ | 35 | $ | 329 | ||||||||||
_______________________ | ||||||||||||||||
(a) | 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 was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. See Note 22 — Commitments and Contingencies for further information regarding Generation's total commitments under the lease agreement. | ||||||||||||||||
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—300MWs 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 or certain specified provisions are elected, 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. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. While this $44 million loss contingency represents Generation's best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant. | ||||||||||||||||
To date, Generation has placed into service 40MW and has commenced development of 150MW of new generation in Maryland towards the 300MW commitment. In July 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland site with at least 120MW of natural gas-fired generation to satisfy one of the commitments to Maryland with achievement of commercial operation expected in 2015. In December 2013, Generation entered into contracts associated with the construction of the 40MW Fourmile Wind project, which was placed in service in December 2014. In December 2014, Generation entered into contracts associated with the construction of the 30MW Fair Wind project in western Maryland with achievement of commercial operations expected in 2015. The wind projects will satisfy a portion of the 125MW Tier I land-based renewables commitment. See Note 22 — Commitments and Contingencies for additional information. Exelon’s and Generation’s consolidated financial statements include $185 million and $24 million of capitalized expenditures within Property, plant and equipment, net as of December 31, 2014 and 2013, respectively, and $3 million and $6 million of development costs within Operating and maintenance expense for the periods ended December 31, 2014 and 2013, respectively, associated with the 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 was 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 was 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 Constellation Merger | ||||||||||||||||
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 ratesetting 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 | — | ||||||||||||||
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 | ||||||||||||||
Noncontrolling interest | 90 | 90 | ||||||||||||||
Deferred credits and other liabilities and preferred securities | 4,683 | 1,933 | ||||||||||||||
Total liabilities, preferred securities and noncontrolling interest | 15,535 | 9,311 | ||||||||||||||
Total purchase price | $ | 7,365 | $ | 5,264 | ||||||||||||
Impact of the Constellation 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 $3,165 million, $3,065 million and $2,091 million and net income (loss) $211 million, $210 million and $(31) million during the years ended December 31, 2014, 2013 and 2012, respectively. | ||||||||||||||||
During the year ended December 31, 2014, Exelon and Generation both incurred merger and integration-related costs of $22 million. Of these amounts, nothing was deferred as a regulatory asset as of December 31, 2014. | ||||||||||||||||
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, 2014, 2013, and 2012. See Note 22 — Commitments and Contingencies for additional information. | ||||||||||||||||
Pro-forma Impact of the Constellation 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. | ||||||||||||||||
Exelon | Generation | |||||||||||||||
Year Ended December 31, | Year Ended December 31, | |||||||||||||||
(unaudited) | 2012 | 2011 (a) | 2012 | 2011 (a) | ||||||||||||
Total revenues | 26,700 | 30,712 | 17,013 | 19,494 | ||||||||||||
Net income attributable to Exelon | 2,092 | 974 | 1,205 | 324 | ||||||||||||
Basic earnings per share | 2.56 | 1.15 | n.a. | n.a. | ||||||||||||
Diluted earnings per share | 2.55 | 1.14 | n.a. | n.a. | ||||||||||||
_____________________ | ||||||||||||||||
(a) The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011. | ||||||||||||||||
(b) The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011. | ||||||||||||||||
Asset Divestitures (Exelon and Generation) | ||||||||||||||||
Including the Quail Run generating facility that was sold on January 21, 2015, Generation has sold certain generating assets with a total net book value of approximately $1.8 billion prior to consideration of asset impairments (See Note 8 — Impairment of Long-Lived Assets for further information), for total pre-tax proceeds of approximately $1.8 billion (after-tax proceeds of approximately $1.4 billion), which resulted in cumulative pre-tax gains on sale of approximately $412 million, which are included in Gain (loss) on sales of assets on Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income. The proceeds are expected to be used primarily to finance a portion of the acquisition of PHI. | ||||||||||||||||
Station | Net Generation Capacity | Location | Operating Segment | Percent Owned | ||||||||||||
Fore River | 726 | North Weymouth, MA | New England | 100% | ||||||||||||
West Valley | 185 | Salt Lake City, UT | Other | 100% | ||||||||||||
Keystone | 714 | Shelocta, PA | Mid-Atlantic | 41.98% | ||||||||||||
Conemaugh | 532 | New Florence, PA | Mid-Atlantic | 31.28% | ||||||||||||
Safe Harbor | 278 | Conestoga, PA | Mid-Atlantic | 66.70% | ||||||||||||
Quail Run | 488 | Odessa, TX | ERCOT | 100% | ||||||||||||
At December 31, 2014, the assets and liabilities of the Quail Run generating facility were reported as Assets held for sale and within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. The table below presents the major classes of assets and liabilities held for sale at December 31, 2014. | ||||||||||||||||
December 31, 2014 | ||||||||||||||||
Assets: | ||||||||||||||||
Property, plant and equipment, net (a) | $ | 143 | ||||||||||||||
Inventory | 4 | |||||||||||||||
Total assets held for sale | $ | 147 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accrued expenses | $ | 1 | ||||||||||||||
Asset retirement obligations | 4 | |||||||||||||||
Total liabilities held for sale (b) | $ | 5 | ||||||||||||||
_____________ | ||||||||||||||||
(a) The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information. | ||||||||||||||||
(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. |
Investment_in_Constellation_En
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Business Combinations [Abstract] | |||||
Investment in Constellation Energy Nuclear Group LLC (Exelon and Generation) | 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 has historically had 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 April 1, 2014, Generation and subsidiaries of Generation, EDF, EDF, Inc. (EDFI) (a subsidiary of EDF) and CENG entered into 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 (the Integration Transaction). CENG will reimburse Generation for its direct and allocated costs for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with Long Island Power Authority, the Unit 2 co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement (PSAA) was amended and extended until the permanent cessation of power generation by the CENG generation plants. | |||||
In addition, on April 1, 2014, Generation made 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 April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI. | |||||
Exelon, Generation, and subsidiaries of Generation, EDFI and its parent (E.D.F. International S.A.S.), and CENG also executed a Fourth Amended and Restated Operating Agreement for CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred distributions to Generation (after repayment of the $400 million loan and associated interest) 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 April 1, 2014 (Preferred Distribution Rights). | |||||
Generation and EDFI also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDFI has 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 NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. | |||||
On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified 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 guarantees Generation’s obligations under this indemnity. | |||||
In addition, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon's assumption of the sponsorship of the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transfer service of employees, including the underfunded balance of the pension and other postretirement welfare benefit plans measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. | |||||
As a condition to obtaining regulatory approval for the NOSA and related transactions from the NRC, Exelon executed a support agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (Exelon Support Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDF remains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG under specified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability has been recognized by Exelon for the guarantees. | |||||
Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investment in CENG and recorded $17 million of revenues from CENG. For the twelve months ended December 31, 2013, Generation recorded $9 million of equity in losses of unconsolidated affiliates related to its investment in CENG and $56 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million. | |||||
As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s Consolidated Financial Statements between CENG and EDF that are considered related party transactions to Generation. As further described in Note 25 — Related Party Transactions EDF and Generation had a PPA with CENG under which they purchased 15% and 85% (through December 31, 2014), respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For the year ended December 31, 2014, Generation had sales to EDF of $137 million. See discussion above and Note 2 — Variable Interest Entities for additional information regarding other transactions, between CENG and EDF included within Exelon and Generation’s financial statements. | |||||
See Note 2 — Variable Interest Entities for additional information about the Registrant's VIEs. | |||||
Accounting for the Consolidation of CENG | |||||
The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within their respective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to the step up to fair value basis of our ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF. | |||||
The fair value of CENG’s assets and liabilities recorded in consolidation 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 valuations necessary to assess the fair values of certain assets and liabilities are considered preliminary as a result of the short time period between the execution of the NOSA and the end of the second quarter of 2014. The estimates of the fair value of assets and liabilities may be modified up to one year from April 1, 2014, as more information is obtained about the fair value of assets and liabilities. The principal items that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with inputs from a third party engineering firm with corresponding adjustments recorded in 2014. See Note 15—Asset Retirement Obligations for discussion of the impacts of adjustments recorded during 2014 related to updated estimates of the CENG asset retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments have resulted in adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date have impacted Generation’s post-consolidation results of operations. No material changes are expected to the fair value of assets and liabilities. | |||||
Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above: | |||||
Fair Values | Exelon and Generation | ||||
Current assets | $ | 499 | |||
Nuclear decommissioning trust fund | 1,955 | ||||
Property, plant and equipment | 3,017 | ||||
Nuclear fuel | 482 | ||||
Other assets | 10 | ||||
Total assets | 5,963 | ||||
Current liabilities | 237 | ||||
Asset retirement obligation | 1,760 | ||||
Pension and other employee benefit obligations | 281 | ||||
Unamortized energy contract liabilities | 171 | ||||
Other liabilities | 114 | ||||
Total liabilities | 2,563 | ||||
Total net assets | $ | 3,400 | |||
Generation also recorded the fair value of the noncontrolling interest on its Consolidated Balance Sheets of approximately $1.5 billion, net of the fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrolling interest was further reduced by the $400 million special cash distribution to EDF. | |||||
Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’S net assets. For the year ended December 31, 2014, Generation reduced by $13 million the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $218 million and CENG’s net income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $407 million during the year ended December 31, 2014. | |||||
Exelon and Generation incurred integration-related costs of $26 million for the year ended December 31, 2014. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. | |||||
See Note 17—Severance for integration-related severance costs incurred by Exelon and Generation during the year ended December 31, 2014. |
Accounts_Receivable_Exelon_Gen
Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Receivables [Abstract] | |||||||||||||||||||||
Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) | Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||||||||||
Accounts receivable at December 31, 2014 and 2013 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: | |||||||||||||||||||||
2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unbilled customer revenues | $ | 1,381 | $ | 823 | (a) | $ | 204 | $ | 140 | $ | 214 | ||||||||||
Allowance for uncollectible | (311 | ) | (60 | ) | (84 | ) | (100 | ) | (c) | (67 | ) | (d) | |||||||||
accounts (b) | |||||||||||||||||||||
2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unbilled customer revenues | $ | 1,151 | $ | 584 | (a) | $ | 201 | $ | 161 | $ | 205 | ||||||||||
Allowance for uncollectible | (272 | ) | (57 | ) | (62 | ) | (107 | ) | (c) | (46 | ) | (d) | |||||||||
accounts (b) | |||||||||||||||||||||
_________________________ | |||||||||||||||||||||
(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 $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below. | ||||||||||||||||||||
(d) | At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
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 $15 million and $19 million as of December 31, 2014 and 2013, 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, 2014 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance 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 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, 2014 and 2013 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. |
Property_Plant_and_Equipment_E
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE) | 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, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-90 | $ | 30,157 | $ | 28,123 | ||||||
Electric—generation | Jan-56 | 22,911 | 20,420 | ||||||||
Gas—transportation and distribution | May-90 | 3,505 | 3,296 | ||||||||
Common—electric and gas | May-50 | 1,169 | 1,101 | ||||||||
Nuclear fuel (a) | 8-Jan | 5,947 | 5,196 | ||||||||
Construction work in progress | N/A | 2,167 | 1,890 | ||||||||
Other property, plant and equipment (b) | May-50 | 973 | 1,017 | ||||||||
Total property, plant and equipment | 66,829 | 61,043 | |||||||||
Less: accumulated depreciation (c) | 14,742 | 13,713 | |||||||||
Property, plant and equipment, net | $ | 52,087 | $ | 47,330 | |||||||
_________________________ | |||||||||||
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively. | ||||||||||
(b) | Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation. | ||||||||||
(c) | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | ||||||||||
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 | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.93 | % | 2.91 | % | 2.76 | % | |||||
Electric—generation | 3.5 | % | 3.35 | % | 3.15 | % | |||||
Gas | 2.13 | % | 2.06 | % | 2.03 | % | |||||
Common—electric and gas | 7.32 | % | 7.53 | % | 7.61 | % | |||||
Generation | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—generation | Jan-56 | $ | 22,911 | 19,004,000,000 | $ | 20,420 | |||||
Nuclear fuel (a) | 8-Jan | 5,947 | 4,815,000,000 | 5,196 | |||||||
Construction work in progress | N/A | 1,404 | 1,352,000,000 | 1,129 | |||||||
Other property, plant and equipment (b) | Jun-31 | 295 | 374,000,000 | 400 | |||||||
Total property, plant and equipment | 30,557 | 27,145 | |||||||||
Less: accumulated depreciation (c) | 7,612 | 7,034 | |||||||||
Property, plant and equipment, net | $ | 22,945 | $ | 20,111 | |||||||
_________________________ | |||||||||||
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively. | ||||||||||
(b) | Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities. | ||||||||||
(c) | Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | ||||||||||
The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.5%, 3.35% and 3.15% for the years ended December 31, 2014, 2013 and 2012, 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. | |||||||||||
ComEd | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-80 | $ | 18,884 | $ | 17,334 | ||||||
Construction work in progress | N/A | 276 | 456 | ||||||||
Other property, plant and equipment (a) | 39-50 | 65 | 60 | ||||||||
Total property, plant and equipment | 19,225 | 17,850 | |||||||||
Less: accumulated depreciation | 3,432 | 3,184 | |||||||||
Property, plant and equipment, net | $ | 15,793 | $ | 14,666 | |||||||
_________________________ | |||||||||||
(a) | Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. | ||||||||||
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 3.05%, 2.97% and 2.79% for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||
PECO | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-65 | $ | 6,886 | $ | 6,669 | ||||||
Gas—transportation and distribution | May-70 | 2,039 | 1,932 | ||||||||
Common—electric and gas | May-50 | 618 | 600 | ||||||||
Construction work in progress | N/A | 154 | 101 | ||||||||
Other property, plant and equipment (a) | 50 | 21 | 17 | ||||||||
Total property, plant and equipment | 9,718 | 9,319 | |||||||||
Less: accumulated depreciation | 2,917 | 2,935 | |||||||||
Property, plant and equipment, net | $ | 6,801 | $ | 6,384 | |||||||
_________________________ | |||||||||||
(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 | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.55 | % | 2.73 | % | 2.51 | % | |||||
Gas | 1.84 | % | 1.79 | % | 1.77 | % | |||||
Common—electric and gas | 5.16 | % | 6.65 | % | 7.54 | % | |||||
BGE | |||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-90 | $ | 6,339 | $ | 6,100 | ||||||
Gas—distribution | May-90 | 1,761 | 1,660 | ||||||||
Common—electric and gas | May-40 | 623 | 578 | ||||||||
Construction work in progress | N/A | 317 | 196 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 32 | ||||||||
Total property, plant and equipment | 9,072 | 8,566 | |||||||||
Less: accumulated depreciation | 2,868 | 2,702 | |||||||||
Property, plant and equipment, net | $ | 6,204 | $ | 5,864 | |||||||
_______________________ | |||||||||||
(a) | Represents land held for future use and non utility property. | ||||||||||
Average Service Life Percentage by Asset Category | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.96 | % | 2.91 | % | 2.92 | % | |||||
Gas | 2.47 | % | 2.36 | % | 2.33 | % | |||||
Common—electric and gas | 9.49 | % | 8.45 | % | 7.68 | % | |||||
See Note 1—Significant Accounting Policies 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. |
Impairment_of_Longlived_Assets
Impairment of Long-lived Assets (Exelon and Generation) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Impairment or Disposal of Tangible Assets Disclosure [Abstract] | ||||||||
Impairment Of Long-Lived Assets (Exelon and Generation) | 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 2014, updates to the long-term fundamental energy prices, which included a thorough evaluation of key assumptions including gas prices, load growth, plant retirements and renewable growth, suggested that the carrying value of certain wind assets with market price exposure may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. | ||||||||
In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with market price exposure for either all or a portion of the life of the asset 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. 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, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. | ||||||||
In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon's and Generation's Consolidated Balance Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset's carrying value exceeds its estimated fair value less costs to sell. Long-lived assets with a carrying amount of approximately $1 billion were written down to their fair value of $556 million and a pre-tax impairment charge of $450 million was recorded in Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | ||||||||
In 2012, a subsidiary of Generation sold three Maryland generating stations in connection with the Constellation merger. As a result of the transaction, Exelon and Generation recorded a pre-tax impairment charge of $272 million to reflect the difference between the sales price and the carrying value of the generating stations, which was included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. | ||||||||
See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales. | ||||||||
In the fourth quarter of 2014, a significant decline in oil prices suggested that the carrying value of certain Upstream assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily located in Oklahoma and Texas, were less than their respective carrying values at December 31, 2014. As a result, long-lived assets with a combined net book value of approximately $163 million were written down to their fair value of $39 million and a pre-tax impairment charge of $124 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. After reflecting the impairment, Generation has $189 million of Upstream assets remaining on its Consolidated Balance Sheets at December 31, 2014. Further declines in commodity prices could potentially result in future impairments of the Upstream assets. | ||||||||
The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material. | ||||||||
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 operate the stations and keep or market the power itself or require the lessees to arrange for a third-party to bid on a service contract for a period following the lease term. 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 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. | ||||||||
On February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on the generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote down the net investment in the CPS long-term lease of $336 million in Investments in Exelon's Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income in 2014. | ||||||||
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 annual reviews performed in 2014 and 2013, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $24 million and $14 million pre-tax impairment charge in 2014 and 2013, respectively, for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements of Operations and Comprehensive Income, 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, 2014, 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 2014. | ||||||||
At December 31, 2014 and 2013, the components of the net investment in long-term leases were as follows: | ||||||||
December 31, 2014 | December 31, 2013 | |||||||
Estimated residual value of leased assets | $ | 685 | $ | 1,465 | ||||
Less: unearned income | 324 | 767 | ||||||
Net investment in long-term leases | $ | 361 | $ | 698 | ||||
Jointly_Owned_Electric_Utility
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Public Utilities, Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE) | |||||||||||||||||||||||||||||||||||||||
Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||||||||||||||
Nuclear generation | Fossil fuel generation | Transmission | Other | |||||||||||||||||||||||||||||||||||||
Quad Cities | Peach | Salem (a) | Nine Mile Point Unit 2(g) | Keystone | Conemaugh | Wyman | PA (b) | DE/NJ (c) | Other (d) | |||||||||||||||||||||||||||||||
Bottom | ||||||||||||||||||||||||||||||||||||||||
(f) | (f) | |||||||||||||||||||||||||||||||||||||||
Operator | Generation | Generation | PSEG | Generation | GenOn | GenOn | FP&L | First | PSEG | |||||||||||||||||||||||||||||||
Nuclear | Energy | |||||||||||||||||||||||||||||||||||||||
Ownership interest | 75 | % | 50 | % | 42.59 | % | 82 | % | — | — | 5.89 | % | Various | 42.55 | % | 44.24 | % | |||||||||||||||||||||||
Exelon’s share at December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Plant (e) | $ | 995 | $ | 1,095 | $ | 531 | $ | 676 | $ | — | $ | — | $ | 3 | $ | 14 | $ | 64 | $ | 2 | ||||||||||||||||||||
Accumulated | 266 | 343 | 150 | 14 | — | — | 3 | 7 | 34 | 1 | ||||||||||||||||||||||||||||||
depreciation (e) | ||||||||||||||||||||||||||||||||||||||||
Construction work | 15 | 133 | 29 | 48 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
in progress | ||||||||||||||||||||||||||||||||||||||||
Exelon’s share at December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Plant (e) | $ | 941 | $ | 883 | $ | 501 | $ | — | $ | 725 | $ | 399 | $ | 3 | $ | 14 | $ | 64 | $ | 2 | ||||||||||||||||||||
Accumulated depreciation (e) | 226 | 326 | 134 | — | 268 | 220 | 3 | 7 | 34 | 1 | ||||||||||||||||||||||||||||||
Construction work | 27 | 174 | 24 | — | 6 | 121 | — | — | — | — | ||||||||||||||||||||||||||||||
in progress | ||||||||||||||||||||||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||||||||||||||
(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, 2014 and 2013. | |||||||||||||||||||||||||||||||||||||||
(b) | PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||||
(c) | PECO owns a 42.55% share in 131 miles of 500kV 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. | |||||||||||||||||||||||||||||||||||||||
(d) | Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey. | |||||||||||||||||||||||||||||||||||||||
(e) | Excludes asset retirement costs. | |||||||||||||||||||||||||||||||||||||||
(f) | As of December 31, 2014, Generation sold its ownership interest in Keystone and Conemaugh. At December 31, 2013, Generation held 41.98% and 31.28% ownership interest in Keystone and Conemaugh, respectively. See Note 4—Mergers, Acquisitions, and Dispositions for additional information. | |||||||||||||||||||||||||||||||||||||||
(g) | On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet, and as of that date, CENG’s operations are consolidated into Generation’s financial statements. As of December 31, 2013, Generation’s ownership interest in CENG, including Nine Mile Point, was treated as an equity method investment, and thus did not represent an undivided Interest. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||||||||||||||||||||||||||||||||||||
Exelon’s, Generation’s, PECO’s and BGE’s undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO’s and BGE’s share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses on PECO’s and BGE’s Consolidated Statements of Operations and Comprehensive Income. |
Intangible_Assets_Exelon_Gener
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE) | 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, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||||||
ComEd | Generation | Exelon | |||||||||||||||||||||||||||||||
Gross | Accumulated | Carrying | Gross | Carrying | Gross | Accumulated | Carrying | ||||||||||||||||||||||||||
Amount (a) | Impairment | Amount | Amount | Amount | Amount | Impairment | Amount | ||||||||||||||||||||||||||
Losses | Losses | ||||||||||||||||||||||||||||||||
Balance, January 1, 2013 | $ | 4,608 | $ | 1,983 | $ | 2,625 | $ | — | $ | — | $ | 4,608 | $ | 1,983 | $ | 2,625 | |||||||||||||||||
Goodwill from business combination | — | — | — | 47 | 47 | 47 | — | 47 | |||||||||||||||||||||||||
Balance, December 31, 2014 | $ | 4,608 | $ | 1,983 | $ | 2,625 | $ | 47 | $ | 47 | $ | 4,655 | $ | 1,983 | $ | 2,672 | |||||||||||||||||
_______________________ | |||||||||||||||||||||||||||||||||
(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 its operating results are 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 operating results are 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. | |||||||||||||||||||||||||||||||||
2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill for impairment annually and more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEd performed a qualitative assessment as of November 1, 2014, for its 2014 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 as well as changes in certain market conditions, including the discount rate and EBITDA multiples, while also considering the passing margin from its last quantitative assessment performed as of November 1, 2013. | |||||||||||||||||||||||||||||||||
Prior 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. | |||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||||
Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and Other long-term assets and liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2014: | |||||||||||||||||||||||||||||||||
Weighted | Estimated amortization expense | ||||||||||||||||||||||||||||||||
Average | |||||||||||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||||||||||
Years (h) | Gross | Accumulated | Net | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||||||
Unamortized Energy Contracts (a) | |||||||||||||||||||||||||||||||||
Exelon Wind (b) | 18 | $ | 224 | $ | (55 | ) | $ | 169 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | |||||||||||||||
Antelope Valley (c) | 25 | 190 | (12 | ) | 178 | 8 | 8 | 8 | 8 | 8 | |||||||||||||||||||||||
Constellation (d) | 1.5 | 1,499 | (1,451 | ) | 48 | 19 | (31 | ) | (21 | ) | 11 | 8 | |||||||||||||||||||||
CENG (e) | 1.7 | (97 | ) | 29 | (68 | ) | (20 | ) | (11 | ) | (15 | ) | (18 | ) | (15 | ) | |||||||||||||||||
Integrys (d) | 2.4 | 6 | (5 | ) | 1 | (8 | ) | 6 | 1 | 1 | — | ||||||||||||||||||||||
Customer Relationships | |||||||||||||||||||||||||||||||||
Constellation (d) | 12.4 | 214 | (58 | ) | 156 | 18 | 18 | 18 | 18 | 17 | |||||||||||||||||||||||
Integrys (d) | 10 | 48 | (1 | ) | 47 | 5 | 5 | 5 | 5 | 5 | |||||||||||||||||||||||
Trade Names | |||||||||||||||||||||||||||||||||
Constellation (d) | 10 | 243 | (79 | ) | 164 | 23 | 23 | 23 | 23 | 23 | |||||||||||||||||||||||
ComEd | |||||||||||||||||||||||||||||||||
Chicago settlement—1999 agreement (f) | 21.8 | 100 | (79 | ) | 21 | 3 | 3 | 4 | 4 | 4 | |||||||||||||||||||||||
Chicago settlement—2003 agreement (g) | 17.9 | 62 | (40 | ) | 22 | 4 | 4 | 3 | 3 | 3 | |||||||||||||||||||||||
Total intangible assets | $ | 2,489 | $ | (1,751 | ) | $ | 738 | $ | 66 | $ | 39 | $ | 40 | $ | 69 | $ | 67 | ||||||||||||||||
_________________________ | |||||||||||||||||||||||||||||||||
(a) | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | ||||||||||||||||||||||||||||||||
(b) | In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states. | ||||||||||||||||||||||||||||||||
(c) | In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc. | ||||||||||||||||||||||||||||||||
(d) | See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions. | ||||||||||||||||||||||||||||||||
(e) | See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||||||||||||||
(f) | 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. | ||||||||||||||||||||||||||||||||
(g) | 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 deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement. | ||||||||||||||||||||||||||||||||
(h) | Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement. | ||||||||||||||||||||||||||||||||
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon (a) | Generation (a) | ComEd | ||||||||||||||||||||||||||||||
2014 | $ | 179 | $ | 179 | $ | 7 | |||||||||||||||||||||||||||
2013 | 478 | 550 | 7 | ||||||||||||||||||||||||||||||
2012 | 1,150 | 1,145 | 7 | ||||||||||||||||||||||||||||||
_________________________ | |||||||||||||||||||||||||||||||||
(a) At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income | |||||||||||||||||||||||||||||||||
Acquired Intangible Assets | |||||||||||||||||||||||||||||||||
Accounting guidance for business combinations requires the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting. | |||||||||||||||||||||||||||||||||
Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Generation has acquired. The valuation of unamortized energy contracts 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 fair value 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 Exelon Wind unamortized energy contracts are amortized on a straight line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenue within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG and Integrys, 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 acquisition dates through either Purchase power and fuel expense or Operating revenues within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income. | |||||||||||||||||||||||||||||||||
Customer Relationships. The customer relationship intangible 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 fair value 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 accounting guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||||||||||||||
Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value 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. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||||||||||||||||||||
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). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. 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, 2014, and 2013, PECO had current AECs of $13 million and $19 million, respectively. PECO had no noncurrent AECs and $5 million as of December 31, 2014, and 2013, respectively. As of December 31, 2014, and 2013, Generation had current RECs of $191 million and $158 million, respectively, and $44 million of noncurrent REC's as of December 31, 2014. As of December 31, 2014, and 2013, ComEd, had current RECs of $4 million and $3 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, 2014 | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Financial Liabilities Recorded at the Carrying Amount | ||||||||||||||||||||||||||||||||||||||||||||||||
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 463 | $ | 3 | $ | 448 | $ | 12 | $ | 463 | $ | 344 | $ | 344 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 21,164 | 1,208 | 20,417 | 1,311 | 22,936 | 19,132 | 19,751 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 648 | — | — | 648 | 648 | 648 | 631 | |||||||||||||||||||||||||||||||||||||||||
SNF obligation | 1,021 | — | 833 | — | 833 | 1,021 | 790 | |||||||||||||||||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 36 | $ | — | $ | 24 | $ | 12 | $ | 36 | $ | 22 | $ | 22 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 8,266 | — | 7,511 | 1,311 | 8,822 | 7,729 | 7,648 | |||||||||||||||||||||||||||||||||||||||||
SNF obligation | 1,021 | — | 833 | — | 833 | 1,021 | 790 | |||||||||||||||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 304 | $ | — | $ | 304 | $ | — | $ | 304 | $ | 184 | $ | 184 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 5,958 | — | 6,788 | — | 6,788 | 5,675 | 6,255 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trust | 206 | — | — | 213 | 213 | 206 | 202 | |||||||||||||||||||||||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,246 | $ | — | $ | 2,537 | $ | — | $ | 2,537 | $ | 2,197 | $ | 2,358 | ||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 184 | — | — | 199 | 199 | 184 | 180 | |||||||||||||||||||||||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 123 | $ | 3 | $ | 120 | $ | — | $ | 123 | $ | 138 | $ | 138 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 1,942 | — | 2,178 | — | 2,178 | 2,011 | 2,148 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 258 | — | — | 236 | 236 | 258 | 249 | |||||||||||||||||||||||||||||||||||||||||
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1), short-term borrowings (Level 2) and third party financing (Level 3). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments. | ||||||||||||||||||||||||||||||||||||||||||||||||
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 Exelon's equity units (Level 1) are valued based on publicly traded securities issued by Exelon. | ||||||||||||||||||||||||||||||||||||||||||||||||
The fair value of Generation’s non-government-backed fixed rate project financing debt, including nuclear fuel procurement contracts, (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-backed 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 (Level 2). | ||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||
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. | |||||||||||||||||||||||||||||||||||||||||||||||
• | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
• | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
Transfers in and out of levels are recognized as of the end of the reporting period when 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. There were no transfers between Level 1 and Level 2 during the year ended December 31, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation and Exelon | ||||||||||||||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents (a) | $ | 405 | $ | — | $ | — | $ | 405 | $ | 1,119 | $ | — | $ | — | $ | 1,119 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 208 | 37 | — | 245 | 208 | 37 | — | 245 | ||||||||||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||||||||||||||
Domestic | 2,423 | 2,207 | — | 4,630 | 2,423 | 2,207 | — | 4,630 | ||||||||||||||||||||||||||||||||||||||||
Foreign | 612 | — | — | 612 | 612 | — | — | 612 | ||||||||||||||||||||||||||||||||||||||||
Equity funds subtotal | 3,035 | 2,207 | — | 5,242 | 3,035 | 2,207 | — | 5,242 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt securities | — | 2,023 | 239 | 2,262 | — | 2,023 | 239 | 2,262 | ||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 996 | — | — | 996 | 996 | — | — | 996 | ||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 95 | — | 95 | — | 95 | — | 95 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 438 | — | 438 | — | 438 | — | 438 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 511 | — | 511 | — | — | 511 | — | — | — | 511 | |||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 996 | 3,067 | 239 | 4,302 | 996 | 3,067 | 239 | 4,302 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 366 | 366 | — | — | 366 | 366 | ||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | 83 | 83 | — | — | 83 | 83 | ||||||||||||||||||||||||||||||||||||||||
Real estate | — | — | 3 | 3 | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||||||||||||||||
Other | — | 301 | — | 301 | — | 301 | — | 301 | ||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds subtotal (b) | 4,239 | 5,612 | 691 | 10,542 | 4,239 | 5,612 | 691 | 10,542 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | ||||||||||||||||||||||||||||||||||||||||||||||||
decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | 15 | — | 15 | — | 15 | — | 15 | ||||||||||||||||||||||||||||||||||||||||
Equities | 6 | 1 | — | 7 | 6 | 1 | — | 7 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 5 | 3 | — | 8 | 5 | 3 | — | 8 | ||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 89 | — | 89 | — | 89 | — | 89 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 10 | — | 10 | — | 10 | — | 10 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 3 | — | 3 | — | 3 | — | 3 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 5 | 105 | — | 110 | 5 | 105 | — | 110 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 184 | 184 | — | — | 184 | 184 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | 11 | 121 | 184 | 316 | 11 | 121 | 184 | 316 | ||||||||||||||||||||||||||||||||||||||||
decommissioning subtotal (c) | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments (d) | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | — | — | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||
Mutual funds (e) | 16 | — | — | — | — | 16 | 46 | — | — | 46 | ||||||||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 16 | — | — | 16 | 47 | — | — | 47 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 1,667 | 3,465 | 1,681 | 6,813 | 1,667 | 3,465 | 1,681 | 6,813 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 201 | 284 | 27 | 512 | 201 | 284 | 27 | 512 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | (1,982 | ) | (2,757 | ) | (557 | ) | (5,296 | ) | (1,982 | ) | (2,757 | ) | (557 | ) | (5,296 | ) | ||||||||||||||||||||||||||||||||
Commodity derivative assets subtotal | (114 | ) | 992 | 1,151 | 2,029 | (114 | ) | 992 | 1,151 | 2,029 | ||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | ||||||||||||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | 8 | — | 8 | — | 31 | — | 31 | ||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | 12 | — | 12 | — | 13 | — | 13 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 18 | 9 | — | 27 | 18 | 9 | — | 27 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (17 | ) | (12 | ) | — | (29 | ) | (17 | ) | (31 | ) | — | (48 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 1 | 17 | — | 18 | 1 | 22 | — | 23 | ||||||||||||||||||||||||||||||||||||||||
assets subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Other investments | — | — | 3 | 3 | 2 | — | 3 | 5 | ||||||||||||||||||||||||||||||||||||||||
Total assets | 4,558 | 6,742 | 2,029 | 13,329 | 5,305 | 6,747 | 2,029 | 14,081 | ||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (2,241 | ) | (3,458 | ) | (788 | ) | (6,487 | ) | (2,241 | ) | (3,458 | ) | (995 | ) | (6,694 | ) | ||||||||||||||||||||||||||||||||
Proprietary trading | (195 | ) | (295 | ) | (42 | ) | (532 | ) | (195 | ) | (295 | ) | (42 | ) | (532 | ) | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | 2,416 | 3,557 | 729 | 6,702 | 2,416 | 3,557 | 729 | 6,702 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities subtotal | (20 | ) | (196 | ) | (101 | ) | (317 | ) | (20 | ) | (196 | ) | (308 | ) | (524 | ) | ||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | (12 | ) | — | (12 | ) | — | (41 | ) | — | (41 | ) | ||||||||||||||||||||||||||||||||||||
Economic hedges | — | (2 | ) | — | (2 | ) | — | (103 | ) | — | (103 | ) | ||||||||||||||||||||||||||||||||||||
Proprietary trading | (14 | ) | (9 | ) | — | (23 | ) | (14 | ) | (9 | ) | — | (23 | ) | ||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 25 | 10 | — | 35 | 25 | 29 | — | 54 | ||||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 11 | (13 | ) | — | (2 | ) | 11 | (124 | ) | — | (113 | ) | ||||||||||||||||||||||||||||||||||||
liabilities subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (31 | ) | — | (31 | ) | — | (107 | ) | — | (107 | ) | ||||||||||||||||||||||||||||||||||||
Total liabilities | (9 | ) | (240 | ) | (101 | ) | (350 | ) | (9 | ) | (427 | ) | (308 | ) | (744 | ) | ||||||||||||||||||||||||||||||||
Total net assets | $ | 4,549 | $ | 6,502 | $ | 1,928 | $ | 12,979 | $ | 5,296 | $ | 6,320 | $ | 1,721 | $ | 13,337 | ||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents (a) | $ | 1,006 | $ | — | $ | — | $ | 1,006 | $ | 1,230 | $ | — | $ | — | $ | 1,230 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | — | — | 459 | 459 | — | — | 459 | ||||||||||||||||||||||||||||||||||||||||
Equities | ||||||||||||||||||||||||||||||||||||||||||||||||
Domestic | 1,642 | 2,271 | — | 3,913 | 1,642 | 2,271 | — | 3,913 | ||||||||||||||||||||||||||||||||||||||||
Foreign | 249 | — | — | 249 | 249 | — | — | 249 | ||||||||||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | — | 4,162 | 1,891 | 2,271 | — | 4,162 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt securities | — | 1,753 | 31 | 1,784 | — | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 882 | — | — | 882 | 882 | — | — | 882 | ||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 87 | — | 87 | — | 87 | — | 87 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 294 | — | 294 | — | 294 | — | 294 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 75 | — | 75 | — | 75 | — | 75 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 314 | 314 | — | — | 314 | 314 | ||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | 5 | 5 | — | — | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 14 | — | 14 | — | 14 | — | 14 | ||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds subtotal (b) | 3,232 | 4,494 | 350 | 8,076 | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | ||||||||||||||||||||||||||||||||||||||||||||||||
decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | 26 | — | 26 | — | 26 | — | 26 | ||||||||||||||||||||||||||||||||||||||||
Equities | 16 | — | — | 16 | 16 | — | — | 16 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 45 | 4 | — | 49 | 45 | 4 | — | 49 | ||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 227 | — | 227 | — | 227 | — | 227 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 20 | — | 20 | — | 20 | — | 20 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | — | 296 | 45 | 251 | — | 296 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 112 | 112 | — | — | 112 | 112 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 1 | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | 61 | 278 | 112 | 451 | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||||||||||||
decommissioning subtotal (c) | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments (d) | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||
Mutual funds (e) | 13 | — | — | 13 | 54 | — | — | 54 | ||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 13 | — | — | 13 | 56 | — | — | 56 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative assets | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | (863 | ) | (3,131 | ) | (430 | ) | (4,424 | ) | (863 | ) | (3,131 | ) | (430 | ) | (4,424 | ) | ||||||||||||||||||||||||||||||||
Commodity derivative assets subtotal | (46 | ) | 766 | 577 | 1,297 | (46 | ) | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 30 | 32 | — | 62 | 30 | 39 | — | 69 | ||||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (30 | ) | (2 | ) | — | (32 | ) | (30 | ) | (2 | ) | — | (32 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | 30 | — | 30 | — | 37 | — | 37 | ||||||||||||||||||||||||||||||||||||||||
assets subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Other investments | — | — | 15 | 15 | — | — | 15 | 15 | ||||||||||||||||||||||||||||||||||||||||
Total assets | 4,266 | 5,568 | 1,054 | 10,888 | 4,533 | 5,575 | 1,054 | 11,162 | ||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (540 | ) | (1,890 | ) | (397 | ) | (2,827 | ) | (540 | ) | (1,890 | ) | (590 | ) | (3,020 | ) | ||||||||||||||||||||||||||||||||
Proprietary trading | (328 | ) | (1,256 | ) | (119 | ) | (1,703 | ) | (328 | ) | (1,256 | ) | (119 | ) | (1,703 | ) | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | 869 | 3,007 | 404 | 4,280 | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities subtotal | 1 | (139 | ) | (112 | ) | (250 | ) | 1 | (139 | ) | (305 | ) | (443 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | (31 | ) | (13 | ) | — | (44 | ) | (31 | ) | (17 | ) | — | (48 | ) | ||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | — | 32 | 31 | 1 | — | 32 | ||||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | (12 | ) | — | (12 | ) | — | (16 | ) | — | (16 | ) | ||||||||||||||||||||||||||||||||||||
liabilities subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (29 | ) | — | (29 | ) | — | (114 | ) | — | (114 | ) | ||||||||||||||||||||||||||||||||||||
Total liabilities | 1 | (180 | ) | (112 | ) | (291 | ) | 1 | (269 | ) | (305 | ) | (573 | ) | ||||||||||||||||||||||||||||||||||
Total net assets | $ | 4,267 | $ | 5,388 | $ | 942 | $ | 10,597 | $ | 4,534 | $ | 5,306 | $ | 749 | $ | 10,589 | ||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | Excludes net liabilities of $5 million at both December 31, 2014 and 2013. 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 $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation. | |||||||||||||||||||||||||||||||||||||||||||||||
(e) | The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||
(f) | Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014. Collateral posted (received) to/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. | |||||||||||||||||||||||||||||||||||||||||||||||
ComEd, PECO and BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
The following tables present assets and liabilities measured and recorded at fair value on the Utilities' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 25 | $ | — | $ | — | $ | 25 | $ | 12 | $ | — | $ | — | $ | 12 | $ | 103 | $ | — | $ | — | $ | 103 | ||||||||||||||||||||||||
Rabbi trust investments in Mutual funds (a) | — | — | — | — | 9 | — | — | 9 | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||||||
Total assets | 25 | — | — | 25 | 21 | — | — | 21 | 108 | — | — | 108 | ||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation | — | (8 | ) | — | (8 | ) | — | (15 | ) | — | (15 | ) | — | (5 | ) | — | (5 | ) | ||||||||||||||||||||||||||||||
obligation | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | — | — | (207 | ) | (207 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
liabilities (b) | ||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (207 | ) | (215 | ) | — | (15 | ) | — | (15 | ) | — | (5 | ) | — | (5 | ) | |||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 25 | $ | (8 | ) | $ | (207 | ) | $ | (190 | ) | $ | 21 | $ | (15 | ) | $ | — | $ | 6 | $ | 108 | $ | (5 | ) | $ | — | $ | 103 | |||||||||||||||||||
ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | — | $ | — | $ | — | $ | — | $ | 175 | $ | — | $ | — | $ | 175 | $ | 31 | $ | — | $ | — | $ | 31 | ||||||||||||||||||||||||
Rabbi trust investments in Mutual funds (a) | 5 | — | — | 5 | 9 | — | — | 9 | 6 | — | — | 6 | ||||||||||||||||||||||||||||||||||||
Total assets | 5 | — | — | 5 | 184 | — | — | 184 | 37 | — | — | 37 | ||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation | — | (8 | ) | — | (8 | ) | — | (17 | ) | — | (17 | ) | — | (6 | ) | — | (6 | ) | ||||||||||||||||||||||||||||||
obligation | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | — | — | (193 | ) | (193 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
liabilities (b) | ||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (193 | ) | (201 | ) | — | (17 | ) | — | (17 | ) | — | (6 | ) | — | (6 | ) | |||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | (8 | ) | $ | (193 | ) | $ | (196 | ) | $ | 184 | $ | (17 | ) | $ | — | $ | 167 | $ | 37 | $ | (6 | ) | $ | — | $ | 31 | |||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||||||||||||||||||||
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||||||||||
For The Year Ended December 31, 2014 | Nuclear | Pledged Assets | Mark-to-Market | Other | Total Generation | Other- ComEd (b) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||||||||||||||||||
Decommissioning | for Zion Station | Derivatives | Investments | |||||||||||||||||||||||||||||||||||||||||||||
Trust Fund | Decommissioning | |||||||||||||||||||||||||||||||||||||||||||||||
Investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | $ | (193 | ) | $ | — | $ | 749 | |||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | 6 | — | 526 | (a) | — | 532 | — | — | 532 | |||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 14 | — | — | — | 14 | — | (14 | ) | — | |||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | 2 | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets/liabilities | — | — | — | — | — | (14 | ) | 14 | — | |||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | 198 | — | 198 | — | — | 198 | ||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 400 | 120 | 76 | (c) | 2 | 598 | — | — | 598 | |||||||||||||||||||||||||||||||||||||||
Sales | (15 | ) | (50 | ) | (7 | ) | (8 | ) | (80 | ) | — | — | (80 | ) | ||||||||||||||||||||||||||||||||||
Settlements | (64 | ) | — | — | — | (64 | ) | — | — | (64 | ) | |||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | (7 | ) | — | (7 | ) | — | — | (7 | ) | |||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (201 | ) | (6 | ) | (207 | ) | — | — | (207 | ) | ||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2014 | $ | 691 | $ | 184 | $ | 1,050 | $ | 3 | $ | 1,928 | $ | (207 | ) | $ | — | $ | 1,721 | |||||||||||||||||||||||||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2014 | $ | 4 | $ | — | $ | 640 | $ | — | $ | 644 | $ | — | $ | — | $ | 644 | ||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||||||||||
For The Year Ended December 31, 2013 | Nuclear | Pledged Assets | Mark-to-Market | Other | Total Generation | Other- ComEd (b)(f) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||||||||||||||||||
Decommissioning | for Zion Station | Derivatives (d) | Investments | |||||||||||||||||||||||||||||||||||||||||||||
Trust Fund | Decommissioning | |||||||||||||||||||||||||||||||||||||||||||||||
Investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | $ | (293 | ) | $ | — | $ | 656 | |||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | — | |||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | 2 | — | (51 | ) | (a) | — | (49 | ) | — | 7 | (42 | ) | ||||||||||||||||||||||||||||||||||||
Included in other | — | — | (219 | ) | 2 | (217 | ) | — | 219 | 2 | ||||||||||||||||||||||||||||||||||||||
comprehensive income | ||||||||||||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 8 | — | — | — | 8 | — | (8 | ) | — | |||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets/liabilities | — | — | — | — | — | 100 | (218 | ) | (118 | ) | ||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | 7 | — | 7 | — | — | 7 | ||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | — | — | 297 | ||||||||||||||||||||||||||||||||||||||||
Sales | (28 | ) | (39 | ) | (11 | ) | (8 | ) | (86 | ) | — | — | (86 | ) | ||||||||||||||||||||||||||||||||||
Settlements | (18 | ) | — | — | — | (18 | ) | — | — | (18 | ) | |||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | 86 | (e) | 1 | 87 | — | — | 87 | |||||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (35 | ) | (1 | ) | (36 | ) | — | — | (36 | ) | ||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | $ | (193 | ) | $ | — | $ | 749 | |||||||||||||||||||||||||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | — | $ | 156 | $ | — | $ | 157 | $ | — | $ | — | $ | 168 | ||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | Includes $11 million of decreases in fair value and realized gains 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(e) | Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | |||||||||||||||||||||||||||||||||||||||||||||||
(f) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
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, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
Operating | Purchased | Other, net (a) | Operating | Purchased | Other, net (a) | |||||||||||||||||||||||||||||||||||||||||||
Revenues | Power and | Revenues | Power and | |||||||||||||||||||||||||||||||||||||||||||||
Fuel | Fuel | |||||||||||||||||||||||||||||||||||||||||||||||
Total gains (losses) included in net income for the year ended December 31, 2014 | $ | 614 | $ | (88 | ) | $ | 6 | $ | 614 | $ | (88 | ) | $ | 6 | ||||||||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014 | $ | 663 | $ | (23 | ) | $ | 4 | $ | 663 | $ | (23 | ) | $ | 4 | ||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
Operating | Purchased | Other, net (a) | Operating | Purchased | Other, net (a) | |||||||||||||||||||||||||||||||||||||||||||
Revenues | Power and | Revenues | Power and | |||||||||||||||||||||||||||||||||||||||||||||
Fuel | Fuel | |||||||||||||||||||||||||||||||||||||||||||||||
Total gains (losses) included in net income for the year ended December 31, 2013 | $ | (158 | ) | $ | 107 | $ | 2 | $ | (152 | ) | $ | 108 | $ | 2 | ||||||||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2013 | $ | 30 | $ | 126 | $ | 1 | $ | 40 | $ | 127 | $ | 1 | ||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||||||||||||||||||||||||||||||
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 and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG'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, which are included in Domestic or Foreign equities, 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, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3. | ||||||||||||||||||||||||||||||||||||||||||||||||
Equity, balanced 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, Generation, and CENG 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. | ||||||||||||||||||||||||||||||||||||||||||||||||
Private equity investments include investments in operating companies that are not publicly traded on a stock exchange. 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. | ||||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $290 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds. | ||||||||||||||||||||||||||||||||||||||||||||||||
See Note 15—Asset Retirement Obligations for further discussion on the NDT fund investments. | ||||||||||||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||||||||||
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 other attributes. 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 more 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 $2.75 and $0.34 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 31,2014 | Valuation | Unobservable | Range | ||||||||||||||||||||||||||||||||||||||||||||
Technique | Input | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Economic hedges (Generation) (a)(c) | $ | 893 | Discounted | Forward power price | $15 | - | $120 | (d) | ||||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Forward gas price | $1.52 | - | $14.02 | (d) | ||||||||||||||||||||||||||||||||||||||||||||
Option Model | Volatility percentage | 8% | - | 257% | ||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Proprietary trading (Generation) (a)(c) | $ | (15 | ) | Discounted | Forward power price | $15 | - | $117 | (d) | |||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives | $ | (207 | ) | Discounted | Forward heat rate (b) | 8x | - | 9x | ||||||||||||||||||||||||||||||||||||||||
(ComEd) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Marketability reserve | 3.50% | - | 8% | |||||||||||||||||||||||||||||||||||||||||||||
Renewable factor | 86% | - | 126% | |||||||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | The fair values do not include cash collateral held on level three positions of $172 million as of December 31, 2014. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | 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 $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading. | |||||||||||||||||||||||||||||||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 | Valuation | Unobservable | Range | ||||||||||||||||||||||||||||||||||||||||||||
Technique | Input | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Economic hedges (Generation) (a)(c) | $ | 488 | Discounted | Forward power price | $8 | - | $176 | (d) | ||||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Forward gas price | $2.98 | - | $16.63 | (d) | ||||||||||||||||||||||||||||||||||||||||||||
Option Model | Volatility percentage | 15% | - | 142% | ||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives— | $ | 3 | Discounted | Forward power price | $10 | - | $176 | (d) | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading (Generation) (a)(c) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives | $ | (193 | ) | Discounted | Forward heat rate (b) | 8x | - | 9x | ||||||||||||||||||||||||||||||||||||||||
(ComEd) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Marketability reserve | 3.50% | - | 8% | |||||||||||||||||||||||||||||||||||||||||||||
Renewable factor | 84% | - | 128% | |||||||||||||||||||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | 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 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 price 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. |
Derivative_Financial_Instrumen
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||
Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||||||||||||
The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. | ||||||||||||||||||||||||||||||||||||||||
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, 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 Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivative economic hedges related to 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. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas 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, 2014, the percentage of expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. 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. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for more detail regarding divestitures. | ||||||||||||||||||||||||||||||||||||||||
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 for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 Order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reductions was approved in March 2014. 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 2014 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 2014 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 10,571 GWh, 8,762 GWh and 12,958 GWh for the years ended December 31, 2014, 2013 and 2012, 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, 2014, Exelon and Generation had $1,450 million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 million of notional amounts of floating-to-fixed hedges outstanding, respectively. 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 $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. 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 exchange hedges as of December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||||
Description | Derivatives | Economic | Proprietary | Collateral | Subtotal | Derivatives | Economic | Collateral | Subtotal | Total | ||||||||||||||||||||||||||||||
Designated as | Hedges | Trading (a) | and Netting (b) | Designated as | Hedges | and Netting (b) | ||||||||||||||||||||||||||||||||||
Hedging | Hedging | |||||||||||||||||||||||||||||||||||||||
Instruments | Instruments | |||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | $ | 7 | $ | 7 | $ | 20 | $ | (22 | ) | $ | 12 | $ | 3 | $ | — | $ | — | $ | 3 | $ | 15 | |||||||||||||||||||
assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | 1 | 5 | 7 | (7 | ) | 6 | 20 | 1 | (19 | ) | 2 | 8 | ||||||||||||||||||||||||||||
assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 8 | 12 | 27 | (29 | ) | 18 | 23 | 1 | (19 | ) | 5 | 23 | ||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (8 | ) | (2 | ) | (14 | ) | 25 | 1 | — | — | — | — | 1 | |||||||||||||||||||||||||||
liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (4 | ) | — | (9 | ) | 10 | (3 | ) | (29 | ) | (101 | ) | 19 | (111 | ) | (114 | ) | |||||||||||||||||||||||
liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (12 | ) | (2 | ) | (23 | ) | 35 | (2 | ) | (29 | ) | (101 | ) | 19 | (111 | ) | (113 | ) | ||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | (4 | ) | $ | 10 | $ | 4 | $ | 6 | $ | 16 | $ | (6 | ) | $ | (100 | ) | $ | — | $ | (106 | ) | $ | (90 | ) | |||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||||||||||||||||
(b) | 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 and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||||
Description | Derivatives | Economic | Proprietary | Collateral | Subtotal | Derivatives | Total | |||||||||||||||||||||||||||||||||
Designated as | Hedges | Trading (a) | and Netting (b) | Designated as | ||||||||||||||||||||||||||||||||||||
Hedging | Hedging | |||||||||||||||||||||||||||||||||||||||
Instruments | Instruments | |||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | $ | — | $ | 3 | $ | 15 | $ | (19 | ) | $ | (1 | ) | $ | — | $ | (1 | ) | |||||||||||||||||||||||
assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | 26 | 3 | 15 | (13 | ) | 31 | 7 | 38 | ||||||||||||||||||||||||||||||||
assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 26 | 6 | 30 | (32 | ) | 30 | 7 | 37 | ||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (1 | ) | (1 | ) | (18 | ) | 19 | (1 | ) | — | (1 | ) | ||||||||||||||||||||||||||||
liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (10 | ) | (1 | ) | (13 | ) | 13 | (11 | ) | (4 | ) | (15 | ) | |||||||||||||||||||||||||||
liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (11 | ) | (2 | ) | (31 | ) | 32 | (12 | ) | (4 | ) | (16 | ) | |||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 15 | $ | 4 | $ | (1 | ) | $ | — | $ | 18 | $ | 3 | $ | 21 | |||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||||||||||||||||
(b) | 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: | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||
Income Statement Location | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||||||
Generation | Interest expense (a) | $ | (16 | ) | $ | (15 | ) | $ | (6 | ) | $ | 2 | $ | (6 | ) | $ | — | |||||||||||||||||||||||
Exelon | Interest expense | $ | 3 | $ | (24 | ) | $ | (9 | ) | $ | 15 | $ | (3 | ) | $ | (1 | ) | |||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively. | |||||||||||||||||||||||||||||||||||||||
During 2014, Exelon entered into $100 million and $75 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2019 and 2020, respectively. At December 31, 2014, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. At December 31, 2013, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with a derivative asset of $26 million and $23 million, respectively. During the years ended December 31, 2014 and 2013, the impact on the results of operations, as a result of the ineffectiveness from fair value hedges, was a $18 million gain and $2 million gain, respectively. | ||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley project financings, 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 September 30, 2014. The interest rate swap was designated as a cash flow hedge, and as a result, unrealized losses of approximately $21 million have been recorded to Accumulated OCI, net on Exelon's and Generation’s Consolidated Balance Sheets. During the third quarter of 2014, the interest rate swap was terminated consistent with the agreements. The unrealized loss of $21 million will be amortized into Interest expense on Exelon's and Generation’s Consolidated Statements of Operations and Comprehensive Income over the term of the DOE guaranteed loan. | ||||||||||||||||||||||||||||||||||||||||
During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a total notional amount of $26 million as of December 31, 2014 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. At December 31, 2014, the subsidiary had a $3 million derivative liability related to these swaps. | ||||||||||||||||||||||||||||||||||||||||
During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swap has a notional amount of $26 million as of December 31, 2014, and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2014, the derivative asset related to the swap was immaterial. | ||||||||||||||||||||||||||||||||||||||||
During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $213 million as of December 31, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At December 31, 2014, the subsidiary had a $2 million derivative liability related to the swaps. | ||||||||||||||||||||||||||||||||||||||||
During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $505 million as of December 31, 2014 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2014, the subsidiary had a $8 million derivative liability related to the swap. | ||||||||||||||||||||||||||||||||||||||||
During 2014, Exelon entered into $400 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated refinance of existing debt. The swaps are designated as cash flow hedges. At December 31, 2014, Exelon had a $28 million derivative liability related to the swaps. | ||||||||||||||||||||||||||||||||||||||||
During the years ended December 31, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. | ||||||||||||||||||||||||||||||||||||||||
Economic Hedges. During 2014, Exelon entered into $1,900 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated future debt issuance related to the proposed PHI acquisition. At December 31, 2014, Exelon had a $100 million derivative liability related to the swaps. | ||||||||||||||||||||||||||||||||||||||||
During the fourth quarter, fixed-to-floating interest rate swaps, which were marked-to-market, acquired as part of the Constellation merger, expired for Exelon and Generation. The notional amounts of the swaps was $150 million. | ||||||||||||||||||||||||||||||||||||||||
At December 31, 2014, Generation had $126 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $349 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. | ||||||||||||||||||||||||||||||||||||||||
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 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. 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 including initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2014 and 2013, $8 million and $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, 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, 2014: | ||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||
Derivatives | Economic | Proprietary | Collateral | Subtotal (b) | Economic | Total | ||||||||||||||||||||||||||||||||||
Hedges | Trading | and Netting (a) | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||||||
Mark-to-market | $ | 4,992 | $ | 456 | $ | (4,184 | ) | $ | 1,264 | $ | — | $ | 1,264 | |||||||||||||||||||||||||||
derivative assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | 1,821 | 56 | (1,112 | ) | 765 | — | 765 | |||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 6,813 | 512 | (5,296 | ) | 2,029 | — | 2,029 | |||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (4,947 | ) | (468 | ) | 5,200 | (215 | ) | (20 | ) | (235 | ) | |||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (1,540 | ) | (64 | ) | 1,502 | (102 | ) | (187 | ) | (289 | ) | |||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (6,487 | ) | (532 | ) | 6,702 | (317 | ) | (207 | ) | (524 | ) | |||||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 326 | $ | (20 | ) | $ | 1,406 | $ | 1,712 | $ | (207 | ) | $ | 1,505 | ||||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(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 $(416) million and $(171) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(599) million and $(220) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014. | |||||||||||||||||||||||||||||||||||||||
(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, 2013: | ||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||
Derivatives | Economic | Proprietary | Collateral | Subtotal (b) | Economic | Total | ||||||||||||||||||||||||||||||||||
Hedges | Trading | and | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||||||
Netting (a) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | $ | 2,616 | $ | 1,476 | $ | (3,364 | ) | $ | 728 | $ | — | $ | 728 | |||||||||||||||||||||||||||
derivative assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | 1,344 | 285 | (1,060 | ) | 569 | — | 569 | |||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 3,960 | 1,761 | (4,424 | ) | 1,297 | — | 1,297 | |||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (2,023 | ) | (1,410 | ) | 3,292 | (141 | ) | (17 | ) | (158 | ) | |||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (804 | ) | (293 | ) | 988 | (109 | ) | (176 | ) | (285 | ) | |||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (2,827 | ) | (1,703 | ) | 4,280 | (250 | ) | (193 | ) | (443 | ) | |||||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 1,133 | $ | 58 | $ | (144 | ) | $ | 1,047 | $ | (193 | ) | $ | 854 | ||||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(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. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. 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. | |||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges (Exelon, Generation and ComEd). As discussed previously, effective prior to the Constellation merger, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably probable, 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 $2 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. See Note 13—Debt and Credit Agreements for information about reclassifications from Accumulated OCI on interest rate swap activity that occurred after December 31, 2014. | ||||||||||||||||||||||||||||||||||||||||
The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2014 and 2013, 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. | ||||||||||||||||||||||||||||||||||||||||
Income Statement | Total Cash Flow Hedge OCI Activity, | |||||||||||||||||||||||||||||||||||||||
Location | Net of Income Tax | |||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||
Energy-Related | Total Cash Flow | |||||||||||||||||||||||||||||||||||||||
Hedges | Hedges | |||||||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at January 1, 2013 | $ | 532 | (a)(d) | $ | 368 | |||||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | — | 29 | (e) | |||||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net | Operating Revenues | (413 | ) | (c)(b) | (277 | ) | ||||||||||||||||||||||||||||||||||
income | ||||||||||||||||||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | — | — | |||||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2013 | 119 | (d) | 120 | |||||||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | — | (31 | ) | (e) | ||||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | (117 | ) | (b) | (117 | ) | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2014 | $ | 2 | (d) | $ | (28 | ) | ||||||||||||||||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Includes $133 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. | |||||||||||||||||||||||||||||||||||||||
(b) | Amount is net of related income tax expense of $78 million and $270 million for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
(c) | Includes $133 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 year ended December 31, 2013. | |||||||||||||||||||||||||||||||||||||||
(d) | Excludes $20 million and $5 million,of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
(e) | Includes $15 million and $15 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 years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
During the years ended December 31, 2014, 2013, and 2012, 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 $195 million, $683 million and $1,368 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 for the year ended December 31, 2012. | ||||||||||||||||||||||||||||||||||||||||
The effect of Exelon’s former energy-related cash flow hedge activity impact on pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $464 million and $747 million pre-tax gain for the years ended December 31, 2014, 2013 and 2012, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million for the year ended December 31, 2012. 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 Constellation 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 ("treasury") 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. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed PHI acquisition. For the years ended December 31, 2014, 2013 and 2012, 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, or interest 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 | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2014 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | (413 | ) | $ | (194 | ) | $ | — | $ | (607 | ) | $ | — | $ | — | $ | (607 | ) | ||||||||||||||||||||||
Reclassification to realized at settlement of | 231 | (223 | ) | — | 8 | — | — | 8 | ||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains (losses) | (182 | ) | (417 | ) | — | (599 | ) | — | — | (599 | ) | |||||||||||||||||||||||||||||
Change in fair value of treasury positions | 10 | — | (2 | ) | 8 | — | (100 | ) | (92 | ) | ||||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (2 | ) | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | 8 | — | (2 | ) | 6 | — | (100 | ) | (94 | ) | ||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | (174 | ) | $ | (417 | ) | $ | (2 | ) | $ | (593 | ) | $ | — | $ | (100 | ) | $ | (693 | ) | ||||||||||||||||||||
Generation | Intercompany | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2013 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | 286 | $ | 180 | $ | — | $ | 466 | $ | (6 | ) | $ | — | $ | 460 | |||||||||||||||||||||||||
Reclassification to realized at settlement of | (64 | ) | 104 | — | 40 | 13 | — | 53 | ||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains | 222 | 284 | — | 506 | 7 | — | 513 | |||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | (1 | ) | — | (4 | ) | (5 | ) | — | — | (5 | ) | |||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (1 | ) | — | — | (1 | ) | — | — | (1 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | (2 | ) | — | (4 | ) | (6 | ) | — | — | (6 | ) | |||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | 220 | $ | 284 | $ | (4 | ) | $ | 500 | $ | 7 | $ | — | $ | 507 | |||||||||||||||||||||||||
Generation | Intercompany | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2012 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | (362 | ) | $ | 215 | $ | — | $ | (147 | ) | $ | (94 | ) | $ | — | $ | (241 | ) | ||||||||||||||||||||||
Reclassification to realized at settlement of | 432 | 238 | — | 670 | 101 | — | 771 | |||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains | 70 | 453 | — | 523 | 7 | — | 530 | |||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | — | — | 6 | 6 | — | — | 6 | |||||||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (3 | ) | — | — | (3 | ) | — | — | (3 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | (3 | ) | — | 6 | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | 67 | $ | 453 | $ | 6 | $ | 526 | $ | 7 | $ | — | $ | 533 | ||||||||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Prior to the Constellation merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation. | |||||||||||||||||||||||||||||||||||||||
Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2014, 2013, and 2012 Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s 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. | ||||||||||||||||||||||||||||||||||||||||
Location on Income | For the Years Ended | |||||||||||||||||||||||||||||||||||||||
Statement | December 31, | |||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | Operating Revenues | $ | (1 | ) | $ | (22 | ) | $ | (13 | ) | ||||||||||||||||||||||||||||||
Reclassification to realized at settlement of commodity positions | Operating Revenues | (29 | ) | (15 | ) | 108 | ||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains (losses) | Operating Revenues | (30 | ) | (37 | ) | 95 | ||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | Operating Revenues | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||||
Reclassification to realized at settlement of treasury positions | Operating Revenues | 3 | (3 | ) | — | |||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains (losses) | Operating Revenues | 4 | (2 | ) | 1 | |||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | Operating Revenues | $ | (26 | ) | $ | (39 | ) | $ | 96 | |||||||||||||||||||||||||||||||
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, 2014. 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 exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and 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 exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively. | ||||||||||||||||||||||||||||||||||||||||
Rating as of December 31, 2014 | Total | Credit | Net | Number of | Net Exposure of | |||||||||||||||||||||||||||||||||||
Exposure | Collateral (a) | Exposure | Counterparties | Counterparties | ||||||||||||||||||||||||||||||||||||
Before Credit | Greater than 10% | Greater than 10% | ||||||||||||||||||||||||||||||||||||||
Collateral | of Net Exposure | of Net Exposure | ||||||||||||||||||||||||||||||||||||||
Investment grade | $ | 1,629 | $ | 62 | $ | 1,567 | 1 | $ | 452 | |||||||||||||||||||||||||||||||
Non-investment grade | 49 | 19 | 30 | — | — | |||||||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated—investment grade | 479 | — | 479 | — | — | |||||||||||||||||||||||||||||||||||
Internally rated—non-investment | 60 | 4 | 56 | — | — | |||||||||||||||||||||||||||||||||||
grade | ||||||||||||||||||||||||||||||||||||||||
Total | $ | 2,217 | $ | 85 | $ | 2,132 | 1 | $ | 452 | |||||||||||||||||||||||||||||||
Net Credit Exposure by Type of Counterparty | 31-Dec-14 | |||||||||||||||||||||||||||||||||||||||
Financial institutions | $ | 295 | ||||||||||||||||||||||||||||||||||||||
Investor-owned utilities, marketers, power producers | 958 | |||||||||||||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 862 | |||||||||||||||||||||||||||||||||||||||
Other | 17 | |||||||||||||||||||||||||||||||||||||||
Total | $ | 2,132 | ||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 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, 2014, ComEd’s net 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, 2014, 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, 2014, PECO had credit exposure of $8 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, 2014, 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, 2014, BGE had credit exposure of $8 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 | 2014 | 2013 | ||||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | $ | (1,433 | ) | $ | (1,056 | ) | ||||||||||||||||||||||||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting | 1,140 | 846 | ||||||||||||||||||||||||||||||||||||||
Arrangements (b) | ||||||||||||||||||||||||||||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature (c) | $ | (293 | ) | $ | (210 | ) | ||||||||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. | |||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||
(c) | 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 $1,497 million and letters of credit posted of $672 million, and cash collateral held of $77 million and letters of credit held of $24 million as of December 31, 2014 for counterparties with derivative positions. Generation had cash collateral posted of $72 million and letters of credit posted of $364 million and cash collateral held of $206 million and letters of credit held of $34 million at December 31, 2013 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $2.4 billion and $2.0 billion as of December 31, 2014 and 2013, respectively. 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, 2014, Generation’s and Exelon’s swaps were in a liability position, with a fair value of $16 million and $90 million, respectively. | ||||||||||||||||||||||||||||||||||||||||
See Note 24 — Segment Information for further 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, 2014, ComEd held approximately $2 million 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, 2014, 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 3 — Regulatory Matters 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, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2014, PECO could have been required to post approximately $36 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, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2014, BGE could have been required to post approximately $79 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, 2014 | ||||||||||||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||||||||||
Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE) | 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, 2014 and 2013: | ||||||||||||||||||||||
Maximum | Outstanding | Average Interest Rate on | ||||||||||||||||||||
Program Size at | Commercial | Commercial Paper Borrowings for | ||||||||||||||||||||
December 31, | Paper at | the Year Ended December 31, | ||||||||||||||||||||
December 31, | ||||||||||||||||||||||
Commercial Paper Issuer | 2014 (a)(b) | 2013 (a)(b) | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Exelon Corporate | $ | 500 | $ | 500 | $ | — | $ | — | — | % | 0.27 | % | ||||||||||
Generation | 5,600 | 5,600 | — | — | 0.32 | % | 0.32 | % | ||||||||||||||
ComEd | 1,000 | 1,000 | 304 | 184 | 0.33 | % | 0.4 | % | ||||||||||||||
PECO | 600 | 600 | — | — | n.a. | n.a. | ||||||||||||||||
BGE | 600 | 600 | 120 | 135 | 0.29 | % | 0.31 | % | ||||||||||||||
Total | $ | 8,300 | $ | 8,300 | $ | 424 | $ | 319 | ||||||||||||||
_____________________ | ||||||||||||||||||||||
(a) | Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||||||
(b) | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||||||||||||||||||
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, 2014, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements: | ||||||||||||||||||||||
Available Capacity at December 31, 2014 | ||||||||||||||||||||||
Borrower | Aggregate Bank | Facility Draws | Outstanding | Actual | To Support | |||||||||||||||||
Commitment (a) | Letters of Credit(c) | Additional | ||||||||||||||||||||
Commercial | ||||||||||||||||||||||
Paper (b) | ||||||||||||||||||||||
Exelon Corporate | $ | 500 | $ | — | $ | 6 | $ | 494 | $ | 494 | ||||||||||||
Generation | 5,800 | — | 1,181 | 4,619 | 4,504 | |||||||||||||||||
ComEd | 1,000 | — | 2 | 998 | 694 | |||||||||||||||||
PECO | 600 | — | 1 | 599 | 599 | |||||||||||||||||
BGE | 600 | — | — | 600 | 480 | |||||||||||||||||
Total | $ | 8,500 | $ | — | $ | 1,190 | $ | 7,310 | $ | 6,771 | ||||||||||||
_______________________ | ||||||||||||||||||||||
(a) | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||||||||||||||||||
(b) | Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program. | |||||||||||||||||||||
(c) | Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind. | |||||||||||||||||||||
As of December 31, 2014, there were no borrowings under the Registrants’ credit facilities. | ||||||||||||||||||||||
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2014, 2013 and 2012. PECO did not have any short-term borrowings during 2014, 2013 or 2012. | ||||||||||||||||||||||
Exelon | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 571 | $ | 254 | $ | 199 | ||||||||||||||||
Maximum borrowings outstanding | 1,164 | 682 | 505 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.37 | % | 0.48 | % | ||||||||||||||||
Average interest rates, at December 31 | 0.53 | % | 0.35 | % | n.a. | |||||||||||||||||
Generation | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 93 | $ | 42 | $ | 4 | ||||||||||||||||
Maximum borrowings outstanding | 552 | 291 | 165 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.32 | % | 0.45 | % | ||||||||||||||||
Average interest rates, at December 31 | n.a. | n.a. | n.a. | |||||||||||||||||||
ComEd | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 415 | $ | 203 | $ | 110 | ||||||||||||||||
Maximum borrowings outstanding | 597 | 446 | 366 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.33 | % | 0.4 | % | 0.5 | % | ||||||||||||||||
Average interest rates, at December 31 | 0.5 | % | 0.37 | % | n.a. | |||||||||||||||||
BGE | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 64 | $ | 35 | $ | 6 | ||||||||||||||||
Maximum borrowings outstanding | 180 | 135 | 76 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.29 | % | 0.31 | % | 0.43 | % | ||||||||||||||||
Average interest rates, computed at December 31 | 0.61 | % | 0.31 | % | n.a. | |||||||||||||||||
Credit Facilities | ||||||||||||||||||||||
On March 28, 2014, ComEd extended for an additional year the expiration date of 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, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any 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 May 30, 2014, each of Exelon Corporate, Generation, PECO and BGE extended the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, into May 2019, with the exception of a cumulative amount of $315 million in commitments, which expire in April 2018. Costs incurred to extend these facilities were not material. | ||||||||||||||||||||||
On October 24, 2014, a $100 million bilateral CENG credit facility was amended and extended for an additional year. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation's commercial paper program. | ||||||||||||||||||||||
On November 24, 2014, Generation entered into a $25 million bilateral credit facility, scheduled to mature in December of 2016. This facility does not currently back Generation's commercial paper program. | ||||||||||||||||||||||
On January 9, 2015, Generation amended and extended its $75 million bilateral credit facility for an additional two years. This facility does not back Generation's commercial paper program. | ||||||||||||||||||||||
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, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 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' revolving credit facilities would not constitute an event of default under any of the other Registrants' revolving 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 revolving credit facility would constitute an event of default under the Exelon Corporation revolving credit facility. | ||||||||||||||||||||||
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, 2014: | ||||||||||||||||||||||
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, 2014, the interest coverage ratios at the Registrants were as follows: | ||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||
Interest coverage ratio | 9.19 | 12.35 | 7.03 | 8.72 | 9.28 | |||||||||||||||||
Credit Agreements | ||||||||||||||||||||||
In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $3.2 billion as a result of the June 2014 debt and equity security issuances discussed below, as well as, the net after-tax proceeds from generating asset divestitures during the second half of 2014. During the year ended December 31, 2014, Exelon recorded $31 million to interest expense in connection with the bridge facility to temporarily finance the PHI acquisition. It is not currently expected that Exelon will be required to draw upon this credit facility to finance the proposed PHI acquisition. | ||||||||||||||||||||||
Junior Subordinated Notes | ||||||||||||||||||||||
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes. | ||||||||||||||||||||||
Each equity unit represents an undivided beneficial ownership interest in Exelon’s 2.5% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017. In connection with the remarketing, Exelon may modify the maturity date of the notes to a date earlier than June 1, 2024 but not earlier than June 1, 2020, remove redemption provisions of the notes, or change the interest rate on the notes, including changing the interest rate from fixed to floating. Investors that participate in the remarketing receive the remarketing proceeds and may use those funds to either settle the equity forward upon settlement date or invest in the remarketed debt and use other funds for the share purchase. Exelon intends to use the remarketing proceeds to repay debt issued or for other corporate purposes as soon as practical following such settlements. If the remarketing fails, holders of the notes will have the right to put their notes to Exelon for an amount equal to the principal amount of notes held by such holder plus accrued interest. The equity units carry a total annual distribution rate of 6.5%, which is comprised of a quarterly coupon rate of interest of 2.5% and a quarterly contract payment of 4.0% (contract payments). | ||||||||||||||||||||||
Each purchase contract obligates the holder to purchase, and Exelon to sell, for $50.00 a number of shares of Exelon’s common stock in accordance with the conversion ratios set forth below: | ||||||||||||||||||||||
• | If the market price equals or exceeds $43.7484, then 1.1429 shares. | |||||||||||||||||||||
• | If the market price is less than $43.7484 but greater than $35.00, a number of shares of common stock having a value, based on the market price, equal to $50.00. | |||||||||||||||||||||
• | If the market price is less than or equal to $35.00, then 1.4286 shares. | |||||||||||||||||||||
A holder’s ownership interest in the notes is pledged to Exelon to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the purchase contract must be secured by a U.S. Treasury security. | ||||||||||||||||||||||
At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of junior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at the time of issuance, the present value of the contract payments of $131 million were recorded to Long-term debt, representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. The Long-term debt recorded for the contract payments is considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method. | ||||||||||||||||||||||
Long-Term Debt | ||||||||||||||||||||||
The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2014 and 2013: | ||||||||||||||||||||||
Exelon | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Rate stabilization bonds | 5.72 | % | - | 5.82 | % | 2017 | $ | 195 | $ | 265 | ||||||||||||
First mortgage bonds (a)(b) | 1.2 | % | - | 6.45 | % | 2015 - 2044 | 8,079 | 7,746 | ||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2015 - 2042 | 7,071 | 7,571 | ||||||||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2016 - 2036 | 1,750 | 1,750 | ||||||||||||||
Pollution control note | 4.1 | % | 2014 | — | 20 | |||||||||||||||||
Nuclear fuel procurement contracts | 3.25 | % | - | 3.35 | % | 2018 | 70 | — | ||||||||||||||
Junior subordinated notes | 6.5 | % | 2017 | 1,150 | — | |||||||||||||||||
Nonrecourse debt: | ||||||||||||||||||||||
Fixed rates | 2.33 | % | - | 6 | % | 2031 - 2037 | 1,166 | 1,077 | ||||||||||||||
Variable rates | 2.41 | % | - | 5 | % | 2019 - 2030 | 1,101 | 150 | ||||||||||||||
Notes payable and other (c) | 6.95 | % | - | 7.83 | % | 2015 - 2053 | 174 | 181 | ||||||||||||||
Total long-term debt | 20,756 | 18,760 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (37 | ) | (19 | ) | ||||||||||||||||||
Fair value adjustment | 441 | 384 | ||||||||||||||||||||
Fair value hedge carrying value adjustment, | 4 | 7 | ||||||||||||||||||||
net | ||||||||||||||||||||||
Long-term debt due within one year | (1,802 | ) | (1,509 | ) | ||||||||||||||||||
Long-term debt | $ | 19,362 | $ | 17,623 | ||||||||||||||||||
Long-term debt to financing trusts (d) | ||||||||||||||||||||||
Subordinated debentures to ComEd Financing | 6.35 | % | 2033 | $ | 206 | $ | 206 | |||||||||||||||
III | ||||||||||||||||||||||
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 $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | |||||||||||||||||||||
(d) | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. | |||||||||||||||||||||
Generation | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2015 - 2042 | $ | 5,771 | $ | 6,271 | ||||||||||||
Social Security Administration | 2.93 | % | 2015 | — | 1 | |||||||||||||||||
Pollution control notes | 4.1 | % | 2014 | — | 20 | |||||||||||||||||
Nuclear fuel procurement contracts | 3.25 | % | - | 3.35 | % | 2018 | 70 | — | ||||||||||||||
Nonrecourse debt: | ||||||||||||||||||||||
Fixed rates | 2.33 | % | - | 6 | % | 2031 - 2037 | 1,166 | 1,077 | ||||||||||||||
Variable rates | 2.41 | % | - | 5 | % | 2019 - 2030 | 1,101 | 150 | ||||||||||||||
Notes payable and other (a) | 7.83 | % | 2014 - 2020 | 26 | 33 | |||||||||||||||||
Total long-term debt | 8,134 | 7,552 | ||||||||||||||||||||
Fair value adjustment | 146 | 166 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (14 | ) | 11 | |||||||||||||||||||
Long-term debt due within one year | (614 | ) | (561 | ) | ||||||||||||||||||
Long-term debt | $ | 7,652 | $ | 7,168 | ||||||||||||||||||
______________________ | ||||||||||||||||||||||
(a) | Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | |||||||||||||||||||||
On January 13, 2015, Generation issued $750 million in aggregate principal amount of Senior Notes. The Senior Notes carry an annual interest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will be used to fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes due June 15, 2015 and for general corporate purposes. In addition to the issuance, Exelon terminated $400 million of floating-to-fixed interest rate swaps that had been designated as cash flow hedges. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments at this time are probable not to occur. As a result Exelon will reclassify $26 million of deferred losses in AOCI to Other, net in the first quarter of 2015. | ||||||||||||||||||||||
ComEd | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
First mortgage bonds (a)(b) | 1.95 | % | - | 6.45 | % | 2015 - 2044 | $ | 5,829 | $ | 5,546 | ||||||||||||
Notes payable and other (c) | 6.95 | % | - | 7.49 | % | 2015 - 2053 | 148 | 148 | ||||||||||||||
Total long-term debt | 5,977 | 5,694 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (19 | ) | (19 | ) | ||||||||||||||||||
Long-term debt due within one year | (260 | ) | (617 | ) | ||||||||||||||||||
Long-term debt | $ | 5,698 | $ | 5,058 | ||||||||||||||||||
Long-term debt to financing trust (d) | ||||||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2033 | $ | 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 both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053. | |||||||||||||||||||||
(d) | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. | |||||||||||||||||||||
PECO | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
First mortgage bonds (a)(b) | 1.2 | % | - | 5.95 | % | 2016 - 2044 | $ | 2,250 | $ | 2,200 | ||||||||||||
Total long-term debt | 2,250 | 2,200 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (4 | ) | (3 | ) | ||||||||||||||||||
Long-term debt due within one year | — | (250 | ) | |||||||||||||||||||
Long-term debt | $ | 2,246 | $ | 1,947 | ||||||||||||||||||
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 Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. | |||||||||||||||||||||
BGE | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Rate stabilization bonds | 5.72 | % | - | 5.82 | % | 2017 | 195 | $ | 265 | |||||||||||||
Notes | 2.8 | % | - | 6.35 | % | 2016 - 2036 | $ | 1,750 | $ | 1,750 | ||||||||||||
Total long-term debt | 1,945 | 2,015 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (3 | ) | (4 | ) | ||||||||||||||||||
Long-term debt due within one year | (75 | ) | (70 | ) | ||||||||||||||||||
Long-term debt | $ | 1,867 | $ | 1,941 | ||||||||||||||||||
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 Long-term 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 2019 and thereafter are as follows: | ||||||||||||||||||||||
Year | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||
2015 | $ | 1,739 | $ | 604 | $ | 260 | $ | — | $ | 75 | ||||||||||||
2016 | 1,269 | 4 | 665 | 300 | 300 | |||||||||||||||||
2017 | 2,400 | 705 | 425 | — | 120 | |||||||||||||||||
2018 | 1,415 | 75 | 840 | 500 | — | |||||||||||||||||
2019 | 982 | 682 | 300 | — | — | |||||||||||||||||
Thereafter | 13,599 | (a) | 6,064 | 3,693 | (b) | 1,634 | (c) | 1,708 | (d) | |||||||||||||
Total | $ | 21,404 | $ | 8,134 | $ | 6,183 | $ | 2,434 | $ | 2,203 | ||||||||||||
____________________ | ||||||||||||||||||||||
(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. | |||||||||||||||||||||
Nonrecourse Debt | ||||||||||||||||||||||
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.7 billion of generating assets have been pledged as collateral at December 31, 2014. | ||||||||||||||||||||||
Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement, fully amortizing by June 30, 2031 related to a solar construction project in Denver, Colorado. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2014, $7 million was outstanding. | ||||||||||||||||||||||
CEU Upstream. In July 2011, Generation entered into 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. The agreement is scheduled to expire on January 14, 2019, at a fixed rate of 2.41% annually with interest payable quarterly. As of December 31, 2014, $77 million was outstanding under the facility. 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, 2014, Generation was in compliance with this provision. | ||||||||||||||||||||||
Sacramento PV Energy. In July 2011, a subsidiary of Generation entered into a 19-year, $41 million nonrecourse note to finance a 30MW solar facility in Sacramento, California. The note bears interest at a variable rate equal to the six-month LIBOR plus 2.25%. Interest is payable quarterly and is secured by the equity interests and assets of the subsidiary. The note is scheduled to mature on December 31, 2030. As of December 31, 2014, $35 million was outstanding. The subsidiary also executed interest rate swaps with an initial notional value of $30 million in order to convert the variable interest payments to fixed payments on 75% of the $41 million facility amount, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps. | ||||||||||||||||||||||
Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $10 million solar loan agreement, fully amortizing by December 31, 2031 related to a solar construction project in Holyoke, Massachusetts. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2014, $10 million was outstanding. The agreement includes a provision that requires Generation to establish and maintain a reserve fund to be held by Holyoke Solar Cooperative. As of December 31, 2014, Generation was in compliance with this provision. | ||||||||||||||||||||||
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational 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. As of December 31, 2014, $557 million was outstanding. | ||||||||||||||||||||||
In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2014, Generation had $156 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. Generation expects to contribute approximately $2 million in additional equity contributions. | ||||||||||||||||||||||
In connection with this agreement, on September 28, 2011, Generation entered into a floating-to-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. During the third quarter of 2014, the original interest rate swap was terminated, consistent with the agreements. See Note 12 — Derivative Financial Instruments for additional information regarding the interest rate swaps associated with Antelope Valley. | ||||||||||||||||||||||
Constellation Solar Horizons. In September 2012, a subsidiary of Generation entered into an 18-year $38 million nonrecourse note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. The note is schedule to mature on September 7, 2030. The note bears interest at a variable rate equal to the three-month LIBOR plus 2.25%. Interest is payable quarterly, and the note is secured by the equity interests and assets of the subsidiary. As of December 31, 2014, $34 million was outstanding. The subsidiary also executed interest rate swaps for an initial notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps. | ||||||||||||||||||||||
Continental Wind. In September 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 with interest payable semi-annually. 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 667MW. The net proceeds were distributed to Generation for its general business purposes. As of December 31, 2014, $592 million was outstanding. In connection with this nonrecourse 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, 2014, the Continental Wind letter of credit facility had $47 million in letters of credit outstanding related to the project. | ||||||||||||||||||||||
ExGen Renewables I. On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a nonrecourse senior secured loan, due February 6, 2021. The proceeds were distributed to Generation for its general business purposes. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% floor with interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2014, $282 million was outstanding. In addition to the financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of 2.03% to manage a portion of the interest rate exposure in connection with the financing. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps. | ||||||||||||||||||||||
ExGen Texas Power. In September 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan, scheduled to mature on September 18, 2021. The net proceeds were distributed to Generation for general business purposes. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2014, $673 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps. | ||||||||||||||||||||||
Income_Taxes_Exelon_Generation
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||
Income Taxes (Exelon, Generation, ComEd, PECO and BGE) | 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, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Included in operations: | ||||||||||||||||||||
Federal | ||||||||||||||||||||
Current | $ | 121 | $ | 360 | $ | (171 | ) | $ | 28 | $ | 24 | |||||||||
Deferred | 576 | (35 | ) | 395 | 87 | 90 | ||||||||||||||
Investment tax credit amortization | (20 | ) | (16 | ) | (2 | ) | — | (1 | ) | |||||||||||
State | ||||||||||||||||||||
Current | 42 | 35 | 7 | (2 | ) | — | ||||||||||||||
Deferred | (53 | ) | (137 | ) | 39 | 1 | 27 | |||||||||||||
Total | $ | 666 | $ | 207 | $ | 268 | $ | 114 | $ | 140 | ||||||||||
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 | ||||||||||
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, 2014 | 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 | 1.3 | (1.9 | ) | 4.5 | (0.1 | ) | 5 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 2.4 | 4.8 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.5 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | (2.0 | ) | (4.1 | ) | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.2 | — | 0.2 | |||||||||||||||
Amortization of investment tax credit, net deferred | (1.1 | ) | (2.0 | ) | (0.3 | ) | (0.1 | ) | (0.3 | ) | ||||||||||
taxes | ||||||||||||||||||||
Plant basis differences | (1.9 | ) | — | (0.1 | ) | (10.4 | ) | 0.2 | ||||||||||||
Production tax credits and other credits | (2.4 | ) | (4.8 | ) | — | — | — | |||||||||||||
Non-controlling interest | (1.8 | ) | (3.7 | ) | — | — | — | |||||||||||||
Statute of limitations expiration | (2.6 | ) | (5.3 | ) | — | — | — | |||||||||||||
Other | — | (0.6 | ) | 0.3 | 0.1 | (0.2 | ) | |||||||||||||
Effective income tax rate | 26.8 | % | 16.9 | % | 39.6 | % | 24.5 | % | 39.9 | % | ||||||||||
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 | 4.8 | 1.8 | 3.4 | 1.6 | 4.9 | |||||||||||||||
Qualified nuclear decommissioning trust fund income | 3.7 | 6.1 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.3 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | — | — | — | — | — | |||||||||||||||
Health care reform legislation | 0.1 | — | 0.7 | — | 0.2 | |||||||||||||||
Amortization of investment tax credit, net deferred | (1.9 | ) | (3.0 | ) | (0.6 | ) | (0.1 | ) | — | |||||||||||
taxes | ||||||||||||||||||||
Plant basis differences | (1.6 | ) | — | (0.8 | ) | (7.1 | ) | (0.2 | ) | |||||||||||
Production tax credits and other credits | (2.1 | ) | (3.4 | ) | (0.1 | ) | — | — | ||||||||||||
Statute of limitations expiration | (0.1 | ) | (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 | (3.5 | ) | 4.9 | 4.6 | 2 | 24.3 | ||||||||||||||
Qualified nuclear decommissioning trust fund income | 5.4 | 9.1 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.4 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | — | — | — | — | — | |||||||||||||||
Health care reform legislation | 0.1 | — | 0.4 | — | 11.6 | |||||||||||||||
Amortization of investment tax credit | (1.1 | ) | (1.3 | ) | (0.4 | ) | (0.3 | ) | (8.6 | ) | ||||||||||
Plant basis differences | (2.4 | ) | — | (0.3 | ) | (11.5 | ) | (9.0 | ) | |||||||||||
Production tax credits and other credits | (2.2 | ) | (3.7 | ) | — | — | — | |||||||||||||
Fines and Penalties | 2.6 | 4.4 | — | — | — | |||||||||||||||
Merger expenses (c) | 2.4 | — | — | — | 24.2 | |||||||||||||||
Statute of limitations expiration | (0.1 | ) | (0.3 | ) | — | — | — | |||||||||||||
Other | (1.1 | ) | (0.4 | ) | (0.6 | ) | (0.2 | ) | (13.9 | ) | ||||||||||
Effective income tax rate | 34.9 | % | 47.3 | % | 38.7 | % | 25 | % | 63.6 | % | ||||||||||
_____________________ | ||||||||||||||||||||
(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. | |||||||||||||||||||
(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, 2014 and 2013 are presented below: | ||||||||||||||||||||
For the Year Ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Plant basis differences | $ | (12,143 | ) | $ | (3,834 | ) | $ | (3,945 | ) | $ | (2,749 | ) | $ | (1,661 | ) | |||||
Accrual based contracts | (178 | ) | (178 | ) | — | — | — | |||||||||||||
Derivatives and other financial instruments | (46 | ) | (79 | ) | (4 | ) | — | — | ||||||||||||
Deferred pension and postretirement obligation | 1,914 | (390 | ) | (543 | ) | 2 | (53 | ) | ||||||||||||
Nuclear decommissioning activities | (726 | ) | (726 | ) | — | — | — | |||||||||||||
Deferred debt refinancing costs | 112 | 57 | (18 | ) | (2 | ) | (4 | ) | ||||||||||||
Regulatory assets and liabilities | (1,824 | ) | — | (286 | ) | 27 | (258 | ) | ||||||||||||
Tax loss carryforward | 111 | 48 | — | 11 | 39 | |||||||||||||||
Tax credit carryforward | 97 | 143 | — | — | — | |||||||||||||||
Investment in CENG | (563 | ) | (563 | ) | — | — | — | |||||||||||||
Other, net | 1,029 | 346 | 255 | 111 | 30 | |||||||||||||||
Deferred income tax liabilities (net) | $ | (12,217 | ) | $ | (5,176 | ) | $ | (4,541 | ) | $ | (2,600 | ) | $ | (1,907 | ) | |||||
Unamortized investment tax credits | (555 | ) | (528 | ) | (20 | ) | (2 | ) | (5 | ) | ||||||||||
Total deferred income tax liabilities (net) and | $ | (12,772 | ) | $ | (5,704 | ) | $ | (4,561 | ) | $ | (2,602 | ) | $ | (1,912 | ) | |||||
unamortized investment tax credits | ||||||||||||||||||||
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 postretirement obligation | 1,489 | (362 | ) | (522 | ) | — | (74 | ) | ||||||||||||
Nuclear decommissioning activities | (647 | ) | (646 | ) | — | — | — | |||||||||||||
Deferred debt refinancing costs | 173 | 79 | (21 | ) | (3 | ) | (5 | ) | ||||||||||||
Regulatory assets and liabilities | (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 | $ | (12,372 | ) | $ | (5,845 | ) | $ | (4,132 | ) | $ | (2,404 | ) | $ | (1,798 | ) | |||||
unamortized investment tax credits | ||||||||||||||||||||
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2014. | ||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Federal | ||||||||||||||||||||
Federal general business credits carryforward | 184 | (a) | 184 | — | — | — | ||||||||||||||
State | ||||||||||||||||||||
State net operating losses and other credit carryforwards | 3,141 | 1,693 | — | 170 | 730 | (e) | ||||||||||||||
Deferred taxes on state tax attributes (net) | 169 | 96 | — | 11 | 39 | |||||||||||||||
Valuation allowance on state tax attributes | 50 | 48 | — | — | 1 | |||||||||||||||
_____________________ | ||||||||||||||||||||
(a) | Exelon’s federal general business credit carryforwards will expire beginning in 2032. | |||||||||||||||||||
(b) | Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015 | |||||||||||||||||||
(c) | Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015. | |||||||||||||||||||
(d) | PECO’s state net operating losses will expire beginning in 2031. | |||||||||||||||||||
(e) | 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, 2014, 2013 and 2012: | ||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unrecognized tax benefits at January 1, 2014 | $ | 2,175 | $ | 1,415 | $ | 324 | $ | 44 | $ | — | ||||||||||
Increases based on tax positions related to 2014 | 15 | 15 | — | — | — | |||||||||||||||
Change to positions that only affect timing | (255 | ) | 33 | (175 | ) | — | — | |||||||||||||
Increases based on tax positions prior to 2014 | 18 | 18 | — | — | — | |||||||||||||||
Decreases based on tax positions prior to 2014 | (1 | ) | (2 | ) | — | — | — | |||||||||||||
Decrease from settlements with taxing authorities | (35 | ) | (34 | ) | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | (88 | ) | (88 | ) | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2014 | $ | 1,829 | $ | 1,357 | $ | 149 | $ | 44 | $ | — | ||||||||||
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 | $ | — | ||||||||||
Included in Exelon’s unrecognized tax benefits balance at December 31, 2014 and 2013 are approximately $1,129 million and $1,387 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 $701 million and $672 million, respectively, of unrecognized tax benefits at December 31, 2014 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $788 million and $768 million, respectively, of unrecognized tax benefits at December 31, 2013 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. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit and oral arguments were heard in January of 2015. | ||||||||||||||||||||
Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the $661 million of total unrecognized tax benefits will significantly decrease in the next twelve months. | ||||||||||||||||||||
Settlement of Income Tax Audits and Litigation | ||||||||||||||||||||
As of December 31, 2014, Exelon and Generation have approximately $188 million of state unrecognized tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. | ||||||||||||||||||||
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 tax positions reflected in the Registrants’ Consolidated Balance Sheets. | ||||||||||||||||||||
Net interest receivable (payable) as of | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
December 31, 2014 | $ | (310 | ) | $ | 40 | $ | (203 | ) | $ | 3 | $ | (1 | ) | |||||||
December 31, 2013 | (349 | ) | (37 | ) | (174 | ) | 3 | — | ||||||||||||
The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions. | ||||||||||||||||||||
Net interest expense (income) for the years ended | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
December 31, 2014 | $ | (36 | ) | $ | (50 | ) | $ | 6 | $ | — | $ | 1 | ||||||||
December 31, 2013 | 391 | 17 | 281 | (1 | ) | — | ||||||||||||||
December 31, 2012 | (1 | ) | 11 | (20 | ) | (1 | ) | 9 | ||||||||||||
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, 2001-2013 | |||||||||||||||||||
Constellation and subsidiaries consolidated Federal income tax returns | 2011-March 2012 | |||||||||||||||||||
Exelon and subsidiaries Illinois unitary income tax returns | 2007-2013 | |||||||||||||||||||
Constellation combined New York corporate income tax returns | 2008-2013 | |||||||||||||||||||
Various separate company Pennsylvania corporate net income tax returns | 2010-2013 | |||||||||||||||||||
BGE Maryland corporate net income tax returns | 2011-2013 | |||||||||||||||||||
Various Exelon Maryland corporate net income tax returns | 2012-2013 | |||||||||||||||||||
Various Constellation (Non-BGE) Maryland corporate net income tax returns | 2011-2013 | |||||||||||||||||||
Other Tax Matters | ||||||||||||||||||||
Like-Kind Exchange | ||||||||||||||||||||
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of 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 $1.2 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 $90 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 unpaid tax liabilities related to 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 IRS’s assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded. | ||||||||||||||||||||
On September 30, 2013, the IRS 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. | ||||||||||||||||||||
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 as of December 31, 2014 may be as much as $810 million, of which approximately $310 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 and interest impacts will increase by a material amount. | ||||||||||||||||||||
In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination resulted in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment. See Note 8 —Impairment of Long-Lived Assets for further details. | ||||||||||||||||||||
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 will change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has calculated that adoption of the new method will result in a cash tax detriment of approximately $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 was reflected in the effective income tax rate reconciliation in 2011 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, and $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 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. | ||||||||||||||||||||
Long-Term State Tax Apportionment (Exelon and Generation) | ||||||||||||||||||||
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 2014 pursuant to Exelon's long-term state tax apportionment policy, resulting in the recording of a deferred state tax benefit for Exelon and Generation of $28 million (net of Federal taxes) and $40 million (net of Federal taxes), respectively. The amounts recorded for 2013 in accordance with the policy were immaterial. | ||||||||||||||||||||
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 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of tax net operating losses. | ||||||||||||||||||||
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 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 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 million, 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, 2014 | ||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO) | 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, 2013 to December 31, 2014: | ||||||||||||||||||||
Exelon and | ||||||||||||||||||||
Generation | ||||||||||||||||||||
Nuclear decommissioning ARO at January 1, 2013 | $ | 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 | |||||||||||||||||||
Consolidation of CENG (b) | 1,760 | |||||||||||||||||||
Accretion expense | 334 | |||||||||||||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 19 | |||||||||||||||||||
Costs incurred to decommission retired plants | (7 | ) | ||||||||||||||||||
Nuclear decommissioning ARO at December 31, 2014 (a) | $ | 6,961 | ||||||||||||||||||
_________________________ | ||||||||||||||||||||
(a) | Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. | |||||||||||||||||||
(b) | Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||||||||||||||||
During 2014, Generation’s ARO increased by approximately $2.1 billion. The increase is largely driven by the recording of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidation of CENG (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC ). The change in the ARO was also driven by an increase for accretion of the obligation and an increase in the estimated costs to decommission Byron, Braidwood, and LaSalle nuclear units resulting from the completion of updated decommissioning costs studies received during 2014 as part of the annual assessment. These increases in the ARO were partially offset by decreases in the ARO due to a reduction in estimated escalation rates, primarily for labor and energy costs. The increase in the ARO due to the changes in, and timing of, estimated cash flows was offset within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets, aside from an approximate $16 million credit to income, which is included in Operating and maintenance expense within 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 was entirely offset by decreases in Property, plant and equipment within Exelon’s and Generation’s Consolidated Balance Sheets. | ||||||||||||||||||||
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 Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. 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 former PECO 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. Aside from the former PECO units, Generation does not currently collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from utility customers. Apart from the contributions made to the NDT funds from amounts previously collected from ComEd and currently collected from 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) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, 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 compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts for any of Generation's other nuclear 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 Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities. | ||||||||||||||||||||
At December 31, 2014, and 2013, Exelon and Generation had NDT fund investments totaling $10,537 million and $8,071 million, respectively. At December 31, 2014, approximately 52% of the funds were invested in equity securities and 48% were invested in fixed income securities. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities. 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. | ||||||||||||||||||||
The following table provides unrealized gains on NDT funds for 2014, 2013 and 2012: | ||||||||||||||||||||
Exelon and Generation | ||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Net unrealized gains on decommissioning trust | $ | 180 | $ | 406 | $ | 386 | ||||||||||||||
funds—Regulatory Agreement Units (a) | ||||||||||||||||||||
Net unrealized gains on decommissioning trust | 134 | 146 | 105 | |||||||||||||||||
funds—Non-Regulatory Agreement Units (b)(c) | ||||||||||||||||||||
_______________________ | ||||||||||||||||||||
(a) | Net unrealized gains 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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, 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 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, 2014, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), 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 former PECO 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 Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
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 and decommission the SNF dry storage facility, 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 its 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. | ||||||||||||||||||||
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 for Zion Station decommissioning 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 for the SNF. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $86 million, which is included within the nuclear decommissioning ARO at December 31, 2014. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE 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 payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2014 and 2013: | ||||||||||||||||||||
Exelon and Generation | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Carrying value of Zion Station pledged assets | $ | 319 | $ | 458 | ||||||||||||||||
Payable to Zion Solutions (a) | 292 | 414 | ||||||||||||||||||
Current portion of payable to Zion Solutions (b) | 137 | 109 | ||||||||||||||||||
Cumulative withdrawals by Zion Solutions to pay decommissioning costs | 666 | 498 | ||||||||||||||||||
___________________ | ||||||||||||||||||||
(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. | |||||||||||||||||||
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 constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility 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 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 and its parent company have also provided a performance guarantee and EnergySolutions has 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, 2014 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, 2014 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 6% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 9%). | ||||||||||||||||||||
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 had 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 March 26, 2014, in accordance with a NRC requirement with respect to units involved in a merger or acquisition, CENG submitted its NRC-required decommissioning funding status report as of December 31, 2013 and no additional financial assurance was required. | ||||||||||||||||||||
On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for reactors that have been shut down except for Zion Station which is included on a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 was extended by 20 years. As a result of this extension, and the subsequent funding assurance calculation performed by the NRC, it was found that the parent company guarantee was no longer required and thus the parent guarantee for Limerick Unit 1 will be cancelled effective March 13, 2015. See Note 3 — Regulatory Matters for additional information regarding the operating license extension for Limerick Unit 1. | ||||||||||||||||||||
Generation will file its next biennial decommissioning funding status report with the NRC on or before March 31, 2015. That report will reflect the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Unit 1, Braidwood Unit 2, and Byron Unit 2 do not have adequate funding assurance based on the most recent calculations as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017. | ||||||||||||||||||||
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. 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. 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. On May 1, 2014, the NRC issued its final determination. Although the NRC determined that these historical status reports did not provide complete and accurate information, the violation of the regulatory requirements was not a deliberate violation. The NRC noted the low safety significance and Generation's corrective actions to satisfy the NRC Staff's expectations and issued a Severity Level IV violation, with no monetary penalty. A Severity Level IV violation is the lowest level of violation. | ||||||||||||||||||||
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 Generation’s nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon. | ||||||||||||||||||||
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 units, 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, 2013 to December 31, 2014: | ||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Non-nuclear AROs at January 1, 2013 | $ | 343 | $ | 207 | $ | 99 | $ | 29 | $ | 8 | ||||||||||
Net increase (decrease) due to changes in, and | 1 | (11 | ) | — | — | 12 | ||||||||||||||
timing of, estimated future cash flows (a) | ||||||||||||||||||||
Development projects (b) | 2 | 2 | — | — | — | |||||||||||||||
Accretion expense (c) | 18 | 13 | 4 | 1 | — | |||||||||||||||
Payments | (13 | ) | (10 | ) | (2 | ) | — | (1 | ) | |||||||||||
Non-nuclear AROs at December 31, 2013 (d) | 351 | 201 | 101 | 30 | 19 | |||||||||||||||
Net increase (decrease) due to changes in, and | (1 | ) | (2 | ) | 2 | — | (1 | ) | ||||||||||||
timing of, estimated future cash flows (a) | ||||||||||||||||||||
Development projects (b) | 11 | 11 | — | — | — | |||||||||||||||
Accretion expense (c) | 15 | 11 | 3 | 1 | — | |||||||||||||||
Liabilities held for sale (e) | (4 | ) | (4 | ) | — | — | — | |||||||||||||
Sale of generating assets (f) | (20 | ) | (20 | ) | — | — | — | |||||||||||||
Payments | (6 | ) | (3 | ) | (2 | ) | (1 | ) | — | |||||||||||
Non-nuclear AROs at December 31, 2014 (d) | $ | 346 | $ | 194 | $ | 104 | $ | 30 | $ | 18 | ||||||||||
________________________ | ||||||||||||||||||||
(a) | During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013. | |||||||||||||||||||
(b) | Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites. | |||||||||||||||||||
(c) | 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. | |||||||||||||||||||
(d) | During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets. | |||||||||||||||||||
(e) | Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information. | |||||||||||||||||||
(f) | Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. See Note 4 — Mergers, Acquisitions, and Dispositions for further information. |
Retirement_Benefits_Exelon_Gen
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ||||||||||||||||||||||||
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||
As of December 31, 2014, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2014. | ||||||||||||||||||||||||
On April 1, 2014, as a result of the consolidation of CENG into Generation, the obligations associated with CENG's pension and other postretirement plans are reflected in the disclosures below based on an April 1, 2014 valuation adjusted for subsequent activity. Exelon assumed sponsorship of the CENG pension and other postretirement benefit plans in the third quarter of 2014 when the employees transferred to Exelon. CENG will fund the underfunded balances of the pension and other postretirement benefit plans measured at July 14, 2014 on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF's disposition of a majority of its interest in CENG. Payments received from CENG related to the funded plans will be contributed to the appropriate benefit trusts. | ||||||||||||||||||||||||
Operating Company | ||||||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||||||
Qualified Pension Plans: | ||||||||||||||||||||||||
Exelon Corporation Retirement Program(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Cash Balance Pension Plan(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Pension Plan for Bargaining | X | X | X | |||||||||||||||||||||
Unit Employees(a) | ||||||||||||||||||||||||
Exelon New England Union Employees Pension | X | |||||||||||||||||||||||
Plan(a) | ||||||||||||||||||||||||
Exelon Employee Pension Plan for Clinton, TMI | X | X | X | |||||||||||||||||||||
and Oyster Creek(a) | ||||||||||||||||||||||||
Pension Plan of Constellation Energy Group, Inc.(b) | X | X | X | X | X | |||||||||||||||||||
Pension Plan of Constellation Energy Nuclear | X | X | X | |||||||||||||||||||||
Group, LLC(c) | ||||||||||||||||||||||||
Nine Mile Point Pension Plan(c) | X | X | ||||||||||||||||||||||
Constellation Mystic Power, LLC Union Employees | X | |||||||||||||||||||||||
Pension Plan Including Plan A and Plan B(b) | ||||||||||||||||||||||||
Non-Qualified Pension Plans: | ||||||||||||||||||||||||
Exelon Corporation Supplemental Pension Benefit | X | X | X | X | ||||||||||||||||||||
Plan and 2000 Excess Benefit Plan(a) | ||||||||||||||||||||||||
Exelon Corporation Supplemental Management | X | X | X | X | X | |||||||||||||||||||
Retirement Plan(a) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Senior Executive | X | X | X | |||||||||||||||||||||
Supplemental Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Supplemental | X | X | X | |||||||||||||||||||||
Pension Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Benefits | X | X | X | |||||||||||||||||||||
Restoration Plan(b) | ||||||||||||||||||||||||
Constellation Nuclear Plan, LLC Executive | X | X | ||||||||||||||||||||||
Retirement Plan(c) | ||||||||||||||||||||||||
Constellation Energy Nuclear Plan, LLC Benefits | X | X | ||||||||||||||||||||||
Restoration Plan(c) | ||||||||||||||||||||||||
Baltimore Gas & Electric Company Executive | X | X | X | |||||||||||||||||||||
Benefit Plan(b) | ||||||||||||||||||||||||
Baltimore Gas & Electric Company Manager | X | X | X | |||||||||||||||||||||
Benefit Plan(b) | ||||||||||||||||||||||||
Operating Company | ||||||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||||||
PECO Energy Company Retiree Medical Plan(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Health Care Program(a) | X | X | X | X | ||||||||||||||||||||
Exelon Corporation Employees’ Life Insurance | X | X | X | X | X | |||||||||||||||||||
Plan(a) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Retiree Medical | X | X | X | X | X | |||||||||||||||||||
Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Retiree Dental | X | X | X | |||||||||||||||||||||
Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Employee Life | X | X | X | X | X | |||||||||||||||||||
Insurance Plan and Family Life Insurance Plan(b) | ||||||||||||||||||||||||
Constellation Mystic Power, LLC | X | |||||||||||||||||||||||
Post-Employment Medical Account Savings Plan(b) | ||||||||||||||||||||||||
Exelon New England Union Post-Employment | X | |||||||||||||||||||||||
Medical Savings Account Plan(a) | ||||||||||||||||||||||||
Retiree Medical Plan of Constellation Energy | X | X | X | |||||||||||||||||||||
Nuclear Group LLC(c) | ||||||||||||||||||||||||
Retiree Dental Plan of Constellation Energy | X | X | X | |||||||||||||||||||||
Nuclear Group LLC(c) | ||||||||||||||||||||||||
Nine Mile Point Nuclear Station, LLC Medical Care | X | X | ||||||||||||||||||||||
and Prescription Drug Plan for Retired | ||||||||||||||||||||||||
Employees(c) | ||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | These plans are collectively referred to as the Legacy Exelon plans. | |||||||||||||||||||||||
(b) | These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans. | |||||||||||||||||||||||
(c) | These plans are collectively referred to as the Legacy CENG plans. | |||||||||||||||||||||||
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 OPEB 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 2014, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase to the other postretirement benefit obligation of $12 million. Additionally, Accumulated other comprehensive loss (AOCL) increased by approximately $12 million (after tax), regulatory assets increased by approximately $34 million, and regulatory liabilities increased by approximately $5 million. During the second quarter of 2014, Exelon received an updated valuation for the remainder of its pension and other postretirement obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $13 million and an increase to the other postretirement benefit obligation of $3 million. Additionally, AOCL increased by approximately $1 million (after tax) and regulatory assets increased by approximately $15 million. | ||||||||||||||||||||||||
In April 2014, Exelon announced plan design changes for certain other postretirement benefit plans, which required an interim remeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates and asset values. The remeasurement resulted in a decrease to Exelon's non-pension postretirement benefit obligations, regulatory assets, and AOCL of approximately $790 million, $240 million, and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125 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: | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||||||
Net benefit obligation at beginning of year | $ | 15,459 | $ | 16,800 | $ | 4,451 | $ | 4,820 | ||||||||||||||||
Service cost | 293 | 317 | 117 | 162 | ||||||||||||||||||||
Interest cost | 749 | 650 | 186 | 194 | ||||||||||||||||||||
Plan participants’ contributions | — | — | 42 | 34 | ||||||||||||||||||||
Actuarial loss (gain) | 2,095 | (1,363 | ) | 502 | (551 | ) | ||||||||||||||||||
Plan amendments | — | 1 | (1,012 | ) | 15 | |||||||||||||||||||
Acquisitions/divestitures(a) | 594 | — | 142 | — | ||||||||||||||||||||
Curtailments | (8 | ) | — | — | — | |||||||||||||||||||
Settlements | (30 | ) | (69 | ) | — | — | ||||||||||||||||||
Gross benefits paid | (896 | ) | (877 | ) | (231 | ) | (223 | ) | ||||||||||||||||
Net benefit obligation at end of year | $ | 18,256 | $ | 15,459 | $ | 4,197 | $ | 4,451 | ||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Change in plan assets: | ||||||||||||||||||||||||
Fair value of net plan assets at beginning of year | $ | 13,571 | $ | 13,357 | $ | 2,238 | $ | 2,135 | ||||||||||||||||
Actual return on plan assets | 1,443 | 821 | 90 | 209 | ||||||||||||||||||||
Employer contributions | 332 | 339 | 291 | 83 | ||||||||||||||||||||
Plan participants’ contributions | — | — | 42 | 34 | ||||||||||||||||||||
Benefits paid | (896 | ) | (877 | ) | (231 | ) | (223 | ) | ||||||||||||||||
Acquisitions/divestitures(a) | 454 | — | — | — | ||||||||||||||||||||
Settlements | (30 | ) | (69 | ) | — | — | ||||||||||||||||||
Fair value of net plan assets at end of year | $ | 14,874 | $ | 13,571 | $ | 2,430 | $ | 2,238 | ||||||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information. | |||||||||||||||||||||||
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Other current liabilities | $ | 16 | $ | 12 | $ | 25 | $ | 23 | ||||||||||||||||
Pension obligations | 3,366 | 1,876 | — | — | ||||||||||||||||||||
Non-pension postretirement benefit obligations | — | — | 1,742 | 2,190 | ||||||||||||||||||||
Unfunded status (net benefit obligation less net plan | $ | 3,382 | $ | 1,888 | $ | 1,767 | $ | 2,213 | ||||||||||||||||
assets) | ||||||||||||||||||||||||
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 | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Projected benefit obligation | $ | 18,256 | $ | 15,452 | ||||||||||||||||||||
Fair value of net plan assets | 14,874 | 13,564 | ||||||||||||||||||||||
ABO in | ||||||||||||||||||||||||
excess of plan assets | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Projected benefit obligation | $ | 18,256 | $ | 15,452 | ||||||||||||||||||||
Accumulated benefit obligation | 17,191 | 14,552 | ||||||||||||||||||||||
Fair value of net plan assets | 14,874 | 13,564 | ||||||||||||||||||||||
On a PBO basis, the plans were funded at 81% at December 31, 2014 compared to 88% at December 31, 2013. On an ABO basis, the plans were funded at 87% at December 31, 2014 compared to 93% at December 31, 2013. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels. | ||||||||||||||||||||||||
Components of Net Periodic Benefit Costs | ||||||||||||||||||||||||
The majority of the 2014 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.80%. Certain of the pension plans were remeasured as of October 31, 2014 using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.95%. Costs incurred during the year ended December 31, 2014 reflect the impact of this remeasurement. The majority of the 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.59% for funded plans and a discount rate of 4.90% for all plans. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for December 31, 2014 reflect the impact of this remeasurement. | ||||||||||||||||||||||||
On July 14, 2014 Exelon became the sponsor of the pension and other postretirement plans formerly sponsored by CENG. The components of cost for the CENG plans are included in the table below for the period from April 1, 2014 to December 31, 2014, and reflect the valuation performed on April 1, 2014 upon consolidation of CENG. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further details on the consolidation of CENG. The 2014 pension benefit cost for these plans is calculated using an expected long-term rate of return on plan assets of 7.75% and discount rates ranging from 3.60% - 4.30%. The majority of the 2014 other postretirement benefit cost for the CENG plans is calculated using a discount rate of 4.55%. | ||||||||||||||||||||||||
A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2014, 2013 and 2012. | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Components of net periodic | ||||||||||||||||||||||||
benefit cost: | ||||||||||||||||||||||||
Service cost | $ | 293 | $ | 317 | $ | 280 | $ | 117 | $ | 162 | $ | 156 | ||||||||||||
Interest cost | 749 | 650 | 698 | 186 | 194 | 205 | ||||||||||||||||||
Expected return on assets | (994 | ) | (1,015 | ) | (988 | ) | (154 | ) | (132 | ) | (115 | ) | ||||||||||||
Amortization of: | ||||||||||||||||||||||||
Transition obligation | — | — | — | — | — | 11 | ||||||||||||||||||
Prior service cost (credit) | 14 | 14 | 15 | (122 | ) | (19 | ) | (17 | ) | |||||||||||||||
Actuarial loss | 420 | 562 | 450 | 50 | 83 | 81 | ||||||||||||||||||
Curtailment benefits | — | — | — | — | — | (7 | ) | |||||||||||||||||
Settlement charges | 2 | 9 | 31 | — | — | — | ||||||||||||||||||
Contractual termination benefits (a) | — | — | 14 | — | — | 6 | ||||||||||||||||||
Net periodic benefit cost | $ | 484 | $ | 537 | $ | 500 | $ | 77 | $ | 288 | $ | 320 | ||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | 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 Prescription Drug, Improvement and Modernization Act of 2003 (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 (Part D subsidy). 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 would no longer elect to take the direct Part D subsidy. This resulted in a $17 million increase in cost for the year ended December 31, 2012 related to the amortization of an actuarial loss. Beginning in 2013, eligible employees are offered an Employee Group Waiver Plan (EGWP), a standard Medicare Part D Plan, with a supplemental “wrap," which contains a wraparound prescription drug design that allows the company to provide benefits above those available under the EGWP. | ||||||||||||||||||||||||
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, 2014, 2013 and 2012 for all plans combined. | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Changes in plan assets and benefit | ||||||||||||||||||||||||
obligations recognized in AOCI and regulatory assets (liabilities): | ||||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 1,639 | $ | (1,169 | ) | $ | 1,693 | $ | 561 | $ | (628 | ) | $ | 304 | ||||||||||
Amortization of actuarial loss | (420 | ) | (562 | ) | (450 | ) | (50 | ) | (83 | ) | (81 | ) | ||||||||||||
Current year prior service (credit) cost | — | — | 1 | (1,012 | ) | 15 | (109 | ) | ||||||||||||||||
Amortization of prior service (cost) | (14 | ) | (14 | ) | (15 | ) | 122 | 19 | 17 | |||||||||||||||
credit | ||||||||||||||||||||||||
Current year transition (asset) | — | — | — | — | — | 1 | ||||||||||||||||||
obligation | ||||||||||||||||||||||||
Amortization of transition asset | — | — | — | — | — | (11 | ) | |||||||||||||||||
(obligation) | ||||||||||||||||||||||||
Curtailments | — | — | (10 | ) | — | — | (1 | ) | ||||||||||||||||
Settlements | (2 | ) | (8 | ) | (31 | ) | — | — | — | |||||||||||||||
Total recognized in AOCI and | $ | 1,203 | $ | (1,753 | ) | $ | 1,188 | $ | (379 | ) | $ | (677 | ) | $ | 120 | |||||||||
regulatory assets (liabilities) (a) | ||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. 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. | |||||||||||||||||||||||
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, 2014 and 2013, respectively, for all plans combined: | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Prior service cost (credit) | $ | 49 | $ | 62 | $ | (963 | ) | $ | (73 | ) | ||||||||||||||
Actuarial loss | 7,407 | 6,192 | 985 | 474 | ||||||||||||||||||||
Total (a) | $ | 7,456 | $ | 6,254 | $ | 22 | $ | 401 | ||||||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. 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. | |||||||||||||||||||||||
The following table provides the components of Exelon’s AOCI and regulatory assets at December 31, 2014 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2015. 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, 2015 and actual claims activity as of December 31, 2014. The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefit plans. | ||||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
Prior service cost (credit) | $ | 13 | $ | (175 | ) | |||||||||||||||||||
Actuarial loss | 562 | 74 | ||||||||||||||||||||||
Total (a) | $ | 575 | $ | (101 | ) | |||||||||||||||||||
___________________ | ||||||||||||||||||||||||
(a) | Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, 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 EROA, 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 EROA, 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. | ||||||||||||||||||||||||
Mortality. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations of future improvements in life expectancy. The change was supported through completion of an experience study and supplemental analyses performed by its actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and other postretirement benefits obligations, respectively. | ||||||||||||||||||||||||
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. 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 | |||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Discount rate | 3.94 | % | 4.8 | % | 3.92 | % | 3.92 | % | 4.9 | % | 4 | % | ||||||||||||
Rate of | (a) | (b) | (c) | (a) | (b) | (c) | ||||||||||||||||||
compensation | ||||||||||||||||||||||||
increase | ||||||||||||||||||||||||
Mortality table | RP-2000 table with Scale BB-2D improvements (adjusted) | RP-2000 table with Scale AA | RP-2000 table with Scale AA improvements | RP-2000 table with Scale BB-2D improvements (adjusted) | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | ||||||||||||||||||
improvements | ||||||||||||||||||||||||
Health care cost | N/A | N/A | N/A | 6.00% | 6.00% | 6.50% | ||||||||||||||||||
trend on covered | decreasing | decreasing | decreasing | |||||||||||||||||||||
charges | to | to | to | |||||||||||||||||||||
ultimate | ultimate | ultimate | ||||||||||||||||||||||
trend of | trend of | trend of | ||||||||||||||||||||||
5.00% in | 5.00% in | 5.00% in | ||||||||||||||||||||||
2017 | 2017 | 2017 | ||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||
(a) | 3.25% for 2015-2019 and 3.75% thereafter. | |||||||||||||||||||||||
(b) | 3.25% for 2014-2018 and 3.75% thereafter. | |||||||||||||||||||||||
(c) | 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, 2014, 2013 and 2012: | ||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Discount rate | 4.8 | % | (a) | 3.92 | % | (b) | 4.74 | % | (c) | 4.9 | % | (a) | 4 | % | (b) | 4.8 | % | (c) | ||||||
Expected return on | 7 | % | (d) | 7.5 | % | (d) | 7.5 | % | (d) | 6.59 | % | (d) | 6.45 | % | (d) | 6.68 | % | (d) | ||||||
plan assets | ||||||||||||||||||||||||
Rate of | (e) | (f) | 3.75 | % | (e) | (f) | 3.75 | % | ||||||||||||||||
compensation | ||||||||||||||||||||||||
increase | ||||||||||||||||||||||||
Mortality table | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | ||||||||||||||||||
Health care cost | N/A | N/A | N/A | 6.00% | 6.50% | 6.50% | ||||||||||||||||||
trend on covered | decreasing | decreasing | decreasing | |||||||||||||||||||||
charges | to | to | to | |||||||||||||||||||||
ultimate | ultimate | ultimate | ||||||||||||||||||||||
trend of | trend of | trend of | ||||||||||||||||||||||
5.00% in | 5.00% in | 5.00% in | ||||||||||||||||||||||
2017 | 2017 | 2017 | ||||||||||||||||||||||
___________________________ | ||||||||||||||||||||||||
(a) | The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information. | |||||||||||||||||||||||
(b) | 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 measurements. | |||||||||||||||||||||||
(c) | The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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. | |||||||||||||||||||||||
(d) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. | |||||||||||||||||||||||
(e) | 3.25% for 2014-2018 and 3.75% thereafter. | |||||||||||||||||||||||
(f) | 3.25% for 2013-2017 and 3.75% thereafter. | |||||||||||||||||||||||
Assumed health care cost trend rates impact the costs reported for Exelon's other postretirement benefit plans for participants populations with plan designs that do not have a cap on cost growth. 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 2014 total service and interest cost components | $ | 35 | ||||||||||||||||||||||
on postretirement benefit obligation at December 31, 2014 | 162 | |||||||||||||||||||||||
Effect of a one percentage point decrease in assumed health care cost trend: | ||||||||||||||||||||||||
on 2014 total service and interest cost components | (24 | ) | ||||||||||||||||||||||
on postretirement benefit obligation at December 31, 2014 | (113 | ) | ||||||||||||||||||||||
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 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 | |||||||||||||||||||||||
2014(c) | 2013 | 2012 | 2014 | 2013 | 2012 (a) | |||||||||||||||||||
Generation | $ | 173 | $ | 119 | $ | 48 | $ | 124 | $ | 30 | $ | 135 | ||||||||||||
ComEd | 122 | 118 | 25 | 125 | 4 | 119 | ||||||||||||||||||
PECO | 11 | 11 | 13 | 5 | 20 | 33 | ||||||||||||||||||
BGE (b) | — | — | — | 17 | 24 | 12 | ||||||||||||||||||
BSC(d) | 26 | 91 | 63 | 20 | 5 | 24 | ||||||||||||||||||
Exelon | $ | 332 | $ | 339 | $ | 149 | $ | 291 | $ | 83 | $ | 323 | ||||||||||||
_________________________ | ||||||||||||||||||||||||
(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. Effective January 1, 2013, Exelon is no longer receiving this subsidy. | |||||||||||||||||||||||
(b) | BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements. | |||||||||||||||||||||||
(c) | Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG. | |||||||||||||||||||||||
(d) | Includes $9 million, $72 million, and $13 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2014, 2013, and 2012, 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, until the plan is fully funded on an ABO basis, the projected contribution reflects a funding strategy of contributing $250 million. This level funding strategy helps minimize volatility of future period required pension contributions. | ||||||||||||||||||||||||
Exelon plans to contribute $447 million to its qualified pension plans in 2015, of which Generation, ComEd, PECO, and BGE will contribute $230 million, $138 million, $40 million, and $1 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $36 million related to the legacy CENG plans that will be funded by CENG as provided in an EMA between Exelon and CENG. | ||||||||||||||||||||||||
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 $15 million in 2015, of which Generation, ComEd, PECO, and BGE will make payments of $6 million, $1 million, $1 million and $1 million, respectively. | ||||||||||||||||||||||||
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 2015, 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 $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17 million, $2 million, $0 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, 2014 were: | ||||||||||||||||||||||||
Pension | Other | |||||||||||||||||||||||
Benefits | Postretirement | |||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||
2015 | $ | 1,064 | $ | 217 | ||||||||||||||||||||
2016 | 962 | 223 | ||||||||||||||||||||||
2017 | 979 | 230 | ||||||||||||||||||||||
2018 | 1,004 | 236 | ||||||||||||||||||||||
2019 | 1,032 | 247 | ||||||||||||||||||||||
2020 through 2024 | 5,825 | 1,373 | ||||||||||||||||||||||
Total estimated future benefit payments through 2024 | $ | 10,866 | $ | 2,526 | ||||||||||||||||||||
Allocation to Exelon Subsidiaries | ||||||||||||||||||||||||
Generation, ComEd, PECO, and BGE account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer 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. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated 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. Pension and postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon is allocating costs related to its legacy Exelon pension and postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are being allocated based on accounting cost. The impact of this allocation methodology change is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, 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, 2014, 2013 and 2012, 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 | ||||||||||||||||||
2014 | $ | 250 | $ | 162 | $ | 36 | $ | 46 | $ | 67 | 561 | |||||||||||||
2013 | 347 | 309 | 43 | 71 | 55 | 825 | ||||||||||||||||||
2012 | 341 | 282 | 50 | 99 | 60 | 820 | ||||||||||||||||||
_____________________ | ||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||
(b) | The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 2012. | |||||||||||||||||||||||
(c) | 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 6.46% to estimate its 2015 pension and other postretirement benefit costs, respectively. | ||||||||||||||||||||||||
Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2014 and 2013 asset allocations were as follows: | ||||||||||||||||||||||||
Pension Plans | ||||||||||||||||||||||||
Percentage of Plan Assets | ||||||||||||||||||||||||
at December 31, | ||||||||||||||||||||||||
Asset Category | Target Allocation | 2014 | 2013 | |||||||||||||||||||||
Equity securities | 32 | % | 33 | % | 35 | % | ||||||||||||||||||
Fixed income securities | 37 | % | 37 | 37 | ||||||||||||||||||||
Alternative investments (a) | 31 | % | 30 | 28 | ||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||
Other Postretirement Benefit Plans | ||||||||||||||||||||||||
Percentage of Plan Assets | ||||||||||||||||||||||||
at December 31, | ||||||||||||||||||||||||
Asset Category | Target Allocation | 2014 | 2013 | |||||||||||||||||||||
Equity securities | 41 | % | 42 | % | 45 | % | ||||||||||||||||||
Fixed income securities | 34 | % | 34 | 37 | ||||||||||||||||||||
Alternative investments (a) | 25 | % | 24 | 18 | ||||||||||||||||||||
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, 2014. 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, 2014, there were no significant concentrations (defined as greater than 10% 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, 2014 and 2013: | ||||||||||||||||||||||||
At December 31, 2014 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Pension plan assets | ||||||||||||||||||||||||
Cash equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 1,556 | 1,133 | 2 | 2,691 | ||||||||||||||||||||
Foreign | 1,705 | 316 | — | 2,021 | ||||||||||||||||||||
Equities subtotal | 3,261 | 1,449 | 2 | 4,712 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 1,051 | 88 | — | 1,139 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 80 | — | 80 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Corporate debt securities | — | 3,125 | 120 | 3,245 | ||||||||||||||||||||
Other | — | 942 | 152 | 1,094 | ||||||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||||||
Assets | — | 4 | — | 4 | ||||||||||||||||||||
Liabilities | — | (16 | ) | — | (16 | ) | ||||||||||||||||||
Fixed income subtotal | 1,051 | 4,223 | 272 | 5,546 | ||||||||||||||||||||
Private equity | — | — | 904 | 904 | ||||||||||||||||||||
Hedge funds | — | 1,355 | 1,329 | 2,684 | ||||||||||||||||||||
Real estate | 243 | — | 744 | 987 | ||||||||||||||||||||
Pension plan assets subtotal | 4,556 | 7,027 | 3,251 | 14,834 | ||||||||||||||||||||
At December 31, 2014 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||||||
Cash equivalents | 11 | — | — | 11 | ||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 296 | 378 | — | 674 | ||||||||||||||||||||
Foreign | 184 | 147 | — | 331 | ||||||||||||||||||||
Equities subtotal | 480 | 525 | — | 1,005 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 15 | 59 | — | 74 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 197 | — | 197 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Corporate debt securities | — | 42 | — | 42 | ||||||||||||||||||||
Other | 253 | 272 | — | 525 | ||||||||||||||||||||
Fixed income subtotal | 268 | 570 | — | 838 | ||||||||||||||||||||
Hedge funds | — | 339 | 110 | 449 | ||||||||||||||||||||
Real estate | 8 | — | 116 | 124 | ||||||||||||||||||||
Other postretirement benefit plan assets subtotal | 767 | 1,434 | 226 | 2,427 | ||||||||||||||||||||
Total pension and other postretirement benefit plan assets (c) | $ | 5,323 | $ | 8,461 | $ | 3,477 | $ | 17,261 | ||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Pension plan assets | ||||||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | $ | 1,587 | $ | 865 | $ | 2 | $ | 2,454 | ||||||||||||||||
Foreign | 1,773 | 302 | — | 2,075 | ||||||||||||||||||||
Equities subtotal | 3,360 | 1,167 | 2 | 4,529 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 908 | 99 | — | 1,007 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 88 | — | 88 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Foreign debt securities | — | 205 | — | 205 | ||||||||||||||||||||
Corporate debt securities | — | 2,927 | 41 | 2,968 | ||||||||||||||||||||
Other | 5 | 899 | — | 904 | ||||||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||||||
Assets | — | 7 | — | 7 | ||||||||||||||||||||
Liabilities | — | (134 | ) | — | (134 | ) | ||||||||||||||||||
Fixed income subtotal | 913 | 4,091 | 41 | 5,045 | ||||||||||||||||||||
Private equity | — | — | 806 | 806 | ||||||||||||||||||||
Hedge funds | — | 1,266 | 1,039 | 2,305 | ||||||||||||||||||||
Real estate | 264 | 2 | 582 | 848 | ||||||||||||||||||||
Pension plan assets subtotal | 4,537 | 6,526 | 2,470 | 13,533 | ||||||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||||||
Cash equivalents | 51 | — | — | 51 | ||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 296 | 345 | — | 641 | ||||||||||||||||||||
Foreign | 154 | 170 | — | 324 | ||||||||||||||||||||
Equities subtotal | 450 | 515 | — | 965 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 17 | 46 | — | 63 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 149 | — | 149 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Foreign debt securities | — | 2 | — | 2 | ||||||||||||||||||||
Corporate debt securities | — | 50 | — | 50 | ||||||||||||||||||||
Other | 305 | 225 | — | 530 | ||||||||||||||||||||
Fixed income subtotal | 322 | 472 | — | 794 | ||||||||||||||||||||
Private equity | — | — | 2 | 2 | ||||||||||||||||||||
Hedge funds | — | 295 | 4 | 299 | ||||||||||||||||||||
Real estate | 8 | 5 | 109 | 122 | ||||||||||||||||||||
Other postretirement benefit plan assets subtotal | 831 | 1,287 | 115 | 2,233 | ||||||||||||||||||||
Total pension and other postretirement benefit | $ | 5,368 | $ | 7,813 | $ | 2,585 | $ | 15,766 | ||||||||||||||||
plan assets (c) | ||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||
(a) | See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. | |||||||||||||||||||||||
(b) | Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, 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. | |||||||||||||||||||||||
(c) | Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, 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, 2014 and 2013: | ||||||||||||||||||||||||
Hedge | Private | Real | Fixed | Equities | Total | |||||||||||||||||||
funds | equity | estate | income | |||||||||||||||||||||
Pension Assets | ||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 1,039 | $ | 806 | $ | 582 | $ | 41 | $ | 2 | $ | 2,470 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 77 | 112 | 83 | 7 | — | 279 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Relating to assets sold during the | 3 | — | — | — | — | 3 | ||||||||||||||||||
period | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 311 | 173 | 136 | 227 | — | 847 | ||||||||||||||||||
Sales | (38 | ) | — | (19 | ) | (3 | ) | — | (60 | ) | ||||||||||||||
Settlements (a) | (33 | ) | (203 | ) | (65 | ) | — | — | (301 | ) | ||||||||||||||
Transfers into (out of) Level 3 (b)(c) | (30 | ) | 16 | 27 | — | — | 13 | |||||||||||||||||
Balance as of December 31, 2014 | $ | 1,329 | $ | 904 | $ | 744 | $ | 272 | $ | 2 | $ | 3,251 | ||||||||||||
Other Postretirement Benefits | ||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 4 | $ | 2 | $ | 109 | $ | — | $ | — | $ | 115 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 1 | — | 13 | — | — | 14 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 109 | 1 | 1 | — | — | 111 | ||||||||||||||||||
Sales | (4 | ) | (2 | ) | (7 | ) | — | — | (13 | ) | ||||||||||||||
Settlements (a) | — | (1 | ) | — | — | — | (1 | ) | ||||||||||||||||
Balance as of December 31, 2014 | $ | 110 | $ | — | $ | 116 | $ | — | $ | — | $ | 226 | ||||||||||||
Hedge | Private | Real | Fixed | Equities | Total | |||||||||||||||||||
funds | equity | estate | income | |||||||||||||||||||||
Pension Assets | ||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 1,235 | $ | 754 | $ | 426 | $ | — | $ | — | $ | 2,415 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 143 | 86 | 63 | — | — | 292 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Relating to assets sold during the | 3 | — | (4 | ) | — | — | (1 | ) | ||||||||||||||||
period | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 360 | 123 | 226 | 41 | 2 | 752 | ||||||||||||||||||
Sales | (76 | ) | — | (91 | ) | — | — | (167 | ) | |||||||||||||||
Settlements (a) | (3 | ) | (157 | ) | (38 | ) | — | — | (198 | ) | ||||||||||||||
Transfers into (out of) Level 3 (c) | (623 | ) | — | — | — | — | (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 | $ | — | $ | — | $ | 108 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 1 | — | 11 | — | — | 12 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | — | 1 | 3 | — | — | 4 | ||||||||||||||||||
Sales | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Settlements (a) | (4 | ) | — | — | — | — | (4 | ) | ||||||||||||||||
Transfers into (out of) Level 3 (c) | (4 | ) | — | — | — | — | (4 | ) | ||||||||||||||||
Balance as of December 31, 2013 | $ | 4 | $ | 2 | $ | 109 | $ | — | $ | — | $ | 115 | ||||||||||||
________________________ | ||||||||||||||||||||||||
(a) | Represents cash settlements only. | |||||||||||||||||||||||
(b) | In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million. | |||||||||||||||||||||||
(c) | As of January 1, 2014 and January 1, 2013, 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, 2014 and 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 $43 million and $627 million in 2014 and 2013 respectively. | |||||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the twelve months ended December 31, 2014 for the pension and other postretirement benefit plan assets. | ||||||||||||||||||||||||
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. | ||||||||||||||||||||||||
Equities. Equities consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. 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 Exelon is able to independently corroborate. Equity securities held individually, including rights and warrants, 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 the plans’ 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 NAV 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 remaining fixed income securities, including certain other fixed income investments, 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 | ||||||||||||||||||||||||
Other fixed income investments primarily consist of fixed income commingled funds, mutual funds, and short-term investment funds, which 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 NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using the NAV per fund share, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds have been categorized as Level 3. | ||||||||||||||||||||||||
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. | ||||||||||||||||||||||||
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 NAV 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. | ||||||||||||||||||||||||
As of December 31, 2014, Exelon has outstanding commitments to invest in private equity and real estate investments of approximately $825 million. These commitments will be funded by Exelon’s existing pension and other postretirement benefit trusts. | ||||||||||||||||||||||||
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 and after-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, 2014, 2013 and 2012: | ||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | PECO | BGE (a) | BSC (b) | ||||||||||||||||||
2014 | $ | 103 | $ | 51 | $ | 26 | $ | 8 | $ | 8 | $ | 10 | ||||||||||||
2013 | 85 | 40 | 22 | 8 | 8 | 7 | ||||||||||||||||||
2012 | 67 | 30 | 19 | 7 | 7 | 5 | ||||||||||||||||||
_________________________ | ||||||||||||||||||||||||
(a) | BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012. | |||||||||||||||||||||||
(b) | 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_Exelon_Generation_Co
Severance (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Restructuring and Related Activities [Abstract] | |||||||||||||||||||||
Severance (Exelon, Generation, ComEd and PECO) | 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. | |||||||||||||||||||||
CENG Integration-Related Severance | |||||||||||||||||||||
In connection with the Master Agreement, Generation and CENG recorded a severance accrual in the fourth quarter of 2013 for the anticipated employee position reductions as a result of the integration of $2 million and $16 million, respectively. The majority of these positions are corporate and support positions at CENG. On April 1, 2014, the date the NOSA was executed, Generation consolidated the $19 million CENG severance liability pursuant to the Master Agreement. For the years ended December 31, 2014 and 2013, respectively, Exelon and Generation recorded severance benefit costs associated with the employee reductions of $3 million and $2 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The estimated amount of severance payments associated with this plan is expected to be approximately $24 million. As of December 31, 2014, management recorded its best estimate of severance benefits, which could be adjusted through the completion of the integration process if additional employee position reductions are identified or if employees resign prior to their agreed upon service termination date. Estimated costs to be incurred after December 31, 2014 are not material. | |||||||||||||||||||||
Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration: | |||||||||||||||||||||
Year Ended December 31, 2014 | Exelon and Generation | ||||||||||||||||||||
Severance Liability | |||||||||||||||||||||
Balance at December 31, 2013 | $ | 2 | |||||||||||||||||||
Integration of CENG (a) | 19 | ||||||||||||||||||||
Severance charges | 3 | ||||||||||||||||||||
Payments | (11 | ) | |||||||||||||||||||
Balance at December 31, 2014 | $ | 13 | |||||||||||||||||||
______________________ | |||||||||||||||||||||
(a) | Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||
Cash payments under the severance plan began in 2014. Substantially all cash payments under the plan are expected to be made by the end of 2015. | |||||||||||||||||||||
Constellation 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. | |||||||||||||||||||||
The amount of severance expense associated with the post-merger integration recognized for the twelve months ended December 31, 2014 and 2013 is not material. Estimated costs to be incurred after December 31, 2014 are not immaterial. | |||||||||||||||||||||
For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, 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 | — | 1 | ||||||||||||||||
Other charges | 7 | 4 | 1 | — | 1 | ||||||||||||||||
Total severance benefits | $ | 138 | $ | 88 | $ | 16 | $ | 7 | $ | 19 | |||||||||||
________________________ | |||||||||||||||||||||
(a) | 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. | ||||||||||||||||||||
(b) | 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, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | — | $ | 11 | |||||||||||
Severance charges (a) | 5 | 1 | — | — | — | ||||||||||||||||
Stock compensation | 1 | — | — | — | — | ||||||||||||||||
Payments | (64 | ) | (24 | ) | (1 | ) | — | (5 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | — | $ | — | $ | 6 | |||||||||||
Payments | (41 | ) | (7 | ) | — | — | (4 | ) | |||||||||||||
Balance at December 31, 2014 | $ | 12 | $ | 3 | $ | — | $ | — | $ | 2 | |||||||||||
________________________ | |||||||||||||||||||||
(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, 2014 and December 31, 2013. | ||||||||||||||||||||
Substantially all cash payments under the plan are expected to be made by the end of 2016. | |||||||||||||||||||||
Ongoing Severance Plans | |||||||||||||||||||||
The Registrants provide severance, 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 or with the integration of CENG. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated. | |||||||||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income: | |||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Severance Charges-2014 | $ | 7 | $ | 5 | $ | 1 | $ | — | $ | 1 | |||||||||||
Severance Charges-2013 | 18 | 16 | 2 | — | — | ||||||||||||||||
Severance Charges-2012 | 19 | 14 | 2 | 1 | 3 | ||||||||||||||||
________________________ | |||||||||||||||||||||
(a) | The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material. | ||||||||||||||||||||
(b) | The amount of ongoing severance for Generation for the year ended December 31, 2014 includes a $3 million severance reserve as a result of anticipated employee position reductions due to recent acquisitions. | ||||||||||||||||||||
The severance liability balances associated with these ongoing severance benefits as of December 31, 2014 and 2013 are not material. |
Preferred_and_Preference_Secur
Preferred and Preference Securities (Exelon, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Equity [Abstract] | ||||||||||||||||||
Preferred and Preference Securities (Exelon, ComEd, PECO and BGE) | Preferred and Preference Securities (Exelon, ComEd, PECO and BGE) | |||||||||||||||||
At December 31, 2014 and 2013, 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, 2014 and 2013, 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. | ||||||||||||||||||
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 was 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. | ||||||||||||||||||
At December 31, 2014 and 2013, 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 | 2014 | 2013 | 2014 | 2013 | ||||||||||||||
Price (a) | 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 | 400,000 | 400,000 | 40 | 40 | |||||||||||||
6.99%, 1995 Series | 100.35 | 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, 2014 | |||||||||||||
Common Stock [Abstract] | |||||||||||||
Common Stock (Exelon, Generation, ComEd, PECO and BGE) | Common Stock (Exelon, Generation, ComEd, PECO and BGE) | ||||||||||||
The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Par Value | Shares Authorized | Shares Outstanding | |||||||||||
Common Stock | |||||||||||||
Exelon | no par value | 2,000,000,000 | 859,833,343 | 857,290,484 | |||||||||
ComEd | $ | 12.5 | 250,000,000 | 127,016,947 | 127,016,896 | ||||||||
PECO | no par value | 500,000,000 | 170,478,507 | 170,478,507 | |||||||||
BGE | no par value | 175,000,000 | 1,000 | 1,000 | |||||||||
ComEd had 73,533 and 73,709 warrants outstanding to purchase ComEd common stock at December 31, 2014 and 2013, 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, 2014 and 2013, 24,511 and 24,570 shares of common stock, respectively, were reserved for the conversion of warrants. | |||||||||||||
Equity Securities Offering | |||||||||||||
In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements requiring Exelon to, at its election, prior to October 29, 2015; i) physically settle the transaction through the issuance of 57.5 million shares of its common stock in exchange for net proceeds at the forward price specified in the agreements of between approximately $1.8 billion and $1.9 billion, after consideration of underwriters discount of approximately $60 million and subject to certain adjustments as provided in the forward sales agreement, or ii) net settle the transaction either through the payment of cash or shares of its common stock based on the then current market value of the shares minus the value of the shares at the forward price, net of the underwriters discount and the daily accretion rate. No amounts have or will be recorded in Exelon’s consolidated financial statements with respect to the equity offering until settlement of the forward sale agreements occurs. If Exelon elected to net share settle the contract as of December 31, 2014, Exelon would have been required to issue 4 million shares. If Exelon elects to cash settle the contract, the transaction costs will be recorded as a charge to earnings in the period in which it becomes probable that Exelon will cash settle. Otherwise, all transaction costs will be reflected as a reduction to the value of the common stock issued in Exelon’s Consolidated Balance Sheet. The net proceeds received upon settlement are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes. Until settlement, earnings per share dilution resulting from the forward sales agreement, if any, will be determined under the treasury stock method. | |||||||||||||
Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 13 — Debt and Credit Agreements for further information on the equity units. | |||||||||||||
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, 2014. During 2014, 2013 and 2012, 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, 2014, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2014, 2013 and 2012, 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 67% performance shares and 33% restricted stock units. 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 vested one-third after one year, with the remaining balance vesting over a two-year performance period. These one-time 2013 performance share transition awards 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 Exelon stock ownership requirements are satisfied. In addition to this change, in 2013 ComEd and in 2014 PECO and BGE transitioned from Exelon stock-based awards to cash award programs with payouts based on the performance of each respective utility. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable accounting guidance. | |||||||||||||
The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||
Year Ended | |||||||||||||
December 31, | |||||||||||||
Components of Stock-Based Compensation Expense | 2014 | 2013 | 2012 | ||||||||||
Performance share awards | $ | 59 | $ | 48 | $ | 46 | |||||||
Restricted stock units | 61 | 61 | 50 | ||||||||||
Stock options | 2 | 3 | 15 | ||||||||||
Other stock-based awards | 5 | 6 | 4 | ||||||||||
Total stock-based compensation expense included in operating and | 127 | 118 | 115 | ||||||||||
maintenance expense | |||||||||||||
Income tax benefit | (47 | ) | (44 | ) | (44 | ) | |||||||
Total after-tax stock-based compensation expense | $ | 80 | $ | 74 | $ | 71 | |||||||
The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||
Year Ended | |||||||||||||
December 31, | |||||||||||||
Subsidiaries | 2014 | 2013 | 2012 (a) | ||||||||||
Generation | $ | 52 | $ | 48 | $ | 42 | |||||||
ComEd | 7 | 9 | 11 | ||||||||||
PECO | 3 | 5 | 5 | ||||||||||
BGE | 5 | 6 | 5 | ||||||||||
BSC (b) | 60 | 50 | 52 | ||||||||||
Total | $ | 127 | $ | 118 | $ | 115 | |||||||
________________________ | |||||||||||||
(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 table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary 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. | ||||||||||||
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2014, 2013 and 2012. | |||||||||||||
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, 2014, 2013 and 2012: | |||||||||||||
Year Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Realized tax benefit when exercised/distributed: | |||||||||||||
Stock options | $ | — | $ | — | $ | 3 | |||||||
Restricted stock units | 17 | 11 | 11 | ||||||||||
Performance share awards | 11 | 11 | 7 | ||||||||||
Stock deferral plan | — | 1 | — | ||||||||||
Excess tax benefits included in other financing activities of Exelon’s | |||||||||||||
Consolidated Statements of Cash Flows: | |||||||||||||
Stock options | $ | — | $ | — | $ | 2 | |||||||
Stock Options | |||||||||||||
Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2013 or 2014. For all stock options granted through 2012, 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. | |||||||||||||
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. | |||||||||||||
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 year ended 2012: | |||||||||||||
Year ended December 31, 2012 | |||||||||||||
Dividend yield | 5.28 | % | |||||||||||
Expected volatility | 23.2 | % | |||||||||||
Risk-free interest rate | 1.3 | % | |||||||||||
Expected life (years) | 6.25 | ||||||||||||
Weighted average grant date fair value (per share) | 4.18 | ||||||||||||
The assumptions above relate to Exelon stock options granted in 2012 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, 2014: | |||||||||||||
Shares | Weighted | Weighted | Aggregate | ||||||||||
Average | Average | Intrinsic | |||||||||||
Exercise | Remaining | Value | |||||||||||
Price | Contractual | ||||||||||||
(per | Life | ||||||||||||
share) | (years) | ||||||||||||
Balance of shares outstanding at December 31, 2013 | 21,035,445 | $ | 46.07 | ||||||||||
Options exercised | (291,805 | ) | 25.27 | ||||||||||
Options forfeited | (8,886 | ) | 55.78 | ||||||||||
Options expired | (1,903,787 | ) | 41.47 | ||||||||||
Balance of shares outstanding at December 31, 2014 | 18,830,967 | $ | 46.85 | 4.11 | $ | 29 | |||||||
Exercisable at December 31, 2014 (a) | 18,398,932 | $ | 47.01 | 4.04 | $ | 29 | |||||||
____________________ | |||||||||||||
(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, 2014, 2013 and 2012: | |||||||||||||
Year Ended | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Intrinsic value(a) | $ | 3 | $ | 4 | $ | 19 | |||||||
Cash received for exercise price | 7 | 19 | 47 | ||||||||||
______________________ | |||||||||||||
(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, 2014: | |||||||||||||
Shares | Weighted Average | ||||||||||||
Exercise Price | |||||||||||||
(per share) | |||||||||||||
Nonvested at December 31, 2013 (a) | 847,118 | $ | 40.22 | ||||||||||
Vested | (406,197 | ) | 40.21 | ||||||||||
Forfeited | (8,886 | ) | 55.78 | ||||||||||
Nonvested at December 31, 2014 (a) | 432,035 | $ | 39.91 | ||||||||||
_____________________ | |||||||||||||
(a) | Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | ||||||||||||
At December 31, 2014, $1 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.0 year. | |||||||||||||
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, 2014: | |||||||||||||
Shares | Weighted Average | ||||||||||||
Grant Date Fair | |||||||||||||
Value (per share) | |||||||||||||
Nonvested at December 31, 2013 (a) | 3,386,697 | $ | 34.1 | ||||||||||
Granted | 2,252,574 | 28.71 | |||||||||||
Vested | (1,216,016 | ) | 35.36 | ||||||||||
Forfeited | (86,094 | ) | 31.99 | ||||||||||
Undistributed vested awards (b) | (578,943 | ) | 29.17 | ||||||||||
Nonvested at December 31, 2014 (a) | 3,758,218 | $ | 31.27 | ||||||||||
_______________________ | |||||||||||||
(a) | Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | ||||||||||||
(b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014. | ||||||||||||
The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2014, 2013 and 2012 was $28.71, $31.06 and $39.94, respectively. At December 31, 2014 and 2013, Exelon had obligations related to outstanding restricted stock units not yet settled of $85 million and $77 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2014, 2013 and 2012, Exelon settled restricted stock units with fair value totaling $43 million, $28 million and $25 million, respectively. At December 31, 2014, $59 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.1 years. | |||||||||||||
Performance Share Awards | |||||||||||||
Performance share awards are granted under the LTIP. The 2014 and 2013 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 common stock portion of the performance share and one-time 2013 performance share transition awards is considered an equity award and is 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. | |||||||||||||
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, 2014: | |||||||||||||
Shares | Weighted Average | ||||||||||||
Grant Date Fair | |||||||||||||
Value (per share) | |||||||||||||
Nonvested at December 31, 2013 (a) | 2,014,190 | $ | 32.74 | ||||||||||
Granted | 1,712,085 | 28.75 | |||||||||||
Change in performance | 98,227 | 31.85 | |||||||||||
Vested | (497,714 | ) | 35.05 | ||||||||||
Forfeited | (29,476 | ) | 30.16 | ||||||||||
Undistributed vested awards (b) | (601,215 | ) | 28.96 | ||||||||||
Nonvested at December 31, 2014 (a) | 2,696,097 | $ | 30.62 | ||||||||||
_______________________ | |||||||||||||
(a) | Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | ||||||||||||
(b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014. | ||||||||||||
The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2014, 2013 and 2012 was $28.75, $31.55, and $39.71, respectively. During the years ended December 31, 2014, 2013 and 2012, Exelon settled performance shares with a fair value totaling $27 million, $26 million and $23 million, respectively, of which $13 million, $12 million and $3 million was paid in cash, respectively. As of December 31, 2014, $54 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years. | |||||||||||||
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled: | |||||||||||||
December 31, | |||||||||||||
2014 | 2013 | ||||||||||||
Current liabilities(a) | $ | 28 | $ | 13 | |||||||||
Deferred credits and other liabilities (b) | 36 | 24 | |||||||||||
Common stock | 33 | 32 | |||||||||||
Total | $ | 97 | $ | 69 | |||||||||
__________________________ | |||||||||||||
(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, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Earnings Per Share and Equity (Exelon) | Earnings Per Share and Equity (Exelon) | |||||||||||
Earnings per Share | ||||||||||||
Diluted earnings per share is calculated by dividing Net income attributable to common shareholders 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 the 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net income attributable to common shareholders | $ | 1,623 | $ | 1,719 | $ | 1,160 | ||||||
Weighted average common shares outstanding—basic | 860 | 856 | 816 | |||||||||
Assumed exercise and/or distributions of stock-based awards | 4 | 4 | 3 | |||||||||
Weighted average common shares outstanding—diluted | 864 | 860 | 819 | |||||||||
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 17 million in 2014, 20 million in 2013, and 14 million in 2012. The number of equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the year ended December 31, 2014 since issuance. Additionally, there were no forward units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the year ended December 31, 2014 since issuance. Refer to Note 19 — Common Stock for further information regarding the equity units and equity forward units. | ||||||||||||
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, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases. |
Changes_in_Accumulated_Other_C
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Equity [Abstract] | ||||||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO) | Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO) | |||||||||||||||||||||||
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014 and 2013: | ||||||||||||||||||||||||
For the Year Ended December 31, 2014 | Gains and | Unrealized | Pension and | Foreign | AOCI of | Total | ||||||||||||||||||
(Losses) on | Gains and | Non-Pension | Currency | Equity | ||||||||||||||||||||
Cash Flow | (Losses) on | Postretirement | Items | Investments | ||||||||||||||||||||
Hedges | Marketable | Benefit Plan | ||||||||||||||||||||||
Securities | items | |||||||||||||||||||||||
Exelon (a) | ||||||||||||||||||||||||
Beginning balance | $ | 120 | $ | 2 | $ | (2,260 | ) | $ | (10 | ) | $ | 108 | $ | (2,040 | ) | |||||||||
OCI before reclassifications | (31 | ) | (1 | ) | (498 | ) | (9 | ) | 11 | (528 | ) | |||||||||||||
Amounts reclassified from AOCI (b) | (117 | ) | 2 | 118 | — | (119 | ) | (116 | ) | |||||||||||||||
Net current-period OCI | (148 | ) | 1 | (380 | ) | (9 | ) | (108 | ) | (644 | ) | |||||||||||||
Ending balance | $ | (28 | ) | $ | 3 | $ | (2,640 | ) | $ | (19 | ) | $ | — | $ | (2,684 | ) | ||||||||
Generation (a) | ||||||||||||||||||||||||
Beginning balance | $ | 114 | $ | 2 | $ | — | $ | (10 | ) | $ | 108 | $ | 214 | |||||||||||
OCI before reclassifications | (15 | ) | (1 | ) | — | (9 | ) | 11 | (14 | ) | ||||||||||||||
Amounts reclassified from AOCI (b) | (117 | ) | — | — | — | (119 | ) | (236 | ) | |||||||||||||||
Net current-period OCI | (132 | ) | (1 | ) | — | (9 | ) | (108 | ) | (250 | ) | |||||||||||||
Ending balance | $ | (18 | ) | $ | 1 | $ | — | $ | (19 | ) | $ | — | $ | (36 | ) | |||||||||
PECO (a) | ||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
OCI before reclassifications | — | — | — | — | — | — | ||||||||||||||||||
Amounts reclassified from AOCI (b) | — | — | — | — | — | — | ||||||||||||||||||
Net current-period OCI | — | — | — | — | — | — | ||||||||||||||||||
Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
For the Year Ended December 31, 2013 | Gains and | Unrealized | Pension and | Foreign | AOCI of | Total | ||||||||||||||||||
(Losses) on | Gains and | Non-Pension | Currency | Equity | ||||||||||||||||||||
Cash Flow | (Losses) on | Postretirement | Items | Investments | ||||||||||||||||||||
Hedges | Marketable | Benefit Plan | ||||||||||||||||||||||
Securities | items | |||||||||||||||||||||||
Exelon (a) | ||||||||||||||||||||||||
Beginning balance | $ | 368 | $ | — | $ | (3,137 | ) | $ | — | $ | 2 | $ | (2,767 | ) | ||||||||||
OCI before reclassifications | 29 | 2 | 669 | (10 | ) | 101 | 791 | |||||||||||||||||
Amounts reclassified from AOCI (b) | (277 | ) | — | 208 | — | 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 | $ | — | $ | — | $ | — | $ | 1 | 513 | |||||||||||||
OCI before reclassifications | 15 | 2 | — | (10 | ) | 102 | 109 | |||||||||||||||||
Amounts reclassified from AOCI (b) | (413 | ) | — | — | — | 5 | (408 | ) | ||||||||||||||||
Net current-period OCI | (398 | ) | 2 | — | (10 | ) | 107 | (299 | ) | |||||||||||||||
Ending balance | $ | 114 | $ | 2 | $ | — | $ | (10 | ) | $ | 108 | $ | 214 | |||||||||||
PECO (a) | ||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
OCI before reclassifications | — | — | — | — | — | — | ||||||||||||||||||
Amounts reclassified from AOCI (b) | — | — | — | — | — | — | ||||||||||||||||||
Net current-period OCI | — | — | — | — | — | — | ||||||||||||||||||
Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||||||||||||||||||||
(b) | See next tables for details about these reclassifications. | |||||||||||||||||||||||
ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2014 and 2013. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2014 and 2013: | ||||||||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the Statements of Operations and Comprehensive Income | ||||||||||||||||||||||
Exelon | Generation | |||||||||||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||||||||||
Energy related hedges | $ | 195 | $ | 195 | Operating revenues | |||||||||||||||||||
195 | 195 | Total before tax | ||||||||||||||||||||||
(78 | ) | (78 | ) | Tax expense | ||||||||||||||||||||
$ | 117 | $ | 117 | Net of tax | ||||||||||||||||||||
Gains and (losses) on available | ||||||||||||||||||||||||
for sale securities | ||||||||||||||||||||||||
Other available securities for sale | $ | (2 | ) | $ | — | Other Income and Deductions | ||||||||||||||||||
$ | (2 | ) | $ | — | Net of tax | |||||||||||||||||||
Amortization of pension and other | ||||||||||||||||||||||||
postretirement benefit plan items | ||||||||||||||||||||||||
Prior service costs (b) | $ | 46 | $ | — | ||||||||||||||||||||
Actuarial losses (b) | (239 | ) | — | |||||||||||||||||||||
(193 | ) | — | Total before tax | |||||||||||||||||||||
75 | — | Tax benefit | ||||||||||||||||||||||
$ | (118 | ) | $ | — | Net of tax | |||||||||||||||||||
Equity investments | ||||||||||||||||||||||||
Sale of equity method investment | $ | 5 | $ | 5 | ||||||||||||||||||||
Reversal of CENG equity method AOCI | 193 | 193 | Equity in losses of unconsolidated affiliates | |||||||||||||||||||||
198 | 198 | Total before tax | ||||||||||||||||||||||
(79 | ) | (79 | ) | Tax expense | ||||||||||||||||||||
$ | 119 | $ | 119 | Net of tax | ||||||||||||||||||||
Total Reclassifications | $ | 116 | $ | 236 | Net of tax | |||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the Statements of Operations and Comprehensive Income | ||||||||||||||||||||||
Exelon | Generation | |||||||||||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||||||||||
Energy related hedges | $ | 464 | $ | 683 | Operating revenues | |||||||||||||||||||
Other cash flow hedges | (3 | ) | — | Interest expense | ||||||||||||||||||||
461 | 683 | Total before tax | ||||||||||||||||||||||
(184 | ) | (270 | ) | Tax expense | ||||||||||||||||||||
$ | 277 | $ | 413 | Net of tax | ||||||||||||||||||||
Amortization of pension and other | ||||||||||||||||||||||||
postretirement benefit plan items | ||||||||||||||||||||||||
Prior service costs (b) | $ | (2 | ) | $ | — | |||||||||||||||||||
Actuarial losses (b) | (339 | ) | — | |||||||||||||||||||||
Deferred compensation unit plan (c) | (1 | ) | — | |||||||||||||||||||||
(342 | ) | — | Total before tax | |||||||||||||||||||||
134 | — | Tax benefit | ||||||||||||||||||||||
$ | (208 | ) | $ | — | 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 — Retirement Benefits for additional details). | |||||||||||||||||||||||
(c) | Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. | |||||||||||||||||||||||
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2014 and 2013: | ||||||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | 19 | $ | — | $ | (1 | ) | |||||||||||||||||
Actuarial loss reclassified to periodic cost | (93 | ) | (133 | ) | (110 | ) | ||||||||||||||||||
Transition obligation reclassified to periodic cost | — | — | (2 | ) | ||||||||||||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | 317 | (430 | ) | 237 | ||||||||||||||||||||
Change in unrealized loss on cash flow hedges | 96 | 166 | 68 | |||||||||||||||||||||
Change in marketable securities | — | — | 1 | |||||||||||||||||||||
Change in unrealized income on equity investments | 73 | (71 | ) | (1 | ) | |||||||||||||||||||
Total | $ | 412 | $ | (468 | ) | $ | 192 | |||||||||||||||||
Generation | ||||||||||||||||||||||||
Change in unrealized loss on cash flow hedges | $ | 84 | $ | 262 | $ | 262 | ||||||||||||||||||
Change in unrealized income on equity investments | 73 | (72 | ) | 1 | ||||||||||||||||||||
Total | $ | 157 | $ | 190 | $ | 263 | ||||||||||||||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Commitments and Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE) | 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 mitigated 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, 2014, 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 $2.7 billion, including CENG's related liability. | ||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||
As part of the execution of NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to 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 guarantees Generation’s obligations under this indemnity. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG. | ||||||||||||||||||||||||||||
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 2014 and 2013, of which Generation’s portion was $18.3 million and $18.5 million respectively. No distributions were declared in 2012. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. 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, 2014, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $319 million. 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. | ||||||||||||||||||||||||||||
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. 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. 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. | ||||||||||||||||||||||||||||
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 historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court 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 May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. For the year ended December 31, 2014, and for the year ended December 31, 2013, Generation incurred expense of $49 million and $136 million, respectively, in SNF disposal fees, recorded in Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. 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 has been, and is expected to be, delayed significantly. | ||||||||||||||||||||||||||||
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, Quad Cities, Ginna, Nine Mile Point, and Calvert Cliffs 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. Settlement agreements pertaining to Calvert Cliffs and Ginna were executed during 2011, and Nine Mile Point during 2012, (the “DOE Settlement Agreements”), as amended in 2014 for Calvert Cliffs and Nine Mile Point, under which the government has agreed to reimburse the costs associated with SNF storage expended or to be expended through 2016 as a result of the DOE delays. The DOE Settlement Agreement is expected to be amended for Ginna in a similar manner as needed. Generation, including CENG, 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 cumulative cash reimbursements for costs incurred as follows: | ||||||||||||||||||||||||||||
Total | Net (a) | |||||||||||||||||||||||||||
Cumulative cash reimbursements (b) | $ | 836 | $ | 702 | ||||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(a) | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. | |||||||||||||||||||||||||||
(b) | Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG. | |||||||||||||||||||||||||||
As of December 31, 2014, and 2013, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: | ||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||
DOE receivable - current (a) | $ | 82 | $ | 71 | ||||||||||||||||||||||||
DOE receivable - noncurrent (b) | 7 | — | ||||||||||||||||||||||||||
Amounts owed to co-owners (a)(c) | (5 | ) | (18 | ) | ||||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(a) | Recorded in Accounts receivable, other. | |||||||||||||||||||||||||||
(b) | Recorded in Deferred debits and other assets, other | |||||||||||||||||||||||||||
(c) | Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. | |||||||||||||||||||||||||||
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, 2014, 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, 2014, was 0.020%. 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 Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial 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. | ||||||||||||||||||||||||||||
At December 31, 2014, 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 | Total | |||||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | ||||||||||||||||||||||||||
2015 | $ | 418 | $ | 152 | $ | 20 | $ | 590 | ||||||||||||||||||||
2016 | 283 | 228 | 15 | 526 | ||||||||||||||||||||||||
2017 | 222 | 121 | 15 | 358 | ||||||||||||||||||||||||
2018 | 112 | 29 | 16 | 157 | ||||||||||||||||||||||||
2019 | 117 | 5 | 16 | 138 | ||||||||||||||||||||||||
Thereafter | 279 | 1 | 35 | 315 | ||||||||||||||||||||||||
Total | $ | 1,431 | $ | 536 | $ | 117 | $ | 2,084 | ||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(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, 2014, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of December 31, 2014, capacity offsets were $132 million, $133 million, $136 million, $137 million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. 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. | ||||||||||||||||||||||||||||
PECO has entered into contracts through a competitive procurement process in order to meet a portion of its default service customers’ electric supply requirements through 2016. See Note 3 — Regulatory Matters for further information regarding the DSP Programs. | ||||||||||||||||||||||||||||
ComEd is subject to requirements established by the Illinois 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. 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, 2014 are as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 620 | $ | 329 | $ | 151 | $ | 140 | $ | — | $ | — | $ | — | ||||||||||||||
Renewable energy and RECs (b) | 1,517 | 75 | 76 | 77 | 78 | 84 | 1,127 | |||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||
Electric supply procurement (c) | 609 | 527 | 82 | — | — | — | — | |||||||||||||||||||||
AECs (d) | 13 | 2 | 2 | 2 | 2 | 2 | 3 | |||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||
Electric supply procurement (e) | 1,315 | 779 | 448 | 88 | — | — | — | |||||||||||||||||||||
Curtailment services (f) | 115 | 40 | 34 | 29 | 12 | — | — | |||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||
(a) | ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. | |||||||||||||||||||||||||||
(b) | Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. | |||||||||||||||||||||||||||
(c) | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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. | |||||||||||||||||||||||||||
(d) | 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. | |||||||||||||||||||||||||||
(e) | BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||
(f) | 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. Beginning with the second quarter of 2014, 100% of CENG's nuclear fuel commitments are disclosed within the Generation line below, since CENG is now fully consolidated by Generation. PECO and BGE have commitments to purchase natural gas related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of December 31, 2014, these commitments were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Generation | $ | 8,981 | $ | 1,404 | $ | 1,119 | $ | 1,124 | $ | 1,001 | $ | 888 | $ | 3,445 | ||||||||||||||
PECO | 428 | 146 | 103 | 60 | 34 | 14 | 71 | |||||||||||||||||||||
BGE | 611 | 111 | 82 | 67 | 57 | 54 | 240 | |||||||||||||||||||||
Other Purchase Obligations | ||||||||||||||||||||||||||||
The Registrants’ other purchase obligations as of December 31, 2014, which primarily represent commitments for services, materials and information technology, are as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Exelon | $ | 894 | $ | 336 | $ | 258 | $ | 150 | $ | 36 | $ | 30 | $ | 84 | ||||||||||||||
Generation (a)(b) | 396 | 163 | 67 | 42 | 30 | 24 | 70 | |||||||||||||||||||||
ComEd (c) | 148 | 63 | 77 | 1 | 1 | 1 | 5 | |||||||||||||||||||||
PECO (c) | 7 | 3 | 4 | — | — | — | — | |||||||||||||||||||||
BGE (c) | 343 | 107 | 110 | 107 | 5 | 5 | 9 | |||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(a) | Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information. | |||||||||||||||||||||||||||
(b) | Purchase obligations include commitments related to assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information. | |||||||||||||||||||||||||||
(c) | 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, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,233 | $ | 1,151 | $ | 77 | $ | 5 | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 596 | 545 | 10 | 4 | 1 | 2 | 34 | |||||||||||||||||||||
Performance guarantees (c) | 1,239 | 472 | 20 | 20 | 20 | 20 | 687 | |||||||||||||||||||||
Energy marketing contract | 3,220 | 3,220 | — | — | — | — | — | |||||||||||||||||||||
guarantees (d) | ||||||||||||||||||||||||||||
Lease guarantees(e) | 40 | — | — | — | — | — | 40 | |||||||||||||||||||||
Nuclear insurance premiums (f) | 3,014 | — | — | — | — | — | 3,014 | |||||||||||||||||||||
Underwriters discount (g) | 60 | 60 | — | — | — | — | — | |||||||||||||||||||||
Total commercial commitments | $ | 9,402 | $ | 5,448 | $ | 107 | $ | 29 | $ | 21 | $ | 22 | $ | 3,775 | ||||||||||||||
___________________________ | ||||||||||||||||||||||||||||
(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. Additionally includes $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 $3.2 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 $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 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. | |||||||||||||||||||||||||||
(g) | Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering. | |||||||||||||||||||||||||||
Generation’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,187 | $ | 1,106 | $ | 76 | $ | 5 | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds | 481 | 468 | 3 | — | — | — | 10 | |||||||||||||||||||||
Performance guarantees (b) | 458 | 319 | 20 | 20 | 20 | 20 | 59 | |||||||||||||||||||||
Energy marketing contract | 1,244 | 1,244 | — | — | — | — | — | |||||||||||||||||||||
guarantees (c) | ||||||||||||||||||||||||||||
Nuclear insurance premiums (d) | 3,014 | — | — | — | — | — | 3,014 | |||||||||||||||||||||
Total commercial commitments | $ | 6,384 | $ | 3,137 | $ | 99 | $ | 25 | $ | 20 | $ | 20 | $ | 3,083 | ||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(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. | |||||||||||||||||||||||||||
(c) | Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 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. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 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, including CENG sites, 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. | |||||||||||||||||||||||||||
ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 17 | $ | 17 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 5 | 3 | — | — | — | — | 2 | |||||||||||||||||||||
Performance guarantees (c) | 200 | — | — | — | — | — | 200 | |||||||||||||||||||||
Total commercial commitments | $ | 222 | $ | 20 | $ | — | $ | — | $ | — | $ | — | $ | 202 | ||||||||||||||
_________________________ | ||||||||||||||||||||||||||||
(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, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 22 | $ | 22 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 18 | 18 | — | — | — | — | — | |||||||||||||||||||||
Performance guarantees(c) | 178 | — | — | — | — | — | 178 | |||||||||||||||||||||
Total commercial commitments | $ | 218 | $ | 40 | $ | — | $ | — | $ | — | $ | — | $ | 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, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds (b) | 11 | 11 | — | — | — | — | — | |||||||||||||||||||||
Performance guarantees (c) | 253 | 3 | — | — | — | — | 250 | |||||||||||||||||||||
Total commercial commitments | $ | 265 | $ | 15 | $ | — | $ | — | $ | — | $ | — | $ | 250 | ||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(a) | Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |||||||||||||||||||||||||||
(b) | Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds. | |||||||||||||||||||||||||||
(c) | 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’s ongoing investments in renewables development and new natural gas construction illustrates Generation’s growth strategy to provide for diversification opportunities while leveraging its expertise and strengths. | ||||||||||||||||||||||||||||
Generation completed the construction of the Antelope Valley solar PV facility in Los Angeles County, California, which became fully operational in the first half of 2014. Generation has no further remaining construction commitments for the project. | ||||||||||||||||||||||||||||
On July 3, 2013, Generation executed a turbine supply agreement to expand its Beebe wind project in Michigan. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained 2014. | ||||||||||||||||||||||||||||
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with at least 120MW of new natural gas-fired generation. The remaining commitment is approximately $39 million under the contract and achievement of commercial operation is expected in 2015. This project will satisfy a portion of Exelon's commitment to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger. | ||||||||||||||||||||||||||||
On December 27, 2013, Generated executed a turbine supply agreement for construction of the 40MW Fourmile Wind project in western Maryland. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained in 2014. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger. | ||||||||||||||||||||||||||||
During the third and fourth quarter of 2014, Generation executed contracts associated with the construction of new combined-cycle gas turbine units in Texas. The remaining commitment is approximately $1.0 billion under these contracts and achievement of commercial operations is expected in 2017. | ||||||||||||||||||||||||||||
During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 30 MW Fair Wind project in western Maryland. The remaining commitment is approximately $19 million under these contracts and achievement of commercial operations is expected in 2015. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger. | ||||||||||||||||||||||||||||
During the fourth quarter of 2014 Generation executed contracts associated with the construction of the 78 MW Sendero Wind project in southern Texas. The remaining commitment is approximately $56 million under these contracts and achievement of commercial operations is expected in 2015. | ||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||
Equity Investment Commitments | ||||||||||||||||||||||||||||
As part of Generation's recent investments in technology development, Generation has entered into equity purchase agreements which include commitments to purchase additional equity through incremental payments. The additional equity is provided by the agreements to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services. As of December 31, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows: | ||||||||||||||||||||||||||||
Total | ||||||||||||||||||||||||||||
2015 | $ | 98 | ||||||||||||||||||||||||||
2016 | 38 | |||||||||||||||||||||||||||
2017 | 20 | |||||||||||||||||||||||||||
2018 | 11 | |||||||||||||||||||||||||||
Total | $ | 167 | ||||||||||||||||||||||||||
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, 2014 were: | ||||||||||||||||||||||||||||
Exelon | Generation (b) | ComEd (c) | PECO (c) | BGE (c)(d) | ||||||||||||||||||||||||
2015 | $ | 99 | $ | 51 | $ | 14 | $ | 3 | $ | 13 | ||||||||||||||||||
2016 | 102 | 57 | 13 | 3 | 11 | |||||||||||||||||||||||
2017 | 102 | 63 | 8 | 3 | 10 | |||||||||||||||||||||||
2018 | 86 | 57 | 4 | 3 | 9 | |||||||||||||||||||||||
2019 | 70 | 43 | 4 | 2 | 7 | |||||||||||||||||||||||
Remaining years | 699 | 628 | 2 | — | 27 | |||||||||||||||||||||||
Total minimum future lease payments | $ | 1,158 | (a) | $ | 899 | (a) | $ | 45 | $ | 14 | $ | 77 | ||||||||||||||||
______________________ | ||||||||||||||||||||||||||||
(a) | Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment. | |||||||||||||||||||||||||||
(b) | The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million . | |||||||||||||||||||||||||||
(c) | 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 2015—2019, was $2 million, $3 million, and $2 million respectively. | |||||||||||||||||||||||||||
(d) | Includes all future lease payments on a 99 year real estate lease that expires in 2106. | |||||||||||||||||||||||||||
The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2014, 2013 and 2012: | ||||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation (a) | ComEd | PECO | BGE | |||||||||||||||||||||||
2014 | $ | 865 | $ | 806 | $ | 15 | $ | 14 | $ | 12 | ||||||||||||||||||
2013 | 806 | 744 | 15 | 21 | 11 | |||||||||||||||||||||||
2012 | 930 | 872 | 18 | 27 | 12 | |||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||
(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 $755 million, $694 million and $801 million during 2014, 2013 and 2012, 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. The guarantee expired January 31, 2014. Generation was not required to make payments under the guarantee, and, therefore, has no further obligation related to this guarantee. | ||||||||||||||||||||||||||||
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 now 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 almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location. | ||||||||||||||||||||||||||||
• | ComEd has identified 42 sites, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 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 2019. | |||||||||||||||||||||||||||
• | PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites 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 2021. | |||||||||||||||||||||||||||
• | 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. At this time, BGE is unable to estimate the results of this investigation. | |||||||||||||||||||||||||||
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 recover, 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. See Note 3—Regulatory Matters for additional information regarding the associated regulatory assets. | ||||||||||||||||||||||||||||
As of December 31, 2014 and 2013, 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: | ||||||||||||||||||||||||||||
December 31, 2014 | Total environmental | Portion of total related to MGP | ||||||||||||||||||||||||||
investigation | investigation and remediation | |||||||||||||||||||||||||||
and remediation reserve | ||||||||||||||||||||||||||||
Exelon | $ | 347 | $ | 277 | ||||||||||||||||||||||||
Generation | 63 | — | ||||||||||||||||||||||||||
ComEd | 238 | 235 | ||||||||||||||||||||||||||
PECO | 45 | 42 | ||||||||||||||||||||||||||
BGE | 1 | — | ||||||||||||||||||||||||||
31-Dec-13 | Total environmental | Portion of total related to MGP | ||||||||||||||||||||||||||
investigation | investigation and remediation | |||||||||||||||||||||||||||
and remediation reserve | ||||||||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||||||
Generation | 56 | — | ||||||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||||
BGE | 1 | — | ||||||||||||||||||||||||||
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 activity. Management determines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time of each study and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency. | ||||||||||||||||||||||||||||
During the third quarter of 2014, 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 environmental liabilities and related regulatory assets by $26 million and $4 million, respectively, primarily reflecting refined assumptions regarding clean-up techniques and scopes based on additional experience and analysis as site clean-up and investigation activities progress. | ||||||||||||||||||||||||||||
BGE has established a reserve for the active sites that is not material. Given that the former gas purification site is in the early stages of investigation and the extent of contamination is not currently known, BGE is unable to estimate actual remediation costs, which may be material to BGE’s results of operations, cash flows, and financial position. | ||||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||
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. As of December 31, 2014 and 2013, Generation’s remaining groundwater contamination reserve was $13 million and $14 million. respectively. | ||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||
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 an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012. | ||||||||||||||||||||||||||||
On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors’ Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME’s portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected. Creditors were provided 30 days from the Effective Date to file rejection damages claims associated with contracts rejected under the Plan. | ||||||||||||||||||||||||||||
During the second quarter of 2013, Exelon filed proofs of claim for approximately $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation related to the coal rail car lease. 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 and a claim under the asbestos cost-sharing agreement with an unspecified amount. A settlement was approved on January 22, 2015, to resolve the claims related to the coal rail car lease for $14 million. Exelon received the funds and recorded the corresponding gain January 2015. | ||||||||||||||||||||||||||||
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. 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 March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, that (i) it has accrued a probable amount of approximately $9 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at two 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, 2014. 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. | ||||||||||||||||||||||||||||
Generation increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million, as a result of Midwest Generation listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussed above, the rejection became effective as part of the Plan. Subsequently, Generation increased its reserve by $15 million pursuant to the second quarter 2014 actuarial study of such claims, of which an estimated $6 million pertains to Midwest Generation’s share. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, that it had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of the agreement. These amounts are considered to be contingent gains and would not be recognized until realized. | ||||||||||||||||||||||||||||
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. 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, and subsequently requested additional analysis sampling and modeling that will be conducted throughout 2015. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment, but will likely be sometime in 2016 at the earliest. 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. The current estimated cost of the landfill cover remediation for the site is approximately $50 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. | ||||||||||||||||||||||||||||
On April 11, 2014, a class action complaint was filed in the U.S. District Court for the Eastern District of Missouri against Cotter and six additional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfill suffered damage to property or loss of use of property due to the defendants’ negligent handling of radioactive materials. On August 22, 2014, the plaintiffs voluntarily dismissed the case without prejudice. | ||||||||||||||||||||||||||||
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 2015 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation 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 Exelon 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, Generation, and ComEd 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 Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE 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 $10 million, which has been fully reserved as of December 31, 2014. | ||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||
Coal Combustion Residuals. On December 19, 2014, the U.S. EPA issued the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 days after publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation is evaluating what, if any, incremental costs will be incurred for coal ash disposal sites formerly owned by Generation that have not yet been closed by their current owners. At this time, however, Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations, and as a result no new liability has been recorded as of December 31, 2014. | ||||||||||||||||||||||||||||
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, 2014 and 2013, Generation had reserved approximately $100 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2014, approximately $22 million of this amount related to 255 open claims presented to Generation, while the remaining $78 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. During the second quarter of 2014, Generation increased its reserve by approximately $15 million, primarily due to increased actual and projected number and severity of claims. | ||||||||||||||||||||||||||||
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, 2014. 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. | ||||||||||||||||||||||||||||
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 Constellation 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 within its Statement of Operations and Comprehensive Income with the remaining $50 million recorded as a Constellation pre-acquisition contingency within its Consolidated Balance Sheets. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on the Constellation 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. The ICC held that for the July 11, 2011 storm, 34,559 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. On July 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in the appeal of the Summer 2011 Storm Docket and dismissed the appeal of the February 2011 Blizzard Docket. The Illinois Appellate Court’s opinion has no accounting impact as ComEd previously established a liability in connection with the June 5, 2013 ICC ruling discussed below. ComEd has asked the Illinois Supreme Court to hear the matter. There is no set time in which the Court must decide whether it will take the case. | ||||||||||||||||||||||||||||
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 the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its 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. ComEd intends to contest the allegations of this suit. In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied in June 2014. As of December 31, 2014, ComEd has a reserve, which is not material, representing its best estimate of probable loss associated with this class action complaint. As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimated amount recorded, which may be material to ComEd’s results of operations, cash flows, and financial position. | ||||||||||||||||||||||||||||
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, 2014 | |||||||||||||||||||||
Supplemental Financial Information [Abstract] | |||||||||||||||||||||
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE) | 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 and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Taxes other than income | |||||||||||||||||||||
Utility (a) | $ | 456 | $ | 89 | $ | 238 | $ | 128 | $ | 86 | |||||||||||
Property | 396 | 240 | 25 | 15 | 114 | ||||||||||||||||
Payroll | 200 | 118 | 28 | 14 | 18 | ||||||||||||||||
Other | 102 | 18 | 2 | 2 | 3 | ||||||||||||||||
Total taxes other than income | $ | 1,154 | $ | 465 | 293 | $ | 159 | $ | 221 | ||||||||||||
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 | |||||||||||
_____________________ | |||||||||||||||||||||
(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, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Other, Net | |||||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||||
Net realized income on decommissioning | |||||||||||||||||||||
trust funds (a)— | |||||||||||||||||||||
Regulatory agreement units | $ | 216 | $ | 216 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 159 | 159 | — | — | — | ||||||||||||||||
Net unrealized gains on decommissioning | |||||||||||||||||||||
trust funds— | |||||||||||||||||||||
Regulatory agreement units | 180 | 180 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 134 | 134 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 29 | 29 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (358 | ) | (358 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 360 | 360 | — | — | — | ||||||||||||||||
Investment income | 1 | 1 | — | (1 | ) | 7 | (c) | ||||||||||||||
Long-term lease income | 24 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 40 | 54 | — | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 21 | — | 3 | 6 | 12 | ||||||||||||||||
Other | 9 | (9 | ) | 14 | 2 | (1 | ) | ||||||||||||||
Other, net | $ | 455 | $ | 406 | $ | 17 | $ | 7 | $ | 18 | |||||||||||
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 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 77 | 77 | — | — | — | ||||||||||||||||
Net unrealized gains on decommissioning trust | |||||||||||||||||||||
funds— | |||||||||||||||||||||
Regulatory agreement units | 406 | 406 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 146 | 146 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 7 | 7 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (546 | ) | (546 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 346 | 346 | — | — | — | ||||||||||||||||
Investment income | 8 | (1 | ) | — | (1 | ) | 9 | (c) | |||||||||||||
Long-term lease income | 28 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 24 | 4 | — | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 22 | — | 11 | 4 | 7 | ||||||||||||||||
Other | 32 | 6 | 15 | 3 | 1 | ||||||||||||||||
Other, net | $ | 460 | $ | 355 | $ | 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 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 102 | 102 | — | — | — | ||||||||||||||||
Net unrealized losses on decommissioning | |||||||||||||||||||||
trust funds— | |||||||||||||||||||||
Regulatory agreement units | 386 | 386 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 105 | 105 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 73 | 73 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (530 | ) | (530 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 325 | 325 | — | — | — | ||||||||||||||||
Investment income | 20 | 3 | 1 | 2 | 11 | (c) | |||||||||||||||
Long-term lease income | 29 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 15 | 2 | 20 | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 17 | — | 6 | 4 | 10 | ||||||||||||||||
Credit Facility termination fees | (85 | ) | (85 | ) | — | — | — | ||||||||||||||
Other | 32 | 1 | 12 | 2 | 2 | ||||||||||||||||
Other, net | $ | 353 | $ | 246 | $ | 39 | $ | 8 | $ | 23 | |||||||||||
_________________________ | |||||||||||||||||||||
(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, 2014, 2013 and 2012. | |||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Depreciation, amortization, accretion and | |||||||||||||||||||||
depletion | |||||||||||||||||||||
Property, plant and equipment | $ | 2,080 | $ | 922 | $ | 588 | $ | 227 | $ | 288 | |||||||||||
Regulatory assets | 191 | — | 99 | 9 | 83 | ||||||||||||||||
Amortization of intangible assets, net | 44 | 44 | — | — | — | ||||||||||||||||
Amortization of energy contract assets and | 135 | 135 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 1,073 | 1,073 | — | — | — | ||||||||||||||||
ARO accretion (c) | 345 | 345 | — | — | — | ||||||||||||||||
Total depreciation, amortization, accretion and | $ | 3,868 | $ | 2,519 | $ | 687 | $ | 236 | $ | 371 | |||||||||||
depletion | |||||||||||||||||||||
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 | — | 119 | 9 | 84 | ||||||||||||||||
Amortization of intangible assets, net | 48 | 43 | 5 | — | — | ||||||||||||||||
Amortization of energy contract assets and | 430 | 507 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 921 | 921 | — | — | — | ||||||||||||||||
ARO accretion (c) | 275 | 275 | — | — | — | ||||||||||||||||
Total depreciation, amortization, accretion and | $ | 3,779 | $ | 2,559 | $ | 669 | $ | 228 | $ | 348 | |||||||||||
depletion | |||||||||||||||||||||
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 | — | 80 | 10 | 53 | ||||||||||||||||
Amortization of intangible assets, net | 40 | 35 | 5 | — | — | ||||||||||||||||
Amortization of energy contract assets and | 1,110 | 1,110 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 848 | 848 | — | — | — | ||||||||||||||||
ARO accretion (c) | 240 | 240 | — | — | — | ||||||||||||||||
Total depreciation, amortization and accretion | $ | 4,079 | $ | 2,966 | $ | 610 | $ | 217 | $ | 298 | |||||||||||
________________________ | |||||||||||||||||||||
(a) | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
(b) | Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
(c) | Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||||
Interest (net of amount capitalized) | $ | 940 | $ | 322 | $ | 292 | $ | 94 | $ | 111 | |||||||||||
Income taxes (net of refunds) | $ | 314 | 227 | (6 | ) | 85 | (21 | ) | |||||||||||||
Other non-cash operating activities: | |||||||||||||||||||||
Pension and non-pension postretirement benefit | $ | 560 | $ | 249 | 162 | $ | 36 | $ | 64 | ||||||||||||
costs | |||||||||||||||||||||
Loss from equity method investments | 22 | 20 | — | — | — | ||||||||||||||||
Provision for uncollectible accounts | 156 | 14 | 26 | 52 | 64 | ||||||||||||||||
Provision for excess and obsolete inventory | 5 | 5 | — | — | — | ||||||||||||||||
Stock-based compensation costs | 91 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (132 | ) | (132 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 122 | 122 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt | 11 | — | 8 | 3 | — | ||||||||||||||||
costs | |||||||||||||||||||||
Amortization of rate stabilization deferral | 65 | — | — | — | 65 | ||||||||||||||||
Amortization of debt fair value adjustment | (23 | ) | (23 | ) | — | — | — | ||||||||||||||
Merger-related commitments | 44 | 44 | — | — | — | ||||||||||||||||
Amortization of debt costs | 53 | 12 | 4 | 2 | 2 | ||||||||||||||||
Discrete impacts from EIMA (c) | 53 | — | 53 | — | — | ||||||||||||||||
Lower of cost or market inventory adjustment | 29 | 29 | — | — | — | ||||||||||||||||
Other | (2 | ) | 6 | 2 | (1 | ) | (15 | ) | |||||||||||||
Total other non-cash operating activities | $ | 1,054 | $ | 346 | $ | 255 | $ | 92 | $ | 180 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission | $ | 47 | $ | — | $ | 36 | $ | — | $ | 11 | |||||||||||
costs | |||||||||||||||||||||
Other regulatory assets and liabilities | (167 | ) | — | (13 | ) | (16 | ) | (121 | ) | ||||||||||||
Cash deposits (d) | (241 | ) | (241 | ) | — | — | — | ||||||||||||||
Other current assets | 7 | 81 | (10 | ) | (2 | ) | (44 | ) | |||||||||||||
Other noncurrent assets and liabilities | (204 | ) | (89 | ) | 32 | 1 | (9 | ) | |||||||||||||
Total changes in other assets and liabilities | $ | (558 | ) | $ | (249 | ) | $ | 45 | $ | (17 | ) | $ | (163 | ) | |||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | 72 | $ | 72 | $ | — | $ | — | $ | — | |||||||||||
Change in capital expenditures not paid | 220 | (61 | ) | (e) | 78 | — | 25 | ||||||||||||||
Fair value of net assets recorded upon CENG | (3,400 | ) | (3,400 | ) | — | — | — | ||||||||||||||
consolidation (f) | |||||||||||||||||||||
Issuance of equity units (g) | 131 | — | — | — | — | ||||||||||||||||
Nuclear fuel procurement (h) | 70 | 70 | — | — | — | ||||||||||||||||
Indemnification of like-kind exchange position (i) | — | — | 5 | — | — | ||||||||||||||||
____________________________ | |||||||||||||||||||||
(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 primarily to cash deposits made to ISO's/RTO's. | ||||||||||||||||||||
(e) | Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley. | ||||||||||||||||||||
(f) | See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||
(g) | Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information. | ||||||||||||||||||||
(h) | Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018. | ||||||||||||||||||||
(i) | See Note 14 — Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||||
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 | |||||||||||
Gain from equity method investments | (10 | ) | (10 | ) | — | — | — | ||||||||||||||
Provision for uncollectible accounts | 101 | 10 | (15 | ) | 61 | 44 | |||||||||||||||
Provision for excess and obsolete inventory | 9 | 9 | — | — | — | ||||||||||||||||
Stock-based compensation costs | 120 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (169 | ) | (169 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 104 | 104 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt | 12 | — | 9 | 3 | — | ||||||||||||||||
costs | |||||||||||||||||||||
Amortization of rate stabilization deferral | 66 | — | — | — | 66 | ||||||||||||||||
Amortization of debt fair value adjustment | (34 | ) | (34 | ) | — | — | — | ||||||||||||||
Discrete impacts from EIMA (c) | (271 | ) | — | (271 | ) | — | — | ||||||||||||||
Amortization of debt costs | 18 | 10 | 1 | 2 | 2 | ||||||||||||||||
Other | (53 | ) | 5 | (4 | ) | (1 | ) | (15 | ) | ||||||||||||
Total other non-cash operating activities | $ | 718 | $ | 270 | $ | 28 | $ | 108 | $ | 153 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission | $ | 12 | $ | — | $ | (35 | ) | $ | 9 | $ | 38 | ||||||||||
costs | |||||||||||||||||||||
Other regulatory assets and liabilities | (64 | ) | — | (43 | ) | (16 | ) | (71 | ) | ||||||||||||
Other current assets | (165 | ) | (151 | ) | 51 | 13 | (8 | ) | |||||||||||||
Other noncurrent assets and liabilities | 322 | 15 | 268 | (d) | (12 | ) | (23 | ) | |||||||||||||
Total changes in other assets and liabilities | $ | 105 | $ | (136 | ) | $ | 241 | $ | (6 | ) | $ | (64 | ) | ||||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | (128 | ) | $ | (128 | ) | $ | — | $ | — | $ | 4 | |||||||||
Change in capital expenditures not paid | (38 | ) | (107 | ) | (e) | (8 | ) | 13 | (48 | ) | |||||||||||
Consolidated VIE dividend to noncontrolling interest | 63 | 63 | — | — | — | ||||||||||||||||
Indemnification of like-kind exchange position (f) | — | — | 176 | — | — | ||||||||||||||||
______________________ | |||||||||||||||||||||
(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 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. | ||||||||||||||||||||
(e) | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | ||||||||||||||||||||
(f) | See Note 14 — Income Taxes for discussion of the like-kind exchanged 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 | |||||||||||
Earnings from equity method investments | 91 | 91 | — | — | — | ||||||||||||||||
Provision for uncollectible accounts | 164 | 22 | 42 | 60 | 44 | ||||||||||||||||
Provision for excess and obsolete inventory | 6 | 6 | 1 | — | — | ||||||||||||||||
Stock-based compensation costs | 94 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (145 | ) | (145 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 160 | 160 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt costs | 18 | — | 13 | 3 | 2 | ||||||||||||||||
Amortization of rate stabilization deferral | 57 | — | — | — | 67 | ||||||||||||||||
Amortization of debt fair value adjustment | (34 | ) | (34 | ) | — | — | — | ||||||||||||||
Merger-related commitments (c) | 141 | 32 | — | — | 27 | ||||||||||||||||
Severance costs | 99 | 34 | — | — | — | ||||||||||||||||
Discrete impacts from EIMA (d) | (96 | ) | — | (96 | ) | — | — | ||||||||||||||
Amortization of debt costs | 19 | 11 | 5 | 3 | 2 | ||||||||||||||||
Other | (30 | ) | — | 5 | 9 | (6 | ) | ||||||||||||||
Total other non-cash operating activities | $ | 1,364 | $ | 518 | $ | 252 | $ | 125 | $ | 193 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 71 | $ | — | $ | 28 | $ | 20 | $ | 26 | |||||||||||
Other regulatory assets and liabilities | (404 | ) | $ | — | (68 | ) | 18 | (112 | ) | ||||||||||||
Other current assets | 213 | (30 | ) | 33 | (12 | ) | (7 | ) | |||||||||||||
Other noncurrent assets and liabilities | (248 | ) | (98 | ) | (95 | ) | (10 | ) | 8 | ||||||||||||
Total changes in other assets and liabilities | $ | (368 | ) | $ | (128 | ) | $ | (102 | ) | $ | 16 | $ | (85 | ) | |||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | 781 | $ | 781 | $ | 2 | $ | — | $ | — | |||||||||||
Change in capital expenditures not paid | 160 | 103 | (e) | 15 | 26 | (4 | ) | ||||||||||||||
Consolidated VIE dividend to noncontrolling interest | 7,365 | 5,264 | — | — | — | ||||||||||||||||
_________________________ | |||||||||||||||||||||
(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) | Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments. | ||||||||||||||||||||
(d) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters. | ||||||||||||||||||||
(e) | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | ||||||||||||||||||||
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 million related to PECO’s DOE SGIG programs. 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, and reimbursements of $95 million, $37 million and $58 million, 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, 2014 and 2013. | |||||||||||||||||||||
31-Dec-14 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Investments | |||||||||||||||||||||
Equity method investments: | |||||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | — | $ | 6 | $ | 8 | $ | 8 | |||||||||||
Bloom Energy | 13 | 13 | — | — | — | ||||||||||||||||
Net Power | 9 | 9 | — | — | — | ||||||||||||||||
Sunnyside | 5 | 5 | — | — | — | ||||||||||||||||
Other equity method investments | 1 | 1 | — | — | — | ||||||||||||||||
Total equity method investments | 50 | 28 | 6 | 8 | 8 | ||||||||||||||||
Other investments: | |||||||||||||||||||||
Net investment in leases | 367 | 7 | — | — | — | ||||||||||||||||
Employee benefit trusts and investments (b) | 85 | 27 | — | 23 | 4 | ||||||||||||||||
Other investments (c) | 42 | 42 | — | — | — | ||||||||||||||||
Total investments | $ | 544 | $ | 104 | $ | 6 | $ | 31 | $ | 12 | |||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Investments | |||||||||||||||||||||
Equity method investments: | |||||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | — | $ | 6 | $ | 8 | $ | 8 | |||||||||||
Keystone Fuels, LLC | 32 | 32 | — | — | — | ||||||||||||||||
Conemaugh Fuels, LLC | 21 | 21 | — | — | — | ||||||||||||||||
CENG | 1,925 | 1,925 | — | — | — | ||||||||||||||||
Safe Harbor | 285 | 285 | — | — | — | ||||||||||||||||
Malacha | 8 | 8 | — | — | — | ||||||||||||||||
Other equity method investments | 2 | 2 | — | — | — | ||||||||||||||||
Total equity method investments | 2,295 | 2,273 | 6 | 8 | 8 | ||||||||||||||||
Other investments: | |||||||||||||||||||||
Net investment in leases | 705 | 7 | — | — | — | ||||||||||||||||
Employee benefit trusts and investments (b) | 90 | 23 | 5 | 23 | 5 | ||||||||||||||||
Other investments (c) | 22 | 22 | — | — | — | ||||||||||||||||
Total investments | $ | 3,112 | $ | 2,325 | $ | 11 | $ | 31 | $ | 13 | |||||||||||
_________________________ | |||||||||||||||||||||
(a) | Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments 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. | ||||||||||||||||||||
(c) | Includes cost method and available-for-sale investments. | ||||||||||||||||||||
The following tables provide additional information about liabilities of the Registrants at December 31, 2014 and 2013. | |||||||||||||||||||||
31-Dec-14 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Accrued expenses | |||||||||||||||||||||
Compensation-related accruals (a) | $ | 832 | $ | 447 | $ | 153 | $ | 50 | $ | 58 | |||||||||||
Taxes accrued | 305 | 248 | 59 | 3 | 42 | ||||||||||||||||
Interest accrued | 240 | 66 | 102 | 33 | 29 | ||||||||||||||||
Severance accrued | 49 | 33 | 2 | 1 | 2 | ||||||||||||||||
Other accrued expenses | 113 | (b) | 92 | (b) | 15 | 4 | — | ||||||||||||||
Total accrued expenses | $ | 1,539 | $ | 886 | $ | 331 | $ | 91 | $ | 131 | |||||||||||
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 | |||||||||||
_______________________ | |||||||||||||||||||||
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. | ||||||||||||||||||||
(b) | Includes $19 million and $228 million for amounts accrued related to Antelope Valley as of December 31, 2014 and December 31, 2013, respectively. |
Segment_Information_Exelon_Gen
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||||||||||
Segment Information (Exelon, Generation, ComEd, PECO and BGE) | 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. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon’s CODM evaluates the performance of and allocates resources to ComEd, PECO and BGE based on net income and return on equity. | ||||||||||||||||||||||||||||||||||||
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 sales to its affiliates, 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, investments in gas and oil exploration and production activities, proprietary trading, distributed generation, 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, unrealized mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value are also not allocated to a region. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments. | ||||||||||||||||||||||||||||||||||||
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, 2014, 2013, and 2012 is as follows: | ||||||||||||||||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE (b) | Other (c) | Intersegment | Exelon | ||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||
Operating revenues(d): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 17,393 | $ | 4,564 | 3,094 | $ | 3,165 | $ | 1,285 | $ | (2,072 | ) | $ | 27,429 | ||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 762 | $ | 4 | $ | 2 | $ | 25 | $ | 1,280 | $ | (2,067 | ) | $ | 6 | |||||||||||||||||||||
2013 | 1,367 | 3 | 1 | 13 | 1,237 | (2,607 | ) | 14 | ||||||||||||||||||||||||||||
2012 | 1,660 | 2 | 3 | 9 | 1,381 | (3,049 | ) | 6 | ||||||||||||||||||||||||||||
Depreciation and amortization | ||||||||||||||||||||||||||||||||||||
2014 | $ | 967 | $ | 687 | $ | 236 | $ | 371 | $ | 53 | $ | — | $ | 2,314 | ||||||||||||||||||||||
2013 | 856 | 669 | 228 | 348 | 52 | — | 2,153 | |||||||||||||||||||||||||||||
2012 | 768 | 610 | 217 | 238 | 48 | — | 1,881 | |||||||||||||||||||||||||||||
Operating expenses (d): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 16,923 | $ | 3,586 | $ | 2,522 | $ | 2,726 | $ | 1,353 | $ | (2,071 | ) | $ | 25,039 | |||||||||||||||||||||
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 | ||||||||||||||||||||||||||||
Equity in earnings (losses) of | ||||||||||||||||||||||||||||||||||||
unconsolidated affiliates | ||||||||||||||||||||||||||||||||||||
2014 | $ | (20 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (20 | ) | ||||||||||||||||||||
2013 | 10 | — | — | — | — | — | 10 | |||||||||||||||||||||||||||||
2012 | (91 | ) | — | — | — | — | — | (91 | ) | |||||||||||||||||||||||||||
Interest expense, net: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 356 | $ | 321 | $ | 113 | $ | 106 | $ | 169 | $ | — | $ | 1,065 | ||||||||||||||||||||||
2013 | 357 | 579 | 115 | 122 | 183 | — | 1,356 | |||||||||||||||||||||||||||||
2012 | 301 | 307 | 123 | 111 | 86 | — | 928 | |||||||||||||||||||||||||||||
Income (loss) before income | ||||||||||||||||||||||||||||||||||||
taxes: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 1,226 | $ | 676 | $ | 466 | $ | 351 | $ | (227 | ) | $ | (6 | ) | $ | 2,486 | ||||||||||||||||||||
2013 | 1,675 | 401 | 557 | 344 | (191 | ) | (13 | ) | 2,773 | |||||||||||||||||||||||||||
2012 | 1,058 | 618 | 508 | (54 | ) | (325 | ) | (7 | ) | 1,798 | ||||||||||||||||||||||||||
Income taxes: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 207 | $ | 268 | $ | 114 | $ | 140 | $ | (63 | ) | $ | — | $ | 666 | |||||||||||||||||||||
2013 | 615 | 152 | 162 | 134 | (20 | ) | 1 | 1,044 | ||||||||||||||||||||||||||||
2012 | 500 | 239 | 127 | (23 | ) | (215 | ) | (1 | ) | 627 | ||||||||||||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 1,019 | $ | 408 | $ | 352 | $ | 211 | $ | (164 | ) | $ | (6 | ) | $ | 1,820 | ||||||||||||||||||||
2013 | 1,060 | 249 | 395 | 210 | (171 | ) | (14 | ) | 1,729 | |||||||||||||||||||||||||||
2012 | 558 | 379 | 381 | (31 | ) | (110 | ) | (6 | ) | 1,171 | ||||||||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 3,012 | $ | 1,689 | $ | 661 | $ | 620 | $ | 95 | $ | — | 6,077 | |||||||||||||||||||||||
2013 | 2,752 | 1,433 | 537 | 587 | 86 | — | 5,395 | |||||||||||||||||||||||||||||
2012 | 3,554 | 1,246 | 422 | 500 | 67 | — | 5,789 | |||||||||||||||||||||||||||||
Total assets: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 45,348 | $ | 25,392 | $ | 9,943 | $ | 8,078 | $ | 9,794 | $ | (11,741 | ) | $ | 86,814 | |||||||||||||||||||||
2013 | 41,232 | 24,118 | 9,617 | 7,861 | 8,317 | (11,221 | ) | 79,924 | ||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||
(a) | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million 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, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million 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. | |||||||||||||||||||||||||||||||||||
(b) | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014. | |||||||||||||||||||||||||||||||||||
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||||||||||||||
(d) | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $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 and Comprehensive Income. | |||||||||||||||||||||||||||||||||||
Generation total revenues: | ||||||||||||||||||||||||||||||||||||
As of April 1, 2014, Generation total revenues and Generation total revenues net of purchased power and fuel expense includes 100% of the activity from CENG. | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Revenues | Intersegment | Total | Revenues | Intersegment | Total | Revenues | Intersegment | Total | ||||||||||||||||||||||||||||
from | revenues | Revenues | from | revenues | Revenues | from | revenues | Revenues | ||||||||||||||||||||||||||||
external | external | external | ||||||||||||||||||||||||||||||||||
customers (a) | customers (a) | customers (a) | ||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 5,265 | $ | (6 | ) | $ | 5,259 | $ | 5,182 | $ | 22 | $ | 5,204 | $ | 5,082 | $ | (44 | ) | $ | 5,038 | ||||||||||||||||
Midwest | 4,467 | 8 | 4,475 | 4,280 | (10 | ) | 4,270 | 4,824 | 24 | 4,848 | ||||||||||||||||||||||||||
New England | 1,417 | 5 | 1,422 | 1,245 | (8 | ) | 1,237 | 1,048 | 45 | 1,093 | ||||||||||||||||||||||||||
New York | 843 | — | 843 | 735 | (21 | ) | 714 | 582 | (25 | ) | 557 | |||||||||||||||||||||||||
ERCOT | 938 | (3 | ) | 935 | 1,222 | (6 | ) | 1,216 | 1,365 | 2 | 1,367 | |||||||||||||||||||||||||
Other Regions (b) | 1,319 | (10 | ) | 1,309 | 946 | 22 | 968 | 755 | 78 | 833 | ||||||||||||||||||||||||||
Total Revenues | $ | 14,249 | $ | (6 | ) | $ | 14,243 | $ | 13,610 | $ | (1 | ) | $ | 13,609 | $ | 13,656 | $ | 80 | $ | 13,736 | ||||||||||||||||
for Reportable Segments | ||||||||||||||||||||||||||||||||||||
Other (c) | 3,144 | 6 | 3,150 | 2,020 | 1 | 2,021 | 781 | (80 | ) | 701 | ||||||||||||||||||||||||||
Total | $ | 17,393 | $ | — | $ | 17,393 | $ | 15,630 | $ | — | $ | 15,630 | $ | 14,437 | $ | — | $ | 14,437 | ||||||||||||||||||
Generation Consolidated Operating Revenues | ||||||||||||||||||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||||||||||
(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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||||||||||||||
Generation total revenues net of purchased power and fuel expense: | ||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
RNF from | Intersegment | Total | RNF from | Intersegment | Total | RNF from | Intersegment | Total | ||||||||||||||||||||||||||||
external | RNF | RNF | external | RNF | RNF | external | RNF | RNF | ||||||||||||||||||||||||||||
customers (a) | customers (a) | customers (a) | ||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 3,466 | $ | (49 | ) | $ | 3,417 | $ | 3,273 | $ | (3 | ) | $ | 3,270 | $ | 3,477 | $ | (44 | ) | $ | 3,433 | |||||||||||||||
Midwest | 2,580 | 14 | 2,594 | 2,585 | 1 | 2,586 | 2,974 | 24 | 2,998 | |||||||||||||||||||||||||||
New England | 432 | (81 | ) | 351 | 217 | (32 | ) | 185 | 151 | 45 | 196 | |||||||||||||||||||||||||
New York | 457 | 26 | 483 | 14 | (18 | ) | (4 | ) | 101 | (25 | ) | 76 | ||||||||||||||||||||||||
ERCOT | 573 | (256 | ) | 317 | 604 | (168 | ) | 436 | 403 | 2 | 405 | |||||||||||||||||||||||||
Other Regions (b) | 611 | (284 | ) | 327 | 334 | (133 | ) | 201 | 53 | 78 | 131 | |||||||||||||||||||||||||
Total Revenues net of | $ | 8,119 | $ | (630 | ) | $ | 7,489 | $ | 7,027 | $ | (353 | ) | $ | 6,674 | $ | 7,159 | $ | 80 | $ | 7,239 | ||||||||||||||||
purchased power and fuel expense for Reportable Segments | ||||||||||||||||||||||||||||||||||||
Other (c) | (651 | ) | 630 | (21 | ) | 406 | 353 | 759 | 217 | (80 | ) | 137 | ||||||||||||||||||||||||
Total Generation | $ | 7,468 | $ | — | $ | 7,468 | $ | 7,433 | $ | — | $ | 7,433 | $ | 7,376 | $ | — | $ | 7,376 | ||||||||||||||||||
Revenues net of purchased power and fuel expense | ||||||||||||||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||||||
(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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense. |
Related_Party_Transactions_Exe
Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Related Party Transactions [Abstract] | ||||||||||||
Related-Party Transactions (Exelon, Generation, ComEd, PECO and BGE) | 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
PECO (a) | $ | 1 | $ | 10 | $ | 6 | ||||||
CENG (b) | 17 | 56 | 42 | |||||||||
BGE (a) | 5 | 4 | — | |||||||||
Total operating revenues from affiliates | $ | 23 | $ | 70 | $ | 48 | ||||||
Purchase power and fuel from affiliates: | ||||||||||||
CENG (c) | $ | 282 | $ | 992 | $ | 793 | ||||||
Keystone Fuels, LLC (d) | 138 | 144 | 119 | |||||||||
Conemaugh Fuels, LLC (d) | 99 | 98 | 101 | |||||||||
Safe Harbor Water Power Corp (d) | 12 | 22 | 23 | |||||||||
Total purchase power and fuel from affiliates | $ | 531 | $ | 1,256 | $ | 1,036 | ||||||
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 | 16 | 12 | |||||||||
Total interest expense to affiliates, net | $ | 41 | $ | 41 | $ | 37 | ||||||
Earnings (losses) in equity method investments: | ||||||||||||
CENG (e) | $ | (19 | ) | $ | 9 | $ | (99 | ) | ||||
Qualifying facilities and domestic power projects | (1 | ) | 1 | 8 | ||||||||
Total earnings (losses) in equity method investments | $ | (20 | ) | $ | 10 | $ | (91 | ) | ||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Receivables from affiliates (current): | ||||||||||||
CENG (b) | $ | — | $ | 3 | ||||||||
Payables to affiliates (current): | ||||||||||||
CENG (c) | $ | — | $ | 85 | ||||||||
ComEd Financing III | 4 | 4 | ||||||||||
PECO Trust III | 1 | 1 | ||||||||||
BGE Capital Trust II | 3 | 4 | ||||||||||
Keystone Fuels, LLC (d) | — | 12 | ||||||||||
Conemaugh Fuels, LLC (d) | — | 9 | ||||||||||
Other | — | 1 | ||||||||||
Total payables to affiliates (current) | $ | 8 | $ | 116 | ||||||||
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 | ||||||||
____________________________ | ||||||||||||
(a) | The intersegment profit associated with the 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 Statement of Operations. See Note 3—Regulatory Matters for additional information. | |||||||||||
(b) | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(c) | CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(d) | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | |||||||||||
(e) | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(f) | The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. | |||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
ComEd (a) | $ | 176 | $ | 506 | $ | 795 | ||||||
PECO (b) | 198 | 405 | 543 | |||||||||
BGE (c) | 387 | 455 | 322 | |||||||||
CENG (d) | 17 | 56 | 42 | |||||||||
BSC | 1 | 1 | — | |||||||||
Total operating revenues from affiliates | $ | 779 | $ | 1,423 | $ | 1,702 | ||||||
Purchase power and fuel from affiliates: | ||||||||||||
ComEd | $ | 1 | $ | 1 | $ | — | ||||||
BGE | 25 | 13 | 8 | |||||||||
CENG (e) | 282 | 992 | 793 | |||||||||
Keystone Fuels, LLC (i) | 138 | 144 | 119 | |||||||||
Conemaugh Fuels, LLC (i) | 99 | 98 | 101 | |||||||||
Safe Harbor Water Power Corporation (i) | 12 | 22 | 23 | |||||||||
Total purchase power and fuel from affiliates | $ | 557 | $ | 1,270 | $ | 1,044 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
ComEd (f) | $ | 3 | $ | 2 | $ | 2 | ||||||
PECO (f) | 2 | 1 | 3 | |||||||||
BSC (g) | 618 | 571 | 625 | |||||||||
Total operating and maintenance from affiliates | $ | 623 | $ | 574 | $ | 630 | ||||||
Interest expense to affiliates, net: | ||||||||||||
Exelon Corporate | $ | 53 | $ | 59 | $ | 75 | ||||||
Earnings (losses) in equity method investments | ||||||||||||
CENG (h) | $ | (19 | ) | $ | 9 | $ | (99 | ) | ||||
Qualifying facilities and domestic power projects | (1 | ) | 1 | 8 | ||||||||
Total earnings (losses) in equity method investments | $ | (20 | ) | $ | 10 | $ | (91 | ) | ||||
Capitalized costs | ||||||||||||
BSC (g) | $ | 91 | $ | 93 | $ | 80 | ||||||
Cash distribution paid to member | $ | 645 | $ | 625 | $ | 1,626 | ||||||
Contribution from member | $ | 53 | $ | 26 | $ | 48 | ||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Receivables from affiliates (current): | ||||||||||||
CENG (d) | $ | — | $ | 3 | ||||||||
ComEd (a) | 43 | 38 | ||||||||||
PECO (b) | 29 | 38 | ||||||||||
BGE (c) | 40 | 27 | ||||||||||
Other | 1 | 2 | ||||||||||
Total receivables from affiliates (current) | $ | 113 | $ | 108 | ||||||||
Long-term debt due to affiliates (current): | ||||||||||||
Exelon Corporate (l) | 556 | — | ||||||||||
Payables to affiliates (current): | ||||||||||||
CENG (e) | $ | — | $ | 85 | ||||||||
Exelon Corporate (j) | 12 | 7 | ||||||||||
BSC (g) | 83 | 66 | ||||||||||
ComEd | 12 | — | ||||||||||
Keystone Fuels, LLC (i) | — | 12 | ||||||||||
Conemaugh Fuels, LLC (i) | — | 9 | ||||||||||
Other | — | 2 | ||||||||||
Total payables to affiliates (current) | $ | 107 | $ | 181 | ||||||||
Long-term debt due to affiliates (noncurrent): | ||||||||||||
Exelon Corporate (l) | 943 | 1,523 | ||||||||||
Payables to affiliates (noncurrent): | ||||||||||||
BSC (g) | $ | 1 | $ | — | ||||||||
ComEd (k) | 2,389 | 2,293 | ||||||||||
PECO (k) | 490 | 447 | ||||||||||
Total payables to affiliates (noncurrent) | $ | 2,880 | $ | 2,740 | ||||||||
_______________________ | ||||||||||||
(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) | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. 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. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. 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) | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(i) | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | |||||||||||
(j) | The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation. | |||||||||||
(k) | 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. | |||||||||||
(l) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. | |||||||||||
ComEd | ||||||||||||
The financial statements of ComEd include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates | ||||||||||||
Generation | $ | 4 | $ | 3 | $ | 2 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (a) | $ | 176 | $ | 512 | $ | 789 | ||||||
Operating and maintenance from affiliate | ||||||||||||
BSC (b) | $ | 166 | $ | 157 | $ | 163 | ||||||
Interest expense to affiliates, net: | ||||||||||||
ComEd Financing III | $ | 13 | $ | 13 | $ | 13 | ||||||
Capitalized costs | ||||||||||||
BSC (b) | $ | 77 | $ | 69 | $ | 92 | ||||||
Cash dividends paid to parent | $ | 307 | $ | 220 | $ | 105 | ||||||
Contribution from parent | $ | 273 | $ | — | $ | 11 | ||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (c) | $ | 13 | $ | 13 | ||||||||
Receivable from affiliates (current): | ||||||||||||
Voluntary employee beneficiary association trust | $ | 2 | $ | 3 | ||||||||
Generation | 12 | — | ||||||||||
Total receivable from affiliates (current) | $ | 14 | $ | 3 | ||||||||
Receivable from affiliates (noncurrent): | ||||||||||||
Generation (d) | $ | 2,389 | $ | 2,293 | ||||||||
Exelon Corporate (e) | 182 | 176 | ||||||||||
Total receivable from affiliates (noncurrent) | $ | 2,571 | $ | 2,469 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (a) | $ | 43 | $ | 38 | ||||||||
BSC (b) | 32 | 30 | ||||||||||
ComEd Financing III | 4 | 4 | ||||||||||
PECO | 2 | — | ||||||||||
Exelon Corporate | 3 | 9 | ||||||||||
Other | — | 2 | ||||||||||
Total payables to affiliates (current) | $ | 84 | $ | 83 | ||||||||
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, which expired in 2013. 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 Registrants. 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) | Represents indemnification from Exelon Corporate related to the like-kind exchange transaction. | |||||||||||
PECO | ||||||||||||
The financial statements of PECO include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
Generation (a) | $ | 2 | $ | 1 | $ | 3 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (b) | $ | 194 | $ | 392 | $ | 533 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
BSC (c) | $ | 96 | $ | 98 | $ | 107 | ||||||
Generation | 3 | 3 | 4 | |||||||||
Total operating and maintenance from affiliates | $ | 99 | $ | 101 | $ | 111 | ||||||
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 | ||||||
Capitalized costs | ||||||||||||
BSC (c) | $ | 39 | $ | 46 | $ | 54 | ||||||
Cash dividends paid to parent | $ | 320 | $ | 332 | $ | 343 | ||||||
Contribution from parent | $ | 24 | $ | 27 | $ | 9 | ||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 3 | $ | 3 | ||||||||
Receivable from affiliate (current): | ||||||||||||
ComEd | $ | 2 | $ | — | ||||||||
BGE | 1 | 3 | ||||||||||
Total receivable from affiliates (current) | $ | 3 | $ | 3 | ||||||||
Receivable from affiliate (noncurrent): | ||||||||||||
Generation (e) | $ | 490 | $ | 447 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (b) | $ | 29 | $ | 38 | ||||||||
BSC (c) | 20 | 17 | ||||||||||
Exelon Corporate | 2 | 2 | ||||||||||
PECO Trust III | 1 | 1 | ||||||||||
Total payables to affiliates (current) | $ | 52 | $ | 58 | ||||||||
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 Registrants. 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. | |||||||||||
BGE | ||||||||||||
The financial statements of BGE include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
Generation (a) | $ | 25 | $ | 13 | $ | 10 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (b) | $ | 382 | $ | 452 | $ | 396 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
BSC (c) | $ | 103 | $ | 83 | $ | 106 | ||||||
Interest expense to affiliates, net: | ||||||||||||
BGE Capital Trust II | $ | 16 | $ | 16 | $ | 16 | ||||||
Capitalized costs | ||||||||||||
BSC (c) | $ | 19 | $ | 15 | $ | 21 | ||||||
Contribution from parent | $ | — | $ | — | $ | 66 | ||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 1 | $ | 1 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (b) | $ | 40 | $ | 27 | ||||||||
BSC (c) | 17 | 20 | ||||||||||
Exelon Corporate | 5 | 1 | ||||||||||
PECO | 1 | 3 | ||||||||||
BGE Capital Trust II | 3 | 4 | ||||||||||
Total payables to affiliates (current) | $ | 66 | $ | 55 | ||||||||
Long-term debt to BGE financing trust | ||||||||||||
BGE Capital Trust II | $ | 258 | $ | 258 | ||||||||
______________________ | ||||||||||||
(a) | BGE provides energy to Generation for Generation’s own use. | |||||||||||
(b) | 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. | |||||||||||
(c) | 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. | |||||||||||
(d) | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’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. |
Quarterly_Data_Unaudited_Exelo
Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Abstract] | ||||||||||||||||||||||||||||||||
Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE) | Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE) | |||||||||||||||||||||||||||||||
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: | ||||||||||||||||||||||||||||||||
Operating Revenues | Operating Income | Net (Loss) Income | ||||||||||||||||||||||||||||||
on Common | ||||||||||||||||||||||||||||||||
Stock | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 7,237 | $ | 6,082 | $ | 168 | (a) | $ | 513 | (b) | $ | 90 | $ | (4 | ) | (c) | ||||||||||||||||
30-Jun | 6,024 | 6,141 | 842 | (a) | 1,005 | 522 | 490 | |||||||||||||||||||||||||
30-Sep | 6,912 | 6,502 | 1,739 | (a) | 1,262 | (b) | 993 | 738 | ||||||||||||||||||||||||
31-Dec | 7,255 | 6,163 | 348 | 889 | 18 | (d) | 495 | |||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock. | |||||||||||||||||||||||||||||||
(b) | In the first and third quarter of 2013, Exelon reclassified $5 million and $8 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock. | |||||||||||||||||||||||||||||||
(c) | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||||||||||||||||||
(d) | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||||||||||||||||||
Average Basic Shares | Net (Loss) Income | |||||||||||||||||||||||||||||||
Outstanding | per Basic Share | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | 858 | 855 | $ | 0.1 | $ | (0.01 | ) | |||||||||||||||||||||||||
30-Jun | 860 | 856 | 0.61 | 0.57 | ||||||||||||||||||||||||||||
30-Sep | 861 | 857 | 1.15 | 0.86 | ||||||||||||||||||||||||||||
31-Dec | 861 | 856 | 0.02 | 0.6 | ||||||||||||||||||||||||||||
Average Diluted Shares | Net (Loss) Income | |||||||||||||||||||||||||||||||
Outstanding | per Diluted Share | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | 861 | 855 | $ | 0.1 | $ | (0.01 | ) | |||||||||||||||||||||||||
30-Jun | 864 | 860 | 0.6 | 0.57 | ||||||||||||||||||||||||||||
30-Sep | 863 | 860 | 1.15 | 0.86 | ||||||||||||||||||||||||||||
31-Dec | 868 | 860 | 0.02 | 0.59 | ||||||||||||||||||||||||||||
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis: | ||||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||
Fourth | Third | Second | First | Fourth | Third | Second | First | |||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||||||||
High price | $ | 38.93 | $ | 36.26 | $ | 37.73 | $ | 33.94 | $ | 30.59 | $ | 32.42 | $ | 37.8 | $ | 34.56 | ||||||||||||||||
Low price | 33.07 | 30.66 | 33.11 | 26.45 | 26.64 | 29.42 | 29.84 | 29.1 | ||||||||||||||||||||||||
Close | 37.08 | 34.09 | 36.48 | 33.56 | 27.39 | 29.64 | 30.88 | 34.48 | ||||||||||||||||||||||||
Dividends | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.525 | ||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts: | ||||||||||||||||||||||||||||||||
Operating Revenues | Operating (Loss) Income | Net (Loss) Income | ||||||||||||||||||||||||||||||
on Membership | ||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 (a) | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 4,390 | $ | 3,533 | $ | (384 | ) | (a) | $ | (59 | ) | (b) | $ | (185 | ) | $ | (18 | ) | ||||||||||||||
30-Jun | 3,789 | 4,070 | 441 | (a) | 603 | 340 | 330 | |||||||||||||||||||||||||
30-Sep | 4,412 | 4,255 | 1,225 | (a) | 729 | (b) | 771 | 490 | ||||||||||||||||||||||||
31-Dec | 4,802 | 3,772 | (105 | ) | 405 | (91 | ) | 269 | ||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest. | |||||||||||||||||||||||||||||||
(b) | In the first and third quarter of 2013, Generation reclassified $5 million and $8 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest. | |||||||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 1,134 | $ | 1,160 | $ | 238 | $ | 209 | $ | 98 | $ | (81 | ) | |||||||||||||||||||
30-Jun | 1,128 | 1,080 | 259 | (a) | 232 | 111 | 96 | |||||||||||||||||||||||||
30-Sep | 1,222 | 1,156 | 288 | (a) | 278 | 126 | 126 | |||||||||||||||||||||||||
31-Dec | 1,079 | 1,068 | 196 | 236 | 73 | 109 | ||||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income. | |||||||||||||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||||||
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts: | ||||||||||||||||||||||||||||||||
Operating Revenues | Operating Income | Net Income | ||||||||||||||||||||||||||||||
on Common | ||||||||||||||||||||||||||||||||
Stock | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 993 | $ | 895 | $ | 149 | $ | 203 | $ | 89 | $ | 121 | ||||||||||||||||||||
30-Jun | 656 | 672 | 134 | 138 | 84 | 72 | ||||||||||||||||||||||||||
30-Sep | 693 | 728 | 133 | 155 | 81 | 92 | ||||||||||||||||||||||||||
31-Dec | 750 | 805 | 156 | 168 | 98 | 102 | ||||||||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||||||
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts: | ||||||||||||||||||||||||||||||||
Operating Revenues | Operating | Net Income | ||||||||||||||||||||||||||||||
Income | attributable to | |||||||||||||||||||||||||||||||
Common Shareholders | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 1,054 | $ | 880 | $ | 169 | $ | 163 | $ | 85 | $ | 77 | ||||||||||||||||||||
30-Jun | 653 | 653 | 55 | 69 | 16 | 22 | ||||||||||||||||||||||||||
30-Sep | 697 | 737 | 102 | 114 | 46 | 50 | ||||||||||||||||||||||||||
31-Dec | 761 | 794 | 113 | 101 | 52 | 47 | ||||||||||||||||||||||||||
Schedule_I_Condensed_Financial
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Condensed Financial Information of Parent Company Only Disclosure [Abstract] | ||||||||||||||||
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) | Exelon Corporation and Subsidiary Companies | |||||||||||||||
Schedule I – Condensed Financial Information of Parent (Exelon Corporate) | ||||||||||||||||
Condensed Statements of Operations and Other Comprehensive Income | ||||||||||||||||
For the Years Ended | ||||||||||||||||
December 31, | ||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | |||||||||||||
Operating expenses | ||||||||||||||||
Operating and maintenance | $ | 9 | $ | 9 | $ | 201 | ||||||||||
Operating and maintenance from affiliates | 38 | 34 | 72 | |||||||||||||
Other | 3 | 12 | 6 | |||||||||||||
Total operating expenses | 50 | 55 | 279 | |||||||||||||
Operating loss | (50 | ) | (55 | ) | (279 | ) | ||||||||||
Other income and (deductions) | ||||||||||||||||
Interest expense, net | (237 | ) | (116 | ) | (153 | ) | ||||||||||
Equity in earnings of investments | 1,779 | 1,903 | 1,278 | |||||||||||||
Interest income from affiliates, net | 53 | 36 | 75 | |||||||||||||
Other, net | (2 | ) | (78 | ) | 7 | |||||||||||
Total other income | 1,593 | 1,745 | 1,207 | |||||||||||||
Income before income taxes | 1,543 | 1,690 | 928 | |||||||||||||
Income taxes (benefit) | (80 | ) | (29 | ) | (232 | ) | ||||||||||
Net income | $ | 1,623 | $ | 1,719 | $ | 1,160 | ||||||||||
Other comprehensive income (loss) | ||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||
Prior service cost (benefit) reclassified to periodic costs | $ | (30 | ) | $ | — | $ | 1 | |||||||||
Actuarial loss reclassified to periodic cost | 147 | 208 | 168 | |||||||||||||
Transition obligation reclassified to periodic cost | — | — | 2 | |||||||||||||
Pension and non-pension postretirement benefit plan valuation | (497 | ) | 669 | (371 | ) | |||||||||||
adjustment | ||||||||||||||||
Unrealized loss on cash flow hedges | (148 | ) | (248 | ) | (120 | ) | ||||||||||
Unrealized gain on marketable securities | 1 | 2 | 2 | |||||||||||||
Unrealized gain on equity investments | 8 | 106 | 1 | |||||||||||||
Unrealized loss on foreign currency translation | (9 | ) | (10 | ) | — | |||||||||||
Reversal of CENG equity method AOCI | (116 | ) | — | — | ||||||||||||
Other comprehensive income (loss) | (644 | ) | 727 | (317 | ) | |||||||||||
Comprehensive income | $ | 979 | $ | 2,446 | $ | 843 | ||||||||||
See Notes to Financial Statements | ||||||||||||||||
Exelon Corporation and Subsidiary Companies | ||||||||||||||||
Schedule I – Condensed Financial Information of Parent (Exelon Corporate) | ||||||||||||||||
Condensed Statements of Cash Flows | ||||||||||||||||
For the Years Ended | ||||||||||||||||
December 31, | ||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | |||||||||||||
Net cash flows provided by operating activities | $ | 806 | $ | 1,053 | $ | 2,131 | ||||||||||
Cash flows from investing activities | ||||||||||||||||
Return on investment of direct financing lease termination | 335 | — | — | |||||||||||||
Changes in Exelon intercompany money pool | (83 | ) | (60 | ) | — | |||||||||||
Note receivable from affiliates | — | 484 | — | |||||||||||||
Capital expenditures | 1 | — | (30 | ) | ||||||||||||
Cash and restricted cash acquired from Constellation | — | — | 679 | |||||||||||||
Change in restricted cash | — | 38 | (38 | ) | ||||||||||||
Investment in affiliates | (70 | ) | (38 | ) | (67 | ) | ||||||||||
Other investing activities | (126 | ) | 15 | — | ||||||||||||
Net cash flows provided by (used in) investing activities | 57 | 439 | 544 | |||||||||||||
Cash flows from financing activities | ||||||||||||||||
Cash receipts from intercompany money pool | — | — | (703 | ) | ||||||||||||
Changes in short-term borrowings | — | 10 | (161 | ) | ||||||||||||
Issuance of long-term debt | 1,150 | — | — | |||||||||||||
Retirement of long-term debt | (23 | ) | (450 | ) | (77 | ) | ||||||||||
Dividends paid on common stock | (1,065 | ) | (1,249 | ) | (1,716 | ) | ||||||||||
Proceeds from employee stock plans | 35 | 47 | 73 | |||||||||||||
Other financing activities | (84 | ) | (6 | ) | 30 | |||||||||||
Net cash flows provided by (used in) financing activities | 13 | (1,648 | ) | (2,554 | ) | |||||||||||
Increase (decrease) in cash and cash equivalents | 876 | (156 | ) | 121 | ||||||||||||
Cash and cash equivalents at beginning of period | 3 | 159 | 38 | |||||||||||||
Cash and cash equivalents at end of period | $ | 879 | $ | 3 | $ | 159 | ||||||||||
See Notes to Financial Statements | ||||||||||||||||
Exelon Corporation and Subsidiary Companies | ||||||||||||||||
Schedule I – Condensed Financial Information of Parent (Exelon Corporate) | ||||||||||||||||
Condensed Balance Sheets | ||||||||||||||||
December 31, | ||||||||||||||||
(In millions) | 2014 | 2013 | ||||||||||||||
ASSETS | ||||||||||||||||
Current assets | ||||||||||||||||
Cash and cash equivalents | $ | 879 | $ | 3 | ||||||||||||
Accounts receivable, net | ||||||||||||||||
Other accounts receivable | 209 | 72 | ||||||||||||||
Accounts receivable from affiliates | 24 | 22 | ||||||||||||||
Deferred income taxes | 20 | 27 | ||||||||||||||
Notes receivable from affiliates | 818 | 179 | ||||||||||||||
Regulatory assets | 254 | 233 | ||||||||||||||
Other | 22 | 1 | ||||||||||||||
Total current assets | 2,226 | 537 | ||||||||||||||
Property, plant and equipment, net | 54 | 57 | ||||||||||||||
Deferred debits and other assets | ||||||||||||||||
Regulatory assets | 3,186 | 3,005 | ||||||||||||||
Investments in affiliates | 26,670 | 26,390 | ||||||||||||||
Deferred income taxes | 2,187 | 1,890 | ||||||||||||||
Notes receivable from affiliates | 943 | 1,522 | ||||||||||||||
Other | 172 | 17 | ||||||||||||||
Total deferred debits and other assets | 33,158 | 32,824 | ||||||||||||||
Total assets | $ | 35,438 | $ | 33,418 | ||||||||||||
See Notes to Financial Statements | ||||||||||||||||
Exelon Corporation and Subsidiary Companies | ||||||||||||||||
Schedule I – Condensed Financial Information of Parent (Exelon Corporate) | ||||||||||||||||
Condensed Balance Sheets | ||||||||||||||||
December 31, | ||||||||||||||||
(In millions) | 2014 | 2013 | ||||||||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||||||||||
Current liabilities | ||||||||||||||||
Long-term debt due within one year | $ | 1,409 | $ | 10 | ||||||||||||
Accounts payable | 2 | 43 | ||||||||||||||
Unamortized energy contract liabilities | — | 12 | ||||||||||||||
Accrued expenses | 25 | 106 | ||||||||||||||
Deferred income taxes | 60 | 26 | ||||||||||||||
Regulatory liabilities | 51 | 2 | ||||||||||||||
Other | 75 | 54 | ||||||||||||||
Total current liabilities | 1,622 | 253 | ||||||||||||||
Long-term debt | 2,841 | 3,033 | ||||||||||||||
Long-term debt to affiliate | 182 | 176 | ||||||||||||||
Deferred credits and other liabilities | ||||||||||||||||
Regulatory liabilities | 37 | 43 | ||||||||||||||
Pension obligations | 7,638 | 6,444 | ||||||||||||||
Non-pension postretirement benefit obligations | 16 | 393 | ||||||||||||||
Deferred income taxes | 93 | 70 | ||||||||||||||
Other | 398 | 271 | ||||||||||||||
Total deferred credits and other liabilities | 8,182 | 7,221 | ||||||||||||||
Total liabilities | 12,827 | 10,683 | ||||||||||||||
Commitments and contingencies | ||||||||||||||||
Shareholders’ equity | ||||||||||||||||
Common stock (No par value, 2,000 shares authorized, 860 and 857 shares | 16,709 | 16,741 | ||||||||||||||
outstanding at December 31, 2014 and 2013, respectively) | ||||||||||||||||
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013, | (2,327 | ) | (2,327 | ) | ||||||||||||
respectively) | ||||||||||||||||
Retained earnings | 10,910 | 10,358 | ||||||||||||||
Accumulated other comprehensive loss, net | (2,684 | ) | (2,040 | ) | ||||||||||||
Total shareholders’ equity | 22,608 | 22,732 | ||||||||||||||
BGE preference stock not subject to mandatory redemption | 3 | 3 | ||||||||||||||
Total liabilities and shareholders’ equity | $ | 35,438 | $ | 33,418 | ||||||||||||
See Notes to Financial Statements | ||||||||||||||||
Basis of Presentation | ||||||||||||||||
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation. | ||||||||||||||||
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. Exelon owned none of PECO’s preference securities, which PECO redeemed in 2013. | ||||||||||||||||
Mergers | ||||||||||||||||
On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the Merger Agreement with PHI. | ||||||||||||||||
On March 12, 2012, Exelon Corporation 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 the customer supply and generation businesses that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger. | ||||||||||||||||
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 at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the merger with Constellation. Also see Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information on BGE’s push-down accounting treatment. | ||||||||||||||||
Debt and Credit Agreements | ||||||||||||||||
Short-Term Borrowings | ||||||||||||||||
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 2014 and December 31, 2013. | ||||||||||||||||
Credit Agreements | ||||||||||||||||
On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $500 million through May 2019. As of December 31, 2014, Exelon Corporation had available capacity under those commitments of $494 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporation’s credit agreement. | ||||||||||||||||
Long-Term Debt | ||||||||||||||||
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2014 and December 31, 2013: | ||||||||||||||||
Maturity | December 31, | |||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||
Long-term debt | ||||||||||||||||
Junior subordinated notes | 6.5 | % | 2017 | $ | 1,150 | $ | — | |||||||||
Senior unsecured notes (a) | 4.9 | % | - | 7.6 | % | 2015-2035 | 2,658 | 2,658 | ||||||||
Total long-term debt | 3,808 | 2,658 | ||||||||||||||
Unamortized debt discount and premium, net | 1 | 2 | ||||||||||||||
Fair value adjustment | 441 | 383 | ||||||||||||||
Long-term debt due within one year | (1,409 | ) | (10 | ) | ||||||||||||
Long-term debt | $ | 2,841 | $ | 3,033 | ||||||||||||
___________ | ||||||||||||||||
(a) | Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. | |||||||||||||||
The debt maturities for Exelon Corporate for the periods 2015, 2016, 2017, 2018, 2019 and thereafter are as follows: | ||||||||||||||||
2015 | $ | 1,350 | ||||||||||||||
2016 | — | |||||||||||||||
2017 | 1,150 | |||||||||||||||
2018 | — | |||||||||||||||
2019 | — | |||||||||||||||
Remaining years | 1,308 | |||||||||||||||
Total long-term debt | $ | 3,808 | ||||||||||||||
Commitments and Contingencies | ||||||||||||||||
See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions. | ||||||||||||||||
Related Party Transactions | ||||||||||||||||
The financial statements of Exelon Corporate include related party transactions as presented in the tables below: | ||||||||||||||||
For the Years Ended | ||||||||||||||||
December 31, | ||||||||||||||||
(In millions) | 2014 | 2013 | 2012 | |||||||||||||
Operating and maintenance from affiliates: | ||||||||||||||||
Business Services Company, LLC (a) | $ | 38 | $ | 34 | $ | 72 | ||||||||||
Interest income from affiliates, net: | ||||||||||||||||
Exelon Generation Consolidated | $ | 53 | $ | 36 | $ | 75 | ||||||||||
Equity in earnings of investments: | ||||||||||||||||
Exelon Energy Delivery Company, LLC (b) | $ | 958 | $ | 834 | $ | 713 | ||||||||||
Exelon Ventures Company, LLC (c) | 926 | 1,076 | 564 | |||||||||||||
UII, LLC | (6 | ) | (2 | ) | 25 | |||||||||||
Exelon Transmission Company, LLC | (7 | ) | (5 | ) | (3 | ) | ||||||||||
Exelon Enterprise | (1 | ) | — | — | ||||||||||||
Exelon Generation Consolidated | (91 | ) | — | — | ||||||||||||
Exelon Consolidations (d) | — | — | (21 | ) | ||||||||||||
Total equity in earnings of investments | $ | 1,779 | $ | 1,903 | $ | 1,278 | ||||||||||
Cash contributions received from affiliates | $ | 1,370 | $ | 1,175 | $ | 2,074 | ||||||||||
December 31, | ||||||||||||||||
(in millions) | 2014 | 2013 | ||||||||||||||
Accounts receivable from affiliates (current): | ||||||||||||||||
Business Services Company, LLC (a) | $ | 2 | $ | 3 | ||||||||||||
Generation | 12 | 7 | ||||||||||||||
ComEd | 3 | 9 | ||||||||||||||
PECO | 2 | 2 | ||||||||||||||
BGE | 5 | 1 | ||||||||||||||
Total accounts receivable from affiliates (current) | $ | 24 | $ | 22 | ||||||||||||
Notes receivable from affiliates (current): | ||||||||||||||||
Business Services Company, LLC (a) | $ | 262 | $ | 179 | ||||||||||||
Exelon Generation Consolidated (e) | $ | 556 | $ | — | ||||||||||||
Total receivable from affiliates (current): | $ | 818 | $ | 179 | ||||||||||||
Investments in affiliates: | ||||||||||||||||
Business Services Company, LLC (a) | $ | 193 | $ | 201 | ||||||||||||
Exelon Energy Delivery Company, LLC (b) | 13,590 | 12,956 | ||||||||||||||
Exelon Ventures Company, LLC (c) | — | 12,750 | ||||||||||||||
UII, LLC | 130 | 470 | ||||||||||||||
Exelon Transmission Company, LLC | 1 | 3 | ||||||||||||||
VEBA | 9 | 10 | ||||||||||||||
Exelon Enterprises | 23 | — | ||||||||||||||
Exelon Generation Consolidated | 12,720 | — | ||||||||||||||
Exelon Consolidations | 4 | — | ||||||||||||||
Total investments in affiliates | $ | 26,670 | $ | 26,390 | ||||||||||||
Notes receivable from affiliates (non-current): | ||||||||||||||||
Generation (e) | $ | 943 | $ | 1,522 | ||||||||||||
Long-term debt to affiliates (non-current): | ||||||||||||||||
ComEd | $ | 182 | $ | 176 | ||||||||||||
_____________________ | ||||||||||||||||
(a) | Exelon Corporate 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. | |||||||||||||||
(b) | Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE. | |||||||||||||||
(c) | Exelon Ventures Company, LLC primarily consisted of Generation and was fully dissolved as of December 31, 2014. Exelon Enterprises, Exelon Generation Consolidated, and Exelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014. | |||||||||||||||
(d) | Equity in earnings of investments for Exelon Consolidations represents the intercompany income component that offsets the corresponding intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate. | |||||||||||||||
(e) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. |
Schedule_II_Valuation_and_Qual
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Valuation and Qualifying Accounts [Abstract] | ||||||||||||||||||||
Schedule II - Valuation and Qualifying Accounts | Exelon Corporation and Subsidiary Companies | |||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions and adjustments | ||||||||||||||||||||
Description | Balance at | Charged to | Charged | Deductions | Balance at | |||||||||||||||
Beginning | Costs and | to Other | End | |||||||||||||||||
of Period | Expenses | Accounts | of Period | |||||||||||||||||
(in millions) | ||||||||||||||||||||
For the year ended December 31, 2014 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 272 | $ | 175 | $ | 69 | (c) | $ | 205 | (d) | $ | 311 | ||||||||
Deferred tax valuation allowance | 13 | — | 37 | — | 50 | |||||||||||||||
Reserve for obsolete materials | 58 | 5 | 34 | 2 | 95 | |||||||||||||||
For the year ended December 31, 2013 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 293 | $ | 121 | $ | 37 | (c) | $ | 179 | (d) | $ | 272 | ||||||||
Deferred tax valuation allowance | 36 | 1 | — | 24 | 13 | |||||||||||||||
Reserve for obsolete materials | 53 | 17 | — | 12 | 58 | |||||||||||||||
For the year ended December 31, 2012 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 199 | $ | 144 | $ | 136 | (b)(c) | $ | 186 | (d) | $ | 293 | ||||||||
Deferred tax valuation allowance | 10 | 18 | 18 | (b) | 10 | 36 | ||||||||||||||
Reserve for obsolete materials | 60 | 2 | 2 | (b) | 11 | 53 | ||||||||||||||
___________________ | ||||||||||||||||||||
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||||||||||||
(b) | Primarily represents the addition of Constellation’s and BGE’s results as of March 12, 2012, the date of the merger. | |||||||||||||||||||
(c) | Includes charges for late payments and non-service receivables. | |||||||||||||||||||
(d) | Write-off of individual accounts receivable. | |||||||||||||||||||
Exelon Generation Company, LLC and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Generation | ||||||||||||||||||||
1 | Financial Statements: | |||||||||||||||||||
Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP | ||||||||||||||||||||
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Balance Sheets at December 31, 2014 and 2013 | ||||||||||||||||||||
Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Notes to Consolidated Financial Statements | ||||||||||||||||||||
2 | Financial Statement Schedules: | |||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto | ||||||||||||||||||||
Exelon Generation Company, LLC and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions and adjustments | ||||||||||||||||||||
Description | Balance at | Charged to | Charged | Deductions | Balance at | |||||||||||||||
Beginning | Costs and | to Other | End | |||||||||||||||||
of Period | Expenses | Accounts | of Period | |||||||||||||||||
(in millions) | ||||||||||||||||||||
For the year ended December 31, 2014 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 57 | $ | 14 | $ | 8 | $ | 19 | $ | 60 | ||||||||||
Deferred tax valuation allowance | 11 | — | 37 | — | 48 | |||||||||||||||
Reserve for obsolete materials | 55 | 5 | 32 | (1 | ) | 93 | ||||||||||||||
For the year ended December 31, 2013 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 84 | $ | (16 | ) | $ | — | $ | 11 | $ | 57 | |||||||||
Deferred tax valuation allowance | 35 | 1 | — | 25 | 11 | |||||||||||||||
Reserve for obsolete materials | 50 | 16 | — | 11 | 55 | |||||||||||||||
For the year ended December 31, 2012 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 29 | $ | — | $ | 66 | (a) | $ | 11 | $ | 84 | |||||||||
Deferred tax valuation allowance | — | 17 | 18 | (a) | — | 35 | ||||||||||||||
Reserve for obsolete materials | 59 | — | 2 | (a) | 11 | 50 | ||||||||||||||
____________________ | ||||||||||||||||||||
(a) | Represents the addition of Constellation’s results as of March 12, 2012, the date of the merger. | |||||||||||||||||||
Commonwealth Edison Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
ComEd | ||||||||||||||||||||
1 | Financial Statements: | |||||||||||||||||||
Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP | ||||||||||||||||||||
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Balance Sheets at December 31, 2014 and 2013 | ||||||||||||||||||||
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Notes to Consolidated Financial Statements | ||||||||||||||||||||
2 | Financial Statement Schedules: | |||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto | ||||||||||||||||||||
Commonwealth Edison Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions and adjustments | ||||||||||||||||||||
Description | Balance at | Charged to | Charged | Deductions | Balance at | |||||||||||||||
Beginning | Costs and | to Other | End | |||||||||||||||||
of Period | Expenses | Accounts | of Period | |||||||||||||||||
(in millions) | ||||||||||||||||||||
For the year ended December 31, 2014 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 62 | $ | 45 | $ | 33 | (a) | $ | 56 | (b) | $ | 84 | ||||||||
Reserve for obsolete materials | 2 | — | 2 | 2 | 2 | |||||||||||||||
For the year ended December 31, 2013 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 70 | $ | 33 | $ | 29 | (a) | $ | 70 | (b) | $ | 62 | ||||||||
Reserve for obsolete materials | 2 | 1 | — | 1 | 2 | |||||||||||||||
For the year ended December 31, 2012 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 78 | $ | 42 | $ | 26 | (a) | $ | 76 | (b) | $ | 70 | ||||||||
Reserve for obsolete materials | 1 | 1 | — | — | 2 | |||||||||||||||
_____________________ | ||||||||||||||||||||
(a) | Primarily charges for late payments and non-service receivables. | |||||||||||||||||||
(b) | Write-off of individual accounts receivable. | |||||||||||||||||||
PECO Energy Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
PECO | ||||||||||||||||||||
1 | Financial Statements: | |||||||||||||||||||
Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP | ||||||||||||||||||||
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Balance Sheets at December 31, 2014 and 2013 | ||||||||||||||||||||
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Notes to Consolidated Financial Statements | ||||||||||||||||||||
2 | Financial Statement Schedules: | |||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto | ||||||||||||||||||||
PECO Energy Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions and adjustments | ||||||||||||||||||||
Description | Balance at | Charged to | Charged | Deductions | Balance at | |||||||||||||||
Beginning | Costs and | to Other | End | |||||||||||||||||
of Period | Expenses | Accounts | of Period | |||||||||||||||||
(in millions) | ||||||||||||||||||||
For the year ended December 31, 2014 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 107 | $ | 52 | $ | 11 | (b) | $ | 70 | (c) | $ | 100 | ||||||||
Reserve for obsolete materials | 1 | — | — | — | 1 | |||||||||||||||
For the year ended December 31, 2013 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 99 | $ | 61 | $ | 7 | (b) | $ | 60 | (c) | $ | 107 | ||||||||
Reserve for obsolete materials | 1 | — | — | — | 1 | |||||||||||||||
For the year ended December 31, 2012 | ||||||||||||||||||||
Allowance for uncollectible accounts (a) | $ | 92 | $ | 60 | $ | 8 | (b) | $ | 61 | (c) | $ | 99 | ||||||||
Reserve for obsolete materials | 1 | — | — | — | 1 | |||||||||||||||
_____________________ | ||||||||||||||||||||
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||||||||||||
(b) | Primarily charges for late payments. | |||||||||||||||||||
(c) | Write-off of individual accounts receivable. | |||||||||||||||||||
Baltimore Gas and Electric Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
BGE | ||||||||||||||||||||
1 | Financial Statements: | |||||||||||||||||||
Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP | ||||||||||||||||||||
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Consolidated Balance Sheets at December 31, 2014 and 2013 | ||||||||||||||||||||
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012 | ||||||||||||||||||||
Notes to Consolidated Financial Statements | ||||||||||||||||||||
2 | Financial Statement Schedules: | |||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto | ||||||||||||||||||||
Baltimore Gas and Electric Company and Subsidiary Companies | ||||||||||||||||||||
Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||||||
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions and adjustments | ||||||||||||||||||||
Description | Balance at | Charged to | Charged | Deductions | Balance at | |||||||||||||||
Beginning | Costs and | to Other | End | |||||||||||||||||
of Period | Expenses | Accounts | of Period | |||||||||||||||||
(in millions) | ||||||||||||||||||||
For the year ended December 31, 2014 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 46 | $ | 64 | $ | 17 | (b) | $ | 60 | (a) | $ | 67 | ||||||||
Deferred tax valuation allowance | 1 | — | — | — | 1 | |||||||||||||||
Reserve for obsolete materials | 1 | — | — | 1 | — | |||||||||||||||
For the year ended December 31, 2013 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 40 | $ | 43 | $ | 1 | $ | 38 | (a) | $ | 46 | |||||||||
Deferred tax valuation allowance | 1 | — | — | — | 1 | |||||||||||||||
Reserve for obsolete materials | 1 | — | — | — | 1 | |||||||||||||||
For the year ended December 31, 2012 | ||||||||||||||||||||
Allowance for uncollectible accounts | $ | 38 | $ | 45 | $ | — | $ | 43 | (a) | $ | 40 | |||||||||
Deferred tax valuation allowance | — | 1 | — | — | 1 | |||||||||||||||
Reserve for obsolete materials | — | 1 | — | — | 1 | |||||||||||||||
_____________________ | ||||||||||||||||||||
(a) | Write-off of individual accounts receivable. | |||||||||||||||||||
(b) | Primarily charges for late payments. |
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 12 Months Ended | |
Dec. 31, 2014 | ||
Accounting Policies [Abstract] | ||
Description of Business (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 — Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction. | ||
On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further information regarding the integration 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, 2014, 2013 and 2012 and the financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2014. | ||
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, 2014 and December 31, 2013, 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 of 99% for certain periods of time, and CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for these certain subsidiaries. | ||
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 additional12.5% 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, 2014 and December 31, 2013, 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 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. | ||
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) | 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) | Reclassifications (Exelon, Generation, ComEd, PECO and BGE) | |
Certain prior year amounts in the registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, financial positions, or cash flows from operating activities. | ||
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE) | 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 or revenue 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) | 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 Constellation 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) | 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 Other income and deductions (interest income) on their Consolidated Statements of Operations and Comprehensive Income. | ||
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) | 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 Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE) | ||
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2014 and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers. | ||
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2014 and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2014, 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) | 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 customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change in estimate, refer to Note 6 — Accounts Receivable. | ||
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. 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) | 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 disclose (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 disclosed, 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) | 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, coal 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) | 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 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 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 (Exelon, Generation, ComEd, PECO and BGE) | |
Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. ComEd, PECO and BGE also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. 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. | ||
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 and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment. | ||
Nuclear Fuel (Exelon and Generation) | 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. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. 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) | 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 (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, 2014 and 2013, there were not 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 $13 million, $10 million and $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, respectively. These costs primarily related to the possible development of new renewable energy projects. | ||
Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE) | 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. | ||
Depreciation, Depletion, and Amortization (Exelon, Generation, ComEd, PECO and BGE) | 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 oil and gas reserves are based on internal calculations. | ||
Amortization of regulatory assets and liabilities are recorded over the recovery or refund 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 or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, generally, 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. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, 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. | ||
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) | 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 throughout 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 and Comprehensive Income 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 (Exelon, Generation, ComEd, PECO and BGE) | 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. | ||
Allowance For Funds Used During Construction (Exelon, Generation, ComEd, PECO and BGE) | 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. | |
Guarantees (Exelon, Generation, ComEd, PECO and BGE) | 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. | ||
Long-lived Assets (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. Indicators of impairment may include a deteriorating business climate, including, but not limited to, current energy prices and market conditions, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. 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 less costs to sell. | |
Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows from contracts that are accounted for as intangible contract assets and liabilities recorded 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). See Note 8 — Impairment of Long-Lived Assets for additional information. | ||
Goodwill (Exelon, Generation, ComEd, PECO and BGE) | 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, Generation's and ComEd’s goodwill. | |
Equity Method Investments (Exelon, Generation, ComEd, PECO and BGE) | 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 other than 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. | |
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, 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. | ||
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. | ||
Direct Financing Lease Investments (Exelon, Generation, ComEd, PECO and BGE) | Direct Financing Lease Investments. Direct financing lease investments represent the estimated residual values of leased coal-fired plants in Georgia. 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. | |
Derivatives Financial Instruments (Exelon, Generation, ComEd, PECO and BGE) | 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 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 Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivatives executed to hedge economic risk related to 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) | 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 July 14, 2014, Exelon became the sponsor of all of CENG's pension and other postretirement benefit 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. | ||
New Accounting Pronouncements (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 management believes may significantly affect 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. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows. | ||
Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force) | ||
In November 2014, the FASB issued authoritative guidance that allows acquired entities to apply pushdown accounting (i.e., reflecting the acquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SEC rescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made it optional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the most recent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financial statements of the Registrants; however, the Registrants will assess the potential impact of the guidance on future acquisitions. | ||
The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants. | ||
Revenue from Contracts with Customers | ||
In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new guidance replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying | ||
principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016. Early adoption is not permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. |
Significant_Accounting_Policie2
Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Accounting Policies [Abstract] | |||||||||||||||||||||
Schedule Of Capitalized Software | The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year: | ||||||||||||||||||||
Net unamortized software costs | Exelon (a) | Generation (a) | ComEd | PECO | BGE | ||||||||||||||||
December 31, 2014 | $ | 596 | $ | 193 | $ | 133 | $ | 84 | $ | 163 | |||||||||||
December 31, 2013 | 479 | 129 | 101 | 71 | 155 | ||||||||||||||||
Amortization of capitalized software costs | Exelon (a) (b) | Generation (a) (b) | ComEd | PECO | BGE (b) | ||||||||||||||||
2014 | $ | 186 | $ | 59 | $ | 45 | $ | 28 | $ | 43 | |||||||||||
2013 | 198 | 67 | 52 | 33 | 36 | ||||||||||||||||
2012 | 208 | 81 | 56 | 30 | 32 | ||||||||||||||||
_______________________ | |||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | ||||||||||||||||||||
(b) | 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 year ended December 31, 2012. | ||||||||||||||||||||
Schedule Of Capitalized Interest And AFUDC | The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year: | ||||||||||||||||||||
Exelon(a)(b) | Generation(a)(b) | ComEd | PECO | BGE (b) | |||||||||||||||||
2014 | Total incurred interest (c) | $ | 1,144 | $ | 419 | $ | 323 | $ | 115 | $ | 118 | ||||||||||
Capitalized interest | 63 | 63 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 37 | — | 5 | 8 | 24 | ||||||||||||||||
2013 | Total incurred interest (c) | $ | 1,423 | $ | 411 | $ | 584 | $ | 117 | $ | 129 | ||||||||||
Capitalized interest | 54 | 54 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 35 | — | 16 | 6 | 13 | ||||||||||||||||
2012 | Total incurred interest (c) | $ | 1,003 | $ | 368 | $ | 310 | $ | 125 | $ | 149 | ||||||||||
Capitalized interest | 67 | 67 | — | — | — | ||||||||||||||||
Credits to AFUDC debt and equity | 25 | — | 9 | 6 | 15 | ||||||||||||||||
_______________________ | |||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | ||||||||||||||||||||
(b) | 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 year ended December 31, 2012. | ||||||||||||||||||||
(c) | Includes interest expense to affiliates. |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 12 Months Ended | |||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||
Variable Interest Entity [Abstract] | ||||||||||||||||||||||||||
Schedule of 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, 2014 and 2013 are as follows: | |||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||
Exelon (a) (b) | Generation (b) | BGE | Exelon (a) | Generation | BGE | |||||||||||||||||||||
Current assets | $ | 1,271 | $ | 1,242 | $ | 21 | $ | 484 | $ | 446 | $ | 28 | ||||||||||||||
Noncurrent assets | 7,580 | 7,566 | 3 | 1,905 | 1,884 | 3 | ||||||||||||||||||||
Total assets | $ | 8,851 | $ | 8,808 | $ | 24 | $ | 2,389 | $ | 2,330 | $ | 31 | ||||||||||||||
Current liabilities | $ | 611 | $ | 526 | $ | 77 | $ | 566 | $ | 481 | $ | 74 | ||||||||||||||
Noncurrent liabilities | 2,730 | 2,600 | 120 | 774 | 562 | 195 | ||||||||||||||||||||
Total liabilities | $ | 3,341 | $ | 3,126 | $ | 197 | $ | 1,340 | $ | 1,043 | $ | 269 | ||||||||||||||
_______________________ | ||||||||||||||||||||||||||
(a) | Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||||||||||||||||||||||||
(b) | Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||||||||||||||||||||||
31-Dec-13 | Commercial | Equity | Total | |||||||||||||||||||||||
Agreement | Investment | |||||||||||||||||||||||||
VIEs | VIEs | |||||||||||||||||||||||||
Total assets(a) | $ | 128 | $ | 332 | $ | 460 | ||||||||||||||||||||
Total liabilities(a) | 17 | 123 | 140 | |||||||||||||||||||||||
Exelon's ownership interest in VIE(a) | — | 86 | 86 | |||||||||||||||||||||||
Other ownership interests in VIE(a) | 111 | 123 | 234 | |||||||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||||
Carrying amount of equity method investments | 7 | 67 | 74 | |||||||||||||||||||||||
Contract intangible asset | 9 | — | 9 | |||||||||||||||||||||||
Debt and payment guarantees | — | 5 | 5 | |||||||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 44 | — | 44 | |||||||||||||||||||||||
___________________ | ||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||
(b) | 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 $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. | |||||||||||||||||||||||||
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities: | ||||||||||||||||||||||||||
31-Dec-14 | Commercial | Equity | Total | |||||||||||||||||||||||
Agreement | Investment | |||||||||||||||||||||||||
VIEs | VIEs | |||||||||||||||||||||||||
Total assets(a) | $ | 506 | $ | 91 | $ | 597 | ||||||||||||||||||||
Total liabilities(a) | 237 | 49 | 286 | |||||||||||||||||||||||
Exelon's ownership interest in VIE(a) | — | 9 | 9 | |||||||||||||||||||||||
Other ownership interests in VIE(a) | 269 | 33 | 302 | |||||||||||||||||||||||
Registrants’ maximum exposure to loss: | ||||||||||||||||||||||||||
Carrying amount of equity method investments | — | 13 | 13 | |||||||||||||||||||||||
Contract intangible asset | 9 | — | 9 | |||||||||||||||||||||||
Debt and payment guarantees | — | 3 | 3 | |||||||||||||||||||||||
Net assets pledged for Zion Station decommissioning(b) | 27 | — | 27 | |||||||||||||||||||||||
As of December 31, 2014 and 2013, these assets and liabilities primarily consisted of the following: | ||||||||||||||||||||||||||
December 31, 2014 | December 31, 2013 | |||||||||||||||||||||||||
Exelon | Generation | BGE | Exelon | Generation | BGE | |||||||||||||||||||||
Cash and cash equivalents | $ | 392 | $ | 392 | $ | — | $ | 62 | $ | 62 | $ | — | ||||||||||||||
Restricted cash | 117 | 96 | 21 | 80 | 52 | 28 | ||||||||||||||||||||
Accounts receivable, net | ||||||||||||||||||||||||||
Customer | 297 | 297 | — | 260 | 260 | — | ||||||||||||||||||||
Other | 57 | 57 | — | — | — | — | ||||||||||||||||||||
Mark-to-market derivatives assets | 171 | 171 | — | 21 | 21 | — | ||||||||||||||||||||
Inventory | ||||||||||||||||||||||||||
Materials and supplies | 172 | 172 | — | — | — | — | ||||||||||||||||||||
Other current assets | 33 | 26 | — | 34 | 23 | — | ||||||||||||||||||||
Total current assets | 1,239 | 1,211 | 21 | 457 | 418 | 28 | ||||||||||||||||||||
Property, plant and equipment, net | 4,638 | 4,638 | — | 1,171 | 1,171 | — | ||||||||||||||||||||
Nuclear decommissioning trust funds | 2,097 | 2,097 | — | — | — | — | ||||||||||||||||||||
Goodwill | 47 | 47 | — | — | — | — | ||||||||||||||||||||
Mark-to-market derivatives assets | 44 | 44 | — | — | — | — | ||||||||||||||||||||
Other noncurrent assets | 95 | 82 | 3 | 127 | 106 | 3 | ||||||||||||||||||||
Total noncurrent assets | 6,921 | 6,908 | 3 | 1,298 | 1,277 | 3 | ||||||||||||||||||||
Total assets | $ | 8,160 | $ | 8,119 | $ | 24 | $ | 1,755 | $ | 1,695 | $ | 31 | ||||||||||||||
Long-term debt due within one year | $ | 87 | $ | 5 | $ | 75 | $ | 85 | $ | 5 | $ | 70 | ||||||||||||||
Accounts payable | 292 | 292 | — | 170 | 170 | — | ||||||||||||||||||||
Accrued expenses | 111 | 108 | 2 | 26 | 22 | 4 | ||||||||||||||||||||
Mark-to-market derivative liabilities | 24 | 24 | — | 29 | 29 | — | ||||||||||||||||||||
Unamortized energy contract liabilities | 22 | 22 | — | 5 | 5 | — | ||||||||||||||||||||
Other current liabilities | 25 | 25 | — | 5 | 5 | — | ||||||||||||||||||||
Total current liabilities | 561 | 476 | 77 | 320 | 236 | 74 | ||||||||||||||||||||
Long-term debt | 212 | 81 | 120 | 298 | 86 | 195 | ||||||||||||||||||||
Asset retirement obligations | 1,763 | 1,763 | — | — | — | — | ||||||||||||||||||||
Pension obligation(a) | 9 | 9 | — | — | — | — | ||||||||||||||||||||
Unamortized energy contract liabilities | 51 | 51 | — | 28 | 28 | — | ||||||||||||||||||||
Other noncurrent liabilities | 127 | 127 | — | 12 | 12 | — | ||||||||||||||||||||
Noncurrent liabilities | 2,162 | 2,031 | 120 | 338 | 126 | 195 | ||||||||||||||||||||
Total liabilities | $ | 2,723 | $ | 2,507 | $ | 197 | $ | 658 | $ | 362 | $ | 269 | ||||||||||||||
___________ | ||||||||||||||||||||||||||
(a) | Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details. |
Regulatory_Matters_Tables
Regulatory Matters (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Regulated Operations [Abstract] | ||||||||||||||||||||||||||||||||
Regulatory Construction Commitment | 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 | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||||||||||||
ComEd | $ | 335 | $ | 150 | $ | 172 | $ | 5 | $ | 4 | $ | 4 | ||||||||||||||||||||
PECO | 100 | 32 | 31 | 25 | 8 | 4 | ||||||||||||||||||||||||||
BGE | 351 | 77 | 104 | 77 | 57 | 36 | ||||||||||||||||||||||||||
Schedule of Regulatory Assets | The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2014 and 2013. | |||||||||||||||||||||||||||||||
December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 247 | $ | 3,009 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Deferred income taxes | 6 | 1,536 | — | 64 | — | 1,400 | 6 | 72 | ||||||||||||||||||||||||
AMI programs | 25 | 271 | 10 | 81 | 15 | 62 | — | 128 | ||||||||||||||||||||||||
Under-recovered distribution service costs | 251 | 120 | 251 | 120 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 8 | 49 | 6 | 47 | 2 | 2 | 1 | 8 | ||||||||||||||||||||||||
Fair value of BGE long-term debt | 7 | 183 | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 4 | 8 | — | — | — | — | 4 | 8 | ||||||||||||||||||||||||
Asset retirement obligations | 1 | 115 | 1 | 73 | — | 26 | — | 16 | ||||||||||||||||||||||||
MGP remediation costs | 36 | 221 | 30 | 189 | 6 | 31 | — | 1 | ||||||||||||||||||||||||
Under-recovered uncollectible accounts | — | 67 | — | 67 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy | 20 | 187 | 20 | 187 | — | — | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 37 | 11 | 26 | 7 | — | — | 11 | 4 | ||||||||||||||||||||||||
Deferred storm costs | 1 | 2 | — | — | — | — | 1 | 2 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 10 | 20 | — | — | — | — | 10 | 20 | ||||||||||||||||||||||||
Rate stabilization deferral | 75 | 85 | — | — | — | — | 75 | 85 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 89 | 159 | — | — | — | — | 89 | 159 | ||||||||||||||||||||||||
Merger integration costs | 2 | 6 | — | — | — | — | 2 | 6 | ||||||||||||||||||||||||
Conservation voltage reduction | 1 | 1 | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||
Under-recovered electric revenue decoupling | 7 | — | — | — | 7 | — | ||||||||||||||||||||||||||
Other (a) | 20 | 26 | 5 | 17 | 6 | 8 | 7 | — | ||||||||||||||||||||||||
Total regulatory assets | $ | 847 | $ | 6,076 | $ | 349 | $ | 852 | $ | 29 | $ | 1,529 | $ | 214 | $ | 510 | ||||||||||||||||
December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory assets | ||||||||||||||||||||||||||||||||
Pension and other postretirement benefits | $ | 221 | $ | 2,794 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Deferred income taxes | 10 | 1,459 | 2 | 65 | — | 1,317 | 8 | 77 | ||||||||||||||||||||||||
AMI programs | 5 | 159 | 5 | 35 | — | 58 | — | 66 | ||||||||||||||||||||||||
AMI meter events | — | 5 | — | — | — | 5 | — | — | ||||||||||||||||||||||||
Under-recovered distribution service costs | 178 | 285 | 178 | 285 | — | — | — | — | ||||||||||||||||||||||||
Debt costs | 12 | 56 | 9 | 53 | 3 | 3 | 1 | 8 | ||||||||||||||||||||||||
Fair value of BGE long-term debt | — | 219 | — | — | — | — | — | — | ||||||||||||||||||||||||
Fair value of BGE supply contracts | 12 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
Severance | 16 | 12 | 12 | — | — | — | 4 | 12 | ||||||||||||||||||||||||
Asset retirement obligations | 1 | 102 | 1 | 67 | — | 25 | — | 10 | ||||||||||||||||||||||||
MGP remediation costs | 40 | 212 | 33 | 178 | 6 | 33 | 1 | 1 | ||||||||||||||||||||||||
RTO start-up costs | 2 | — | 2 | — | — | — | — | — | ||||||||||||||||||||||||
Under-recovered uncollectible accounts | — | 48 | — | 48 | — | — | — | — | ||||||||||||||||||||||||
Renewable energy | 17 | 176 | 17 | 176 | — | — | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 53 | 9 | 52 | 6 | — | — | 1 | 3 | ||||||||||||||||||||||||
Deferred storm costs | 3 | 3 | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||
Electric generation-related regulatory asset | 13 | 30 | — | — | — | — | 13 | 30 | ||||||||||||||||||||||||
Rate stabilization deferral | 71 | 154 | — | — | — | — | 71 | 154 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 73 | 148 | — | — | — | — | 73 | 148 | ||||||||||||||||||||||||
Merger integration costs | 2 | 9 | — | — | — | — | 2 | 9 | ||||||||||||||||||||||||
Other (a) | 31 | 30 | 18 | 20 | 8 | 7 | 4 | 3 | ||||||||||||||||||||||||
Total regulatory assets | $ | 760 | $ | 5,910 | $ | 329 | $ | 933 | $ | 17 | $ | 1,448 | $ | 181 | $ | 524 | ||||||||||||||||
Schedule of Regulatory Liabilities | ||||||||||||||||||||||||||||||||
December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 51 | $ | 37 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Nuclear decommissioning | — | 2,879 | — | 2,389 | — | 490 | — | — | ||||||||||||||||||||||||
Removal costs | 118 | 1,448 | 94 | 1,249 | — | — | 24 | 199 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 25 | 2 | 25 | — | — | 2 | — | — | ||||||||||||||||||||||||
DLC program costs | — | 10 | — | — | — | 10 | — | — | ||||||||||||||||||||||||
Energy efficiency phase II | — | 32 | — | — | — | 32 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 8 | 94 | — | — | 8 | 94 | — | — | ||||||||||||||||||||||||
Gas distribution tax repairs | 20 | 29 | — | — | 20 | 29 | — | — | ||||||||||||||||||||||||
Energy and transmission programs | 68 | 16 | 3 | 16 | 58 | — | 7 | — | ||||||||||||||||||||||||
Over-recovered electric universal service fund costs | 2 | — | — | — | 2 | — | — | — | ||||||||||||||||||||||||
Revenue subject to refund | 3 | — | 3 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered gas revenue decoupling | 12 | — | — | — | — | — | 12 | — | ||||||||||||||||||||||||
Other | 3 | 3 | — | 1 | 2 | — | 1 | 1 | ||||||||||||||||||||||||
Total regulatory liabilities | $ | 310 | $ | 4,550 | $ | 125 | $ | 3,655 | $ | 90 | $ | 657 | $ | 44 | $ | 200 | ||||||||||||||||
December 31, 2013 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | Current | Noncurrent | |||||||||||||||||||||||||
Regulatory liabilities | ||||||||||||||||||||||||||||||||
Other postretirement benefits | $ | 2 | $ | 43 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
Nuclear decommissioning | — | 2,740 | — | 2,293 | — | 447 | — | — | ||||||||||||||||||||||||
Removal costs | 99 | 1,423 | 78 | 1,219 | — | — | 21 | 204 | ||||||||||||||||||||||||
Energy efficiency and demand response programs | 53 | — | 45 | — | 8 | — | — | — | ||||||||||||||||||||||||
DLC Program Costs | 1 | 10 | — | — | 1 | 10 | — | — | ||||||||||||||||||||||||
Energy efficiency phase II | — | 21 | — | — | — | 21 | — | — | ||||||||||||||||||||||||
Electric distribution tax repairs | 20 | 114 | — | — | 20 | 114 | — | — | ||||||||||||||||||||||||
Gas distribution tax repairs | 8 | 37 | — | — | 8 | 37 | ||||||||||||||||||||||||||
Energy and transmission programs | 78 | — | 9 | — | 58 | — | 11 | — | ||||||||||||||||||||||||
Over-recovered gas universal service fund costs | 8 | — | — | — | 8 | — | — | — | ||||||||||||||||||||||||
Revenue subject to refund | 38 | — | 38 | — | — | — | — | — | ||||||||||||||||||||||||
Over-recovered electric and gas revenue decoupling | 16 | — | — | — | — | — | 16 | — | ||||||||||||||||||||||||
Other | 4 | — | — | — | 3 | — | — | — | ||||||||||||||||||||||||
Total regulatory liabilities | $ | 327 | $ | 4,388 | $ | 170 | $ | 3,512 | $ | 106 | $ | 629 | $ | 48 | $ | 204 | ||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||
(a) | For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively. | |||||||||||||||||||||||||||||||
Purchase Of Receivables | The following tables provide information about the purchased receivables of the Registrants as of December 31, 2014 and 2013. | |||||||||||||||||||||||||||||||
As of December 31, 2014 | Exelon | ComEd | PECO | BGE | ||||||||||||||||||||||||||||
Purchased receivables (a) | $ | 290 | $ | 139 | $ | 76 | $ | 75 | ||||||||||||||||||||||||
Allowance for uncollectible accounts (b) | (42 | ) | (21 | ) | (8 | ) | (13 | ) | ||||||||||||||||||||||||
Purchased receivables, net | $ | 248 | $ | 118 | $ | 68 | $ | 62 | ||||||||||||||||||||||||
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 | ||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||
(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. |
Mergers_Acquisitions_and_Dispo1
Mergers, Acquisitions and Dispositions (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Business Combinations [Abstract] | ||||||||||||||||
Schedule of Business Acquisitions, by Acquisition | The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the Integrys acquisition by Generation: | |||||||||||||||
Total consideration transferred | $ | 332 | ||||||||||||||
Identifiable assets acquired and liabilities assumed | ||||||||||||||||
Working capital assets | $ | 389 | ||||||||||||||
Mark-to-market derivative assets | 185 | |||||||||||||||
Unamortized energy contract assets | 115 | |||||||||||||||
Customer relationships | 48 | |||||||||||||||
Working capital liabilities | (195 | ) | ||||||||||||||
Mark-to-market derivative liabilities | (57 | ) | ||||||||||||||
Unamortized energy contract liabilities | (109 | ) | ||||||||||||||
Deferred tax liability | (16 | ) | ||||||||||||||
Total net identifiable assets, at fair value | $ | 360 | ||||||||||||||
Bargain purchase gain (after-tax) | $ | 28 | ||||||||||||||
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 | BGE | Generation | Exelon | Statement of | |||||||||||
Period | Operations | |||||||||||||||
Location | ||||||||||||||||
BGE rate credit of $100 per | Q2 2012 | $ | 113 | $ | — | $ | 113 | Revenues | ||||||||
residential customer (a) | ||||||||||||||||
Customer investment fund to invest | 2012 to 2014 | — | — | 114 | O&M Expense | |||||||||||
in energy efficiency and low-income energy assistance to BGE customers | ||||||||||||||||
Contribution for renewable energy, | 2012 to 2014 | — | — | 2 | O&M Expense | |||||||||||
energy efficiency or related projects in Baltimore | ||||||||||||||||
Charitable contributions at $7 million | 2012 to 2021 | 28 | 35 | 70 | O&M Expense | |||||||||||
per year for 10 years | ||||||||||||||||
State funding for offshore wind | Q2 2012 | — | — | 32 | O&M Expense | |||||||||||
development projects | ||||||||||||||||
Miscellaneous tax benefits | Q2 2012 | (2 | ) | — | (2 | ) | Taxes Other Than Income | |||||||||
Total | $ | 139 | $ | 35 | $ | 329 | ||||||||||
_______________________ | ||||||||||||||||
(a) | 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. | |||||||||||||||
Summary of Asset Divestitures | ||||||||||||||||
Station | Net Generation Capacity | Location | Operating Segment | Percent Owned | ||||||||||||
Fore River | 726 | North Weymouth, MA | New England | 100% | ||||||||||||
West Valley | 185 | Salt Lake City, UT | Other | 100% | ||||||||||||
Keystone | 714 | Shelocta, PA | Mid-Atlantic | 41.98% | ||||||||||||
Conemaugh | 532 | New Florence, PA | Mid-Atlantic | 31.28% | ||||||||||||
Safe Harbor | 278 | Conestoga, PA | Mid-Atlantic | 66.70% | ||||||||||||
Quail Run | 488 | Odessa, TX | ERCOT | 100% | ||||||||||||
The table below presents the major classes of assets and liabilities held for sale at December 31, 2014. | ||||||||||||||||
December 31, 2014 | ||||||||||||||||
Assets: | ||||||||||||||||
Property, plant and equipment, net (a) | $ | 143 | ||||||||||||||
Inventory | 4 | |||||||||||||||
Total assets held for sale | $ | 147 | ||||||||||||||
Liabilities: | ||||||||||||||||
Accrued expenses | $ | 1 | ||||||||||||||
Asset retirement obligations | 4 | |||||||||||||||
Total liabilities held for sale (b) | $ | 5 | ||||||||||||||
_____________ | ||||||||||||||||
(a) The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information. | ||||||||||||||||
(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. | ||||||||||||||||
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | 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 | — | ||||||||||||||
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 | ||||||||||||||
Noncontrolling interest | 90 | 90 | ||||||||||||||
Deferred credits and other liabilities and preferred securities | 4,683 | 1,933 | ||||||||||||||
Total liabilities, preferred securities and noncontrolling interest | 15,535 | 9,311 | ||||||||||||||
Total purchase price | $ | 7,365 | $ | 5,264 | ||||||||||||
Business Acquisition, Pro Forma Information | 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. | |||||||||||||||
Exelon | Generation | |||||||||||||||
Year Ended December 31, | Year Ended December 31, | |||||||||||||||
(unaudited) | 2012 | 2011 (a) | 2012 | 2011 (a) | ||||||||||||
Total revenues | 26,700 | 30,712 | 17,013 | 19,494 | ||||||||||||
Net income attributable to Exelon | 2,092 | 974 | 1,205 | 324 | ||||||||||||
Basic earnings per share | 2.56 | 1.15 | n.a. | n.a. | ||||||||||||
Diluted earnings per share | 2.55 | 1.14 | n.a. | n.a. | ||||||||||||
_____________________ | ||||||||||||||||
(a) The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011. | ||||||||||||||||
(b) The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011. |
Investment_in_Constellation_En1
Investment in Constellation Energy Nuclear Group, LLC (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Business Combinations [Abstract] | |||||
Schedule of total equity in earnings of investment in CENG | The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above: | ||||
Fair Values | Exelon and Generation | ||||
Current assets | $ | 499 | |||
Nuclear decommissioning trust fund | 1,955 | ||||
Property, plant and equipment | 3,017 | ||||
Nuclear fuel | 482 | ||||
Other assets | 10 | ||||
Total assets | 5,963 | ||||
Current liabilities | 237 | ||||
Asset retirement obligation | 1,760 | ||||
Pension and other employee benefit obligations | 281 | ||||
Unamortized energy contract liabilities | 171 | ||||
Other liabilities | 114 | ||||
Total liabilities | 2,563 | ||||
Total net assets | $ | 3,400 | |||
Accounts_Receivable_Tables
Accounts Receivable (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Receivables [Abstract] | |||||||||||||||||||||
Schedule Of Accounts Notes Loans And Financing Receivable | Accounts receivable at December 31, 2014 and 2013 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: | ||||||||||||||||||||
2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unbilled customer revenues | $ | 1,381 | $ | 823 | (a) | $ | 204 | $ | 140 | $ | 214 | ||||||||||
Allowance for uncollectible | (311 | ) | (60 | ) | (84 | ) | (100 | ) | (c) | (67 | ) | (d) | |||||||||
accounts (b) | |||||||||||||||||||||
2013 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unbilled customer revenues | $ | 1,151 | $ | 584 | (a) | $ | 201 | $ | 161 | $ | 205 | ||||||||||
Allowance for uncollectible | (272 | ) | (57 | ) | (62 | ) | (107 | ) | (c) | (46 | ) | (d) | |||||||||
accounts (b) | |||||||||||||||||||||
_________________________ | |||||||||||||||||||||
(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 $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below. | ||||||||||||||||||||
(d) | At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income. |
Property_Plant_and_Equipment_T
Property, Plant, and Equipment (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Property, Plant and Equipment [Abstract] | |||||||||||
Property, Plant and Equipment | The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | ||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-80 | $ | 18,884 | $ | 17,334 | ||||||
Construction work in progress | N/A | 276 | 456 | ||||||||
Other property, plant and equipment (a) | 39-50 | 65 | 60 | ||||||||
Total property, plant and equipment | 19,225 | 17,850 | |||||||||
Less: accumulated depreciation | 3,432 | 3,184 | |||||||||
Property, plant and equipment, net | $ | 15,793 | $ | 14,666 | |||||||
_________________________ | |||||||||||
(a) | Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. | ||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-90 | $ | 30,157 | $ | 28,123 | ||||||
Electric—generation | Jan-56 | 22,911 | 20,420 | ||||||||
Gas—transportation and distribution | May-90 | 3,505 | 3,296 | ||||||||
Common—electric and gas | May-50 | 1,169 | 1,101 | ||||||||
Nuclear fuel (a) | 8-Jan | 5,947 | 5,196 | ||||||||
Construction work in progress | N/A | 2,167 | 1,890 | ||||||||
Other property, plant and equipment (b) | May-50 | 973 | 1,017 | ||||||||
Total property, plant and equipment | 66,829 | 61,043 | |||||||||
Less: accumulated depreciation (c) | 14,742 | 13,713 | |||||||||
Property, plant and equipment, net | $ | 52,087 | $ | 47,330 | |||||||
_________________________ | |||||||||||
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively. | ||||||||||
(b) | Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation. | ||||||||||
(c) | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | ||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—generation | Jan-56 | $ | 22,911 | 19,004,000,000 | $ | 20,420 | |||||
Nuclear fuel (a) | 8-Jan | 5,947 | 4,815,000,000 | 5,196 | |||||||
Construction work in progress | N/A | 1,404 | 1,352,000,000 | 1,129 | |||||||
Other property, plant and equipment (b) | Jun-31 | 295 | 374,000,000 | 400 | |||||||
Total property, plant and equipment | 30,557 | 27,145 | |||||||||
Less: accumulated depreciation (c) | 7,612 | 7,034 | |||||||||
Property, plant and equipment, net | $ | 22,945 | $ | 20,111 | |||||||
_________________________ | |||||||||||
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively. | ||||||||||
(b) | Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities. | ||||||||||
(c) | Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | ||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-90 | $ | 6,339 | $ | 6,100 | ||||||
Gas—distribution | May-90 | 1,761 | 1,660 | ||||||||
Common—electric and gas | May-40 | 623 | 578 | ||||||||
Construction work in progress | N/A | 317 | 196 | ||||||||
Other property, plant and equipment (a) | 20 | 32 | 32 | ||||||||
Total property, plant and equipment | 9,072 | 8,566 | |||||||||
Less: accumulated depreciation | 2,868 | 2,702 | |||||||||
Property, plant and equipment, net | $ | 6,204 | $ | 5,864 | |||||||
_______________________ | |||||||||||
(a) | Represents land held for future use and non utility property. | ||||||||||
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013: | |||||||||||
Average | 2014 | 2013 | |||||||||
Service Life | |||||||||||
(years) | |||||||||||
Asset Category | |||||||||||
Electric—transmission and distribution | May-65 | $ | 6,886 | $ | 6,669 | ||||||
Gas—transportation and distribution | May-70 | 2,039 | 1,932 | ||||||||
Common—electric and gas | May-50 | 618 | 600 | ||||||||
Construction work in progress | N/A | 154 | 101 | ||||||||
Other property, plant and equipment (a) | 50 | 21 | 17 | ||||||||
Total property, plant and equipment | 9,718 | 9,319 | |||||||||
Less: accumulated depreciation | 2,917 | 2,935 | |||||||||
Property, plant and equipment, net | $ | 6,801 | $ | 6,384 | |||||||
_________________________ | |||||||||||
(a) | Represents land held for future use and non utility property. | ||||||||||
Property Plant And Equipment Average Service Life Percentage By Asset Category Table | 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 | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.93 | % | 2.91 | % | 2.76 | % | |||||
Electric—generation | 3.5 | % | 3.35 | % | 3.15 | % | |||||
Gas | 2.13 | % | 2.06 | % | 2.03 | % | |||||
Common—electric and gas | 7.32 | % | 7.53 | % | 7.61 | % | |||||
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 | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.55 | % | 2.73 | % | 2.51 | % | |||||
Gas | 1.84 | % | 1.79 | % | 1.77 | % | |||||
Common—electric and gas | 5.16 | % | 6.65 | % | 7.54 | % | |||||
Average Service Life Percentage by Asset Category | 2014 | 2013 | 2012 | ||||||||
Electric—transmission and distribution | 2.96 | % | 2.91 | % | 2.92 | % | |||||
Gas | 2.47 | % | 2.36 | % | 2.33 | % | |||||
Common—electric and gas | 9.49 | % | 8.45 | % | 7.68 | % |
Recovered_Sheet1
Impairment of Long-Lived assets (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Impairment or Disposal of Tangible Assets Disclosure [Abstract] | ||||||||
Schedule of Capital Leased Assets | At December 31, 2014 and 2013, the components of the net investment in long-term leases were as follows: | |||||||
December 31, 2014 | December 31, 2013 | |||||||
Estimated residual value of leased assets | $ | 685 | $ | 1,465 | ||||
Less: unearned income | 324 | 767 | ||||||
Net investment in long-term leases | $ | 361 | $ | 698 | ||||
Jointly_Owned_Electric_Utility1
Jointly Owned Electric Utility Plant (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Public Utilities, Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||
Schedule of Jointly Owned Utility Plants | Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2014 and 2013 were as follows: | |||||||||||||||||||||||||||||||||||||||
Nuclear generation | Fossil fuel generation | Transmission | Other | |||||||||||||||||||||||||||||||||||||
Quad Cities | Peach | Salem (a) | Nine Mile Point Unit 2(g) | Keystone | Conemaugh | Wyman | PA (b) | DE/NJ (c) | Other (d) | |||||||||||||||||||||||||||||||
Bottom | ||||||||||||||||||||||||||||||||||||||||
(f) | (f) | |||||||||||||||||||||||||||||||||||||||
Operator | Generation | Generation | PSEG | Generation | GenOn | GenOn | FP&L | First | PSEG | |||||||||||||||||||||||||||||||
Nuclear | Energy | |||||||||||||||||||||||||||||||||||||||
Ownership interest | 75 | % | 50 | % | 42.59 | % | 82 | % | — | — | 5.89 | % | Various | 42.55 | % | 44.24 | % | |||||||||||||||||||||||
Exelon’s share at December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Plant (e) | $ | 995 | $ | 1,095 | $ | 531 | $ | 676 | $ | — | $ | — | $ | 3 | $ | 14 | $ | 64 | $ | 2 | ||||||||||||||||||||
Accumulated | 266 | 343 | 150 | 14 | — | — | 3 | 7 | 34 | 1 | ||||||||||||||||||||||||||||||
depreciation (e) | ||||||||||||||||||||||||||||||||||||||||
Construction work | 15 | 133 | 29 | 48 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||
in progress | ||||||||||||||||||||||||||||||||||||||||
Exelon’s share at December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Plant (e) | $ | 941 | $ | 883 | $ | 501 | $ | — | $ | 725 | $ | 399 | $ | 3 | $ | 14 | $ | 64 | $ | 2 | ||||||||||||||||||||
Accumulated depreciation (e) | 226 | 326 | 134 | — | 268 | 220 | 3 | 7 | 34 | 1 | ||||||||||||||||||||||||||||||
Construction work | 27 | 174 | 24 | — | 6 | 121 | — | — | — | — | ||||||||||||||||||||||||||||||
in progress | ||||||||||||||||||||||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||||||||||||||
(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, 2014 and 2013. | |||||||||||||||||||||||||||||||||||||||
(b) | PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above. | |||||||||||||||||||||||||||||||||||||||
(c) | PECO owns a 42.55% share in 131 miles of 500kV 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. | |||||||||||||||||||||||||||||||||||||||
(d) | Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey. | |||||||||||||||||||||||||||||||||||||||
(e) | Excludes asset retirement costs. |
Intangible_Assets_Tables
Intangible Assets (Tables) | 12 Months Ended | ||||||||||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||||||||||
Goodwill and Intangible Assets Disclosure [Abstract] | |||||||||||||||||||||||||||||||||
Schedule Of Goodwill | Exelon’s and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2014 and 2013 were as follows: | ||||||||||||||||||||||||||||||||
ComEd | Generation | Exelon | |||||||||||||||||||||||||||||||
Gross | Accumulated | Carrying | Gross | Carrying | Gross | Accumulated | Carrying | ||||||||||||||||||||||||||
Amount (a) | Impairment | Amount | Amount | Amount | Amount | Impairment | Amount | ||||||||||||||||||||||||||
Losses | Losses | ||||||||||||||||||||||||||||||||
Balance, January 1, 2013 | $ | 4,608 | $ | 1,983 | $ | 2,625 | $ | — | $ | — | $ | 4,608 | $ | 1,983 | $ | 2,625 | |||||||||||||||||
Goodwill from business combination | — | — | — | 47 | 47 | 47 | — | 47 | |||||||||||||||||||||||||
Balance, December 31, 2014 | $ | 4,608 | $ | 1,983 | $ | 2,625 | $ | 47 | $ | 47 | $ | 4,655 | $ | 1,983 | $ | 2,672 | |||||||||||||||||
_______________________ | |||||||||||||||||||||||||||||||||
(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 | Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and Other long-term assets and liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2014: | ||||||||||||||||||||||||||||||||
Weighted | Estimated amortization expense | ||||||||||||||||||||||||||||||||
Average | |||||||||||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||||||||||
Years (h) | Gross | Accumulated | Net | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||||||||||
Amortization | |||||||||||||||||||||||||||||||||
Exelon and Generation | |||||||||||||||||||||||||||||||||
Unamortized Energy Contracts (a) | |||||||||||||||||||||||||||||||||
Exelon Wind (b) | 18 | $ | 224 | $ | (55 | ) | $ | 169 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | $ | 14 | |||||||||||||||
Antelope Valley (c) | 25 | 190 | (12 | ) | 178 | 8 | 8 | 8 | 8 | 8 | |||||||||||||||||||||||
Constellation (d) | 1.5 | 1,499 | (1,451 | ) | 48 | 19 | (31 | ) | (21 | ) | 11 | 8 | |||||||||||||||||||||
CENG (e) | 1.7 | (97 | ) | 29 | (68 | ) | (20 | ) | (11 | ) | (15 | ) | (18 | ) | (15 | ) | |||||||||||||||||
Integrys (d) | 2.4 | 6 | (5 | ) | 1 | (8 | ) | 6 | 1 | 1 | — | ||||||||||||||||||||||
Customer Relationships | |||||||||||||||||||||||||||||||||
Constellation (d) | 12.4 | 214 | (58 | ) | 156 | 18 | 18 | 18 | 18 | 17 | |||||||||||||||||||||||
Integrys (d) | 10 | 48 | (1 | ) | 47 | 5 | 5 | 5 | 5 | 5 | |||||||||||||||||||||||
Trade Names | |||||||||||||||||||||||||||||||||
Constellation (d) | 10 | 243 | (79 | ) | 164 | 23 | 23 | 23 | 23 | 23 | |||||||||||||||||||||||
ComEd | |||||||||||||||||||||||||||||||||
Chicago settlement—1999 agreement (f) | 21.8 | 100 | (79 | ) | 21 | 3 | 3 | 4 | 4 | 4 | |||||||||||||||||||||||
Chicago settlement—2003 agreement (g) | 17.9 | 62 | (40 | ) | 22 | 4 | 4 | 3 | 3 | 3 | |||||||||||||||||||||||
Total intangible assets | $ | 2,489 | $ | (1,751 | ) | $ | 738 | $ | 66 | $ | 39 | $ | 40 | $ | 69 | $ | 67 | ||||||||||||||||
_________________________ | |||||||||||||||||||||||||||||||||
(a) | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | ||||||||||||||||||||||||||||||||
(b) | In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states. | ||||||||||||||||||||||||||||||||
(c) | In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc. | ||||||||||||||||||||||||||||||||
(d) | See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions. | ||||||||||||||||||||||||||||||||
(e) | See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||||||||||||||
(f) | 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. | ||||||||||||||||||||||||||||||||
(g) | 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 deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement. | ||||||||||||||||||||||||||||||||
(h) | Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement. | ||||||||||||||||||||||||||||||||
Schedule Of Finite-Lived Intangible Assets Amortization Expense | The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2014, 2013 and 2012: | ||||||||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon (a) | Generation (a) | ComEd | ||||||||||||||||||||||||||||||
2014 | $ | 179 | $ | 179 | $ | 7 | |||||||||||||||||||||||||||
2013 | 478 | 550 | 7 | ||||||||||||||||||||||||||||||
2012 | 1,150 | 1,145 | 7 | ||||||||||||||||||||||||||||||
Fair_Value_of_Financial_Assets1
Fair Value of Financial Assets and Liabilities (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis | The following tables present assets and liabilities measured and recorded at fair value on the Utilities' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013: | |||||||||||||||||||||||||||||||||||||||||||||||
ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | 25 | $ | — | $ | — | $ | 25 | $ | 12 | $ | — | $ | — | $ | 12 | $ | 103 | $ | — | $ | — | $ | 103 | ||||||||||||||||||||||||
Rabbi trust investments in Mutual funds (a) | — | — | — | — | 9 | — | — | 9 | 5 | — | — | 5 | ||||||||||||||||||||||||||||||||||||
Total assets | 25 | — | — | 25 | 21 | — | — | 21 | 108 | — | — | 108 | ||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation | — | (8 | ) | — | (8 | ) | — | (15 | ) | — | (15 | ) | — | (5 | ) | — | (5 | ) | ||||||||||||||||||||||||||||||
obligation | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | — | — | (207 | ) | (207 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
liabilities (b) | ||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (207 | ) | (215 | ) | — | (15 | ) | — | (15 | ) | — | (5 | ) | — | (5 | ) | |||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 25 | $ | (8 | ) | $ | (207 | ) | $ | (190 | ) | $ | 21 | $ | (15 | ) | $ | — | $ | 6 | $ | 108 | $ | (5 | ) | $ | — | $ | 103 | |||||||||||||||||||
ComEd | PECO | BGE | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | $ | — | $ | — | $ | — | $ | — | $ | 175 | $ | — | $ | — | $ | 175 | $ | 31 | $ | — | $ | — | $ | 31 | ||||||||||||||||||||||||
Rabbi trust investments in Mutual funds (a) | 5 | — | — | 5 | 9 | — | — | 9 | 6 | — | — | 6 | ||||||||||||||||||||||||||||||||||||
Total assets | 5 | — | — | 5 | 184 | — | — | 184 | 37 | — | — | 37 | ||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation | — | (8 | ) | — | (8 | ) | — | (17 | ) | — | (17 | ) | — | (6 | ) | — | (6 | ) | ||||||||||||||||||||||||||||||
obligation | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | — | — | (193 | ) | (193 | ) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
liabilities (b) | ||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | — | (8 | ) | (193 | ) | (201 | ) | — | (17 | ) | — | (17 | ) | — | (6 | ) | — | (6 | ) | |||||||||||||||||||||||||||||
Total net assets (liabilities) | $ | 5 | $ | (8 | ) | $ | (193 | ) | $ | (196 | ) | $ | 184 | $ | (17 | ) | $ | — | $ | 167 | $ | 37 | $ | (6 | ) | $ | — | $ | 31 | |||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||||||||||||||||||||||||||||||||||||||||||||||
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 463 | $ | 3 | $ | 448 | $ | 12 | $ | 463 | $ | 344 | $ | 344 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 21,164 | 1,208 | 20,417 | 1,311 | 22,936 | 19,132 | 19,751 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 648 | — | — | 648 | 648 | 648 | 631 | |||||||||||||||||||||||||||||||||||||||||
SNF obligation | 1,021 | — | 833 | — | 833 | 1,021 | 790 | |||||||||||||||||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 36 | $ | — | $ | 24 | $ | 12 | $ | 36 | $ | 22 | $ | 22 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 8,266 | — | 7,511 | 1,311 | 8,822 | 7,729 | 7,648 | |||||||||||||||||||||||||||||||||||||||||
SNF obligation | 1,021 | — | 833 | — | 833 | 1,021 | 790 | |||||||||||||||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 304 | $ | — | $ | 304 | $ | — | $ | 304 | $ | 184 | $ | 184 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 5,958 | — | 6,788 | — | 6,788 | 5,675 | 6,255 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trust | 206 | — | — | 213 | 213 | 206 | 202 | |||||||||||||||||||||||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | $ | 2,246 | $ | — | $ | 2,537 | $ | — | $ | 2,537 | $ | 2,197 | $ | 2,358 | ||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 184 | — | — | 199 | 199 | 184 | 180 | |||||||||||||||||||||||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||||||||||||||||||||||
Carrying | Fair Value | Carrying | Fair Value | |||||||||||||||||||||||||||||||||||||||||||||
Amount | Level 1 | Level 2 | Level 3 | Total | Amount | |||||||||||||||||||||||||||||||||||||||||||
Short-term liabilities | $ | 123 | $ | 3 | $ | 120 | $ | — | $ | 123 | $ | 138 | $ | 138 | ||||||||||||||||||||||||||||||||||
Long-term debt (including amounts due within one year) | 1,942 | — | 2,178 | — | 2,178 | 2,011 | 2,148 | |||||||||||||||||||||||||||||||||||||||||
Long-term debt to financing trusts | 258 | — | — | 236 | 236 | 258 | 249 | |||||||||||||||||||||||||||||||||||||||||
Fair value of financial liabilities recorded at the carrying amount | The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013: | |||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2014 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents (a) | $ | 405 | $ | — | $ | — | $ | 405 | $ | 1,119 | $ | — | $ | — | $ | 1,119 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 208 | 37 | — | 245 | 208 | 37 | — | 245 | ||||||||||||||||||||||||||||||||||||||||
Equity | ||||||||||||||||||||||||||||||||||||||||||||||||
Domestic | 2,423 | 2,207 | — | 4,630 | 2,423 | 2,207 | — | 4,630 | ||||||||||||||||||||||||||||||||||||||||
Foreign | 612 | — | — | 612 | 612 | — | — | 612 | ||||||||||||||||||||||||||||||||||||||||
Equity funds subtotal | 3,035 | 2,207 | — | 5,242 | 3,035 | 2,207 | — | 5,242 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt securities | — | 2,023 | 239 | 2,262 | — | 2,023 | 239 | 2,262 | ||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 996 | — | — | 996 | 996 | — | — | 996 | ||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 95 | — | 95 | — | 95 | — | 95 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 438 | — | 438 | — | 438 | — | 438 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 511 | — | 511 | — | — | 511 | — | — | — | 511 | |||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 996 | 3,067 | 239 | 4,302 | 996 | 3,067 | 239 | 4,302 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 366 | 366 | — | — | 366 | 366 | ||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | 83 | 83 | — | — | 83 | 83 | ||||||||||||||||||||||||||||||||||||||||
Real estate | — | — | 3 | 3 | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||||||||||||||||
Other | — | 301 | — | 301 | — | 301 | — | 301 | ||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds subtotal (b) | 4,239 | 5,612 | 691 | 10,542 | 4,239 | 5,612 | 691 | 10,542 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | ||||||||||||||||||||||||||||||||||||||||||||||||
decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | 15 | — | 15 | — | 15 | — | 15 | ||||||||||||||||||||||||||||||||||||||||
Equities | 6 | 1 | — | 7 | 6 | 1 | — | 7 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 5 | 3 | — | 8 | 5 | 3 | — | 8 | ||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 89 | — | 89 | — | 89 | — | 89 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 10 | — | 10 | — | 10 | — | 10 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 3 | — | 3 | — | 3 | — | 3 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 5 | 105 | — | 110 | 5 | 105 | — | 110 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 184 | 184 | — | — | 184 | 184 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | 11 | 121 | 184 | 316 | 11 | 121 | 184 | 316 | ||||||||||||||||||||||||||||||||||||||||
decommissioning subtotal (c) | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments (d) | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | — | — | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||
Mutual funds (e) | 16 | — | — | — | — | 16 | 46 | — | — | 46 | ||||||||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 16 | — | — | 16 | 47 | — | — | 47 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 1,667 | 3,465 | 1,681 | 6,813 | 1,667 | 3,465 | 1,681 | 6,813 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 201 | 284 | 27 | 512 | 201 | 284 | 27 | 512 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | (1,982 | ) | (2,757 | ) | (557 | ) | (5,296 | ) | (1,982 | ) | (2,757 | ) | (557 | ) | (5,296 | ) | ||||||||||||||||||||||||||||||||
Commodity derivative assets subtotal | (114 | ) | 992 | 1,151 | 2,029 | (114 | ) | 992 | 1,151 | 2,029 | ||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | ||||||||||||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | 8 | — | 8 | — | 31 | — | 31 | ||||||||||||||||||||||||||||||||||||||||
Economic hedges | — | 12 | — | 12 | — | 13 | — | 13 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 18 | 9 | — | 27 | 18 | 9 | — | 27 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (17 | ) | (12 | ) | — | (29 | ) | (17 | ) | (31 | ) | — | (48 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 1 | 17 | — | 18 | 1 | 22 | — | 23 | ||||||||||||||||||||||||||||||||||||||||
assets subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Other investments | — | — | 3 | 3 | 2 | — | 3 | 5 | ||||||||||||||||||||||||||||||||||||||||
Total assets | 4,558 | 6,742 | 2,029 | 13,329 | 5,305 | 6,747 | 2,029 | 14,081 | ||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (2,241 | ) | (3,458 | ) | (788 | ) | (6,487 | ) | (2,241 | ) | (3,458 | ) | (995 | ) | (6,694 | ) | ||||||||||||||||||||||||||||||||
Proprietary trading | (195 | ) | (295 | ) | (42 | ) | (532 | ) | (195 | ) | (295 | ) | (42 | ) | (532 | ) | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | 2,416 | 3,557 | 729 | 6,702 | 2,416 | 3,557 | 729 | 6,702 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities subtotal | (20 | ) | (196 | ) | (101 | ) | (317 | ) | (20 | ) | (196 | ) | (308 | ) | (524 | ) | ||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Derivatives designated as hedging instruments | — | (12 | ) | — | (12 | ) | — | (41 | ) | — | (41 | ) | ||||||||||||||||||||||||||||||||||||
Economic hedges | — | (2 | ) | — | (2 | ) | — | (103 | ) | — | (103 | ) | ||||||||||||||||||||||||||||||||||||
Proprietary trading | (14 | ) | (9 | ) | — | (23 | ) | (14 | ) | (9 | ) | — | (23 | ) | ||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 25 | 10 | — | 35 | 25 | 29 | — | 54 | ||||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 11 | (13 | ) | — | (2 | ) | 11 | (124 | ) | — | (113 | ) | ||||||||||||||||||||||||||||||||||||
liabilities subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (31 | ) | — | (31 | ) | — | (107 | ) | — | (107 | ) | ||||||||||||||||||||||||||||||||||||
Total liabilities | (9 | ) | (240 | ) | (101 | ) | (350 | ) | (9 | ) | (427 | ) | (308 | ) | (744 | ) | ||||||||||||||||||||||||||||||||
Total net assets | $ | 4,549 | $ | 6,502 | $ | 1,928 | $ | 12,979 | $ | 5,296 | $ | 6,320 | $ | 1,721 | $ | 13,337 | ||||||||||||||||||||||||||||||||
Assets and liabilities measured and recorded at fair value on recurring basis | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, 2013 | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents (a) | $ | 1,006 | $ | — | $ | — | $ | 1,006 | $ | 1,230 | $ | — | $ | — | $ | 1,230 | ||||||||||||||||||||||||||||||||
Nuclear decommissioning trust fund investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | 459 | — | — | 459 | 459 | — | — | 459 | ||||||||||||||||||||||||||||||||||||||||
Equities | ||||||||||||||||||||||||||||||||||||||||||||||||
Domestic | 1,642 | 2,271 | — | 3,913 | 1,642 | 2,271 | — | 3,913 | ||||||||||||||||||||||||||||||||||||||||
Foreign | 249 | — | — | 249 | 249 | — | — | 249 | ||||||||||||||||||||||||||||||||||||||||
Equity funds subtotal | 1,891 | 2,271 | — | 4,162 | 1,891 | 2,271 | — | 4,162 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
Corporate debt securities | — | 1,753 | 31 | 1,784 | — | 1,753 | 31 | 1,784 | ||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 882 | — | — | 882 | 882 | — | — | 882 | ||||||||||||||||||||||||||||||||||||||||
Foreign governments | — | 87 | — | 87 | — | 87 | — | 87 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 294 | — | 294 | — | 294 | — | 294 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 75 | — | 75 | — | 75 | — | 75 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 882 | 2,209 | 31 | 3,122 | 882 | 2,209 | 31 | 3,122 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 314 | 314 | — | — | 314 | 314 | ||||||||||||||||||||||||||||||||||||||||
Private equity | — | — | 5 | 5 | — | — | 5 | 5 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 14 | — | 14 | — | 14 | — | 14 | ||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds subtotal (b) | 3,232 | 4,494 | 350 | 8,076 | 3,232 | 4,494 | 350 | 8,076 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | ||||||||||||||||||||||||||||||||||||||||||||||||
decommissioning | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | 26 | — | 26 | — | 26 | — | 26 | ||||||||||||||||||||||||||||||||||||||||
Equities | 16 | — | — | 16 | 16 | — | — | 16 | ||||||||||||||||||||||||||||||||||||||||
Fixed income | ||||||||||||||||||||||||||||||||||||||||||||||||
U.S. Treasury and agencies | 45 | 4 | — | 49 | 45 | 4 | — | 49 | ||||||||||||||||||||||||||||||||||||||||
Corporate debt | — | 227 | — | 227 | — | 227 | — | 227 | ||||||||||||||||||||||||||||||||||||||||
State and municipal debt | — | 20 | — | 20 | — | 20 | — | 20 | ||||||||||||||||||||||||||||||||||||||||
Fixed income subtotal | 45 | 251 | — | 296 | 45 | 251 | — | 296 | ||||||||||||||||||||||||||||||||||||||||
Middle market lending | — | — | 112 | 112 | — | — | 112 | 112 | ||||||||||||||||||||||||||||||||||||||||
Other | — | 1 | — | 1 | — | 1 | — | 1 | ||||||||||||||||||||||||||||||||||||||||
Pledged assets for Zion Station | 61 | 278 | 112 | 451 | 61 | 278 | 112 | 451 | ||||||||||||||||||||||||||||||||||||||||
decommissioning subtotal (c) | ||||||||||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments (d) | ||||||||||||||||||||||||||||||||||||||||||||||||
Cash equivalents | — | — | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||
Mutual funds (e) | 13 | — | — | 13 | 54 | — | — | 54 | ||||||||||||||||||||||||||||||||||||||||
Rabbi trust investments subtotal | 13 | — | — | 13 | 56 | — | — | 56 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative assets | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | 493 | 2,582 | 885 | 3,960 | 493 | 2,582 | 885 | 3,960 | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading | 324 | 1,315 | 122 | 1,761 | 324 | 1,315 | 122 | 1,761 | ||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | (863 | ) | (3,131 | ) | (430 | ) | (4,424 | ) | (863 | ) | (3,131 | ) | (430 | ) | (4,424 | ) | ||||||||||||||||||||||||||||||||
Commodity derivative assets subtotal | (46 | ) | 766 | 577 | 1,297 | (46 | ) | 766 | 577 | 1,297 | ||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | 30 | 32 | — | 62 | 30 | 39 | — | 69 | ||||||||||||||||||||||||||||||||||||||||
assets | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | (30 | ) | (2 | ) | — | (32 | ) | (30 | ) | (2 | ) | — | (32 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | 30 | — | 30 | — | 37 | — | 37 | ||||||||||||||||||||||||||||||||||||||||
assets subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Other investments | — | — | 15 | 15 | — | — | 15 | 15 | ||||||||||||||||||||||||||||||||||||||||
Total assets | 4,266 | 5,568 | 1,054 | 10,888 | 4,533 | 5,575 | 1,054 | 11,162 | ||||||||||||||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Economic hedges | (540 | ) | (1,890 | ) | (397 | ) | (2,827 | ) | (540 | ) | (1,890 | ) | (590 | ) | (3,020 | ) | ||||||||||||||||||||||||||||||||
Proprietary trading | (328 | ) | (1,256 | ) | (119 | ) | (1,703 | ) | (328 | ) | (1,256 | ) | (119 | ) | (1,703 | ) | ||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral (f) | 869 | 3,007 | 404 | 4,280 | 869 | 3,007 | 404 | 4,280 | ||||||||||||||||||||||||||||||||||||||||
Commodity derivative liabilities subtotal | 1 | (139 | ) | (112 | ) | (250 | ) | 1 | (139 | ) | (305 | ) | (443 | ) | ||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | (31 | ) | (13 | ) | — | (44 | ) | (31 | ) | (17 | ) | — | (48 | ) | ||||||||||||||||||||||||||||||||||
liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of netting and allocation of collateral | 31 | 1 | — | 32 | 31 | 1 | — | 32 | ||||||||||||||||||||||||||||||||||||||||
Interest rate and foreign currency derivative | — | (12 | ) | — | (12 | ) | — | (16 | ) | — | (16 | ) | ||||||||||||||||||||||||||||||||||||
liabilities subtotal | ||||||||||||||||||||||||||||||||||||||||||||||||
Deferred compensation obligation | — | (29 | ) | — | (29 | ) | — | (114 | ) | — | (114 | ) | ||||||||||||||||||||||||||||||||||||
Total liabilities | 1 | (180 | ) | (112 | ) | (291 | ) | 1 | (269 | ) | (305 | ) | (573 | ) | ||||||||||||||||||||||||||||||||||
Total net assets | $ | 4,267 | $ | 5,388 | $ | 942 | $ | 10,597 | $ | 4,534 | $ | 5,306 | $ | 749 | $ | 10,589 | ||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | Excludes net liabilities of $5 million at both December 31, 2014 and 2013. 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 $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation. | |||||||||||||||||||||||||||||||||||||||||||||||
(e) | The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013. | |||||||||||||||||||||||||||||||||||||||||||||||
(f) | Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014. Collateral posted (received) to/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. | |||||||||||||||||||||||||||||||||||||||||||||||
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
Operating | Purchased | Other, net (a) | Operating | Purchased | Other, net (a) | |||||||||||||||||||||||||||||||||||||||||||
Revenues | Power and | Revenues | Power and | |||||||||||||||||||||||||||||||||||||||||||||
Fuel | Fuel | |||||||||||||||||||||||||||||||||||||||||||||||
Total gains (losses) included in net income for the year ended December 31, 2013 | $ | (158 | ) | $ | 107 | $ | 2 | $ | (152 | ) | $ | 108 | $ | 2 | ||||||||||||||||||||||||||||||||||
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2013 | $ | 30 | $ | 126 | $ | 1 | $ | 40 | $ | 127 | $ | 1 | ||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. | |||||||||||||||||||||||||||||||||||||||||||||||
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, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||||||||||
Operating | Purchased | Other, net (a) | Operating | Purchased | Other, net (a) | |||||||||||||||||||||||||||||||||||||||||||
Revenues | Power and | Revenues | Power and | |||||||||||||||||||||||||||||||||||||||||||||
Fuel | Fuel | |||||||||||||||||||||||||||||||||||||||||||||||
Total gains (losses) included in net income for the year ended December 31, 2014 | $ | 614 | $ | (88 | ) | $ | 6 | $ | 614 | $ | (88 | ) | $ | 6 | ||||||||||||||||||||||||||||||||||
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014 | $ | 663 | $ | (23 | ) | $ | 4 | $ | 663 | $ | (23 | ) | $ | 4 | ||||||||||||||||||||||||||||||||||
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2014 and 2013: | ||||||||||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||||||||||
For The Year Ended December 31, 2014 | Nuclear | Pledged Assets | Mark-to-Market | Other | Total Generation | Other- ComEd (b) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||||||||||||||||||
Decommissioning | for Zion Station | Derivatives | Investments | |||||||||||||||||||||||||||||||||||||||||||||
Trust Fund | Decommissioning | |||||||||||||||||||||||||||||||||||||||||||||||
Investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | $ | (193 | ) | $ | — | $ | 749 | |||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | ||||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | 6 | — | 526 | (a) | — | 532 | — | — | 532 | |||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 14 | — | — | — | 14 | — | (14 | ) | — | |||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | 2 | — | — | 2 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets/liabilities | — | — | — | — | — | (14 | ) | 14 | — | |||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | 198 | — | 198 | — | — | 198 | ||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 400 | 120 | 76 | (c) | 2 | 598 | — | — | 598 | |||||||||||||||||||||||||||||||||||||||
Sales | (15 | ) | (50 | ) | (7 | ) | (8 | ) | (80 | ) | — | — | (80 | ) | ||||||||||||||||||||||||||||||||||
Settlements | (64 | ) | — | — | — | (64 | ) | — | — | (64 | ) | |||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | (7 | ) | — | (7 | ) | — | — | (7 | ) | |||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (201 | ) | (6 | ) | (207 | ) | — | — | (207 | ) | ||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2014 | $ | 691 | $ | 184 | $ | 1,050 | $ | 3 | $ | 1,928 | $ | (207 | ) | $ | — | $ | 1,721 | |||||||||||||||||||||||||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2014 | $ | 4 | $ | — | $ | 640 | $ | — | $ | 644 | $ | — | $ | — | $ | 644 | ||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||||||||||
For The Year Ended December 31, 2013 | Nuclear | Pledged Assets | Mark-to-Market | Other | Total Generation | Other- ComEd (b)(f) | Eliminated in Consolidation | Total | ||||||||||||||||||||||||||||||||||||||||
Decommissioning | for Zion Station | Derivatives (d) | Investments | |||||||||||||||||||||||||||||||||||||||||||||
Trust Fund | Decommissioning | |||||||||||||||||||||||||||||||||||||||||||||||
Investments | ||||||||||||||||||||||||||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 183 | $ | 89 | $ | 660 | $ | 17 | $ | 949 | $ | (293 | ) | $ | — | $ | 656 | |||||||||||||||||||||||||||||||
Total realized / unrealized gains (losses) | — | |||||||||||||||||||||||||||||||||||||||||||||||
Included in net income | 2 | — | (51 | ) | (a) | — | (49 | ) | — | 7 | (42 | ) | ||||||||||||||||||||||||||||||||||||
Included in other | — | — | (219 | ) | 2 | (217 | ) | — | 219 | 2 | ||||||||||||||||||||||||||||||||||||||
comprehensive income | ||||||||||||||||||||||||||||||||||||||||||||||||
Included in noncurrent payables to affiliates | 8 | — | — | — | 8 | — | (8 | ) | — | |||||||||||||||||||||||||||||||||||||||
Included in payable for Zion Station decommissioning | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
Included in regulatory assets/liabilities | — | — | — | — | — | 100 | (218 | ) | (118 | ) | ||||||||||||||||||||||||||||||||||||||
Change in collateral | — | — | 7 | — | 7 | — | — | 7 | ||||||||||||||||||||||||||||||||||||||||
Purchases, sales, issuances and settlements | ||||||||||||||||||||||||||||||||||||||||||||||||
Purchases | 203 | 62 | 28 | 4 | 297 | — | — | 297 | ||||||||||||||||||||||||||||||||||||||||
Sales | (28 | ) | (39 | ) | (11 | ) | (8 | ) | (86 | ) | — | — | (86 | ) | ||||||||||||||||||||||||||||||||||
Settlements | (18 | ) | — | — | — | (18 | ) | — | — | (18 | ) | |||||||||||||||||||||||||||||||||||||
Transfers into Level 3 | — | — | 86 | (e) | 1 | 87 | — | — | 87 | |||||||||||||||||||||||||||||||||||||||
Transfers out of Level 3 | — | — | (35 | ) | (1 | ) | (36 | ) | — | — | (36 | ) | ||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2013 | $ | 350 | $ | 112 | $ | 465 | $ | 15 | $ | 942 | $ | (193 | ) | $ | — | $ | 749 | |||||||||||||||||||||||||||||||
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2013 | $ | 1 | $ | — | $ | 156 | $ | — | $ | 157 | $ | — | $ | — | $ | 168 | ||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | Includes $11 million of decreases in fair value and realized gains 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(e) | Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | |||||||||||||||||||||||||||||||||||||||||||||||
(f) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique | The table below discloses the significant inputs to the forward curve used to value these positions. | |||||||||||||||||||||||||||||||||||||||||||||||
Type of trade | Fair Value at December 31,2014 | Valuation | Unobservable | Range | ||||||||||||||||||||||||||||||||||||||||||||
Technique | Input | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Economic hedges (Generation) (a)(c) | $ | 893 | Discounted | Forward power price | $15 | - | $120 | (d) | ||||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Forward gas price | $1.52 | - | $14.02 | (d) | ||||||||||||||||||||||||||||||||||||||||||||
Option Model | Volatility percentage | 8% | - | 257% | ||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Proprietary trading (Generation) (a)(c) | $ | (15 | ) | Discounted | Forward power price | $15 | - | $117 | (d) | |||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives | $ | (207 | ) | Discounted | Forward heat rate (b) | 8x | - | 9x | ||||||||||||||||||||||||||||||||||||||||
(ComEd) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Marketability reserve | 3.50% | - | 8% | |||||||||||||||||||||||||||||||||||||||||||||
Renewable factor | 86% | - | 126% | |||||||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | The fair values do not include cash collateral held on level three positions of $172 million as of December 31, 2014. | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | 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 $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading. | |||||||||||||||||||||||||||||||||||||||||||||||
Type of trade | Fair Value at December 31, 2013 | Valuation | Unobservable | Range | ||||||||||||||||||||||||||||||||||||||||||||
Technique | Input | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives—Economic hedges (Generation) (a)(c) | $ | 488 | Discounted | Forward power price | $8 | - | $176 | (d) | ||||||||||||||||||||||||||||||||||||||||
Cash Flow | ||||||||||||||||||||||||||||||||||||||||||||||||
Forward gas price | $2.98 | - | $16.63 | (d) | ||||||||||||||||||||||||||||||||||||||||||||
Option Model | Volatility percentage | 15% | - | 142% | ||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives— | $ | 3 | Discounted | Forward power price | $10 | - | $176 | (d) | ||||||||||||||||||||||||||||||||||||||||
Proprietary trading (Generation) (a)(c) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivatives | $ | (193 | ) | Discounted | Forward heat rate (b) | 8x | - | 9x | ||||||||||||||||||||||||||||||||||||||||
(ComEd) | Cash Flow | |||||||||||||||||||||||||||||||||||||||||||||||
Marketability reserve | 3.50% | - | 8% | |||||||||||||||||||||||||||||||||||||||||||||
Renewable factor | 84% | - | 128% | |||||||||||||||||||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||||||||||||||
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||||||||||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||||||||||
(c) | The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 | |||||||||||||||||||||||||||||||||||||||||||||||
(d) | 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. |
Derivative_Financial_Instrumen1
Derivative Financial Instruments (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||
Summary of the derivative fair value | The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014: | |||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||
Derivatives | Economic | Proprietary | Collateral | Subtotal (b) | Economic | Total | ||||||||||||||||||||||||||||||||||
Hedges | Trading | and Netting (a) | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||||||
Mark-to-market | $ | 4,992 | $ | 456 | $ | (4,184 | ) | $ | 1,264 | $ | — | $ | 1,264 | |||||||||||||||||||||||||||
derivative assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | 1,821 | 56 | (1,112 | ) | 765 | — | 765 | |||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 6,813 | 512 | (5,296 | ) | 2,029 | — | 2,029 | |||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (4,947 | ) | (468 | ) | 5,200 | (215 | ) | (20 | ) | (235 | ) | |||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (1,540 | ) | (64 | ) | 1,502 | (102 | ) | (187 | ) | (289 | ) | |||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (6,487 | ) | (532 | ) | 6,702 | (317 | ) | (207 | ) | (524 | ) | |||||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 326 | $ | (20 | ) | $ | 1,406 | $ | 1,712 | $ | (207 | ) | $ | 1,505 | ||||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(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 $(416) million and $(171) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(599) million and $(220) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014. | |||||||||||||||||||||||||||||||||||||||
(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, 2013: | ||||||||||||||||||||||||||||||||||||||||
Generation | ComEd | Exelon | ||||||||||||||||||||||||||||||||||||||
Derivatives | Economic | Proprietary | Collateral | Subtotal (b) | Economic | Total | ||||||||||||||||||||||||||||||||||
Hedges | Trading | and | Hedges (c) | Derivatives | ||||||||||||||||||||||||||||||||||||
Netting (a) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | $ | 2,616 | $ | 1,476 | $ | (3,364 | ) | $ | 728 | $ | — | $ | 728 | |||||||||||||||||||||||||||
derivative assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | 1,344 | 285 | (1,060 | ) | 569 | — | 569 | |||||||||||||||||||||||||||||||||
derivative assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 3,960 | 1,761 | (4,424 | ) | 1,297 | — | 1,297 | |||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (2,023 | ) | (1,410 | ) | 3,292 | (141 | ) | (17 | ) | (158 | ) | |||||||||||||||||||||||||||||
derivative liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market | (804 | ) | (293 | ) | 988 | (109 | ) | (176 | ) | (285 | ) | |||||||||||||||||||||||||||||
derivative liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (2,827 | ) | (1,703 | ) | 4,280 | (250 | ) | (193 | ) | (443 | ) | |||||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 1,133 | $ | 58 | $ | (144 | ) | $ | 1,047 | $ | (193 | ) | $ | 854 | ||||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(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. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. 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. | |||||||||||||||||||||||||||||||||||||||
Below is a summary of the interest rate and foreign exchange hedges as of December 31, 2014: | ||||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||||
Description | Derivatives | Economic | Proprietary | Collateral | Subtotal | Derivatives | Economic | Collateral | Subtotal | Total | ||||||||||||||||||||||||||||||
Designated as | Hedges | Trading (a) | and Netting (b) | Designated as | Hedges | and Netting (b) | ||||||||||||||||||||||||||||||||||
Hedging | Hedging | |||||||||||||||||||||||||||||||||||||||
Instruments | Instruments | |||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | $ | 7 | $ | 7 | $ | 20 | $ | (22 | ) | $ | 12 | $ | 3 | $ | — | $ | — | $ | 3 | $ | 15 | |||||||||||||||||||
assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | 1 | 5 | 7 | (7 | ) | 6 | 20 | 1 | (19 | ) | 2 | 8 | ||||||||||||||||||||||||||||
assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 8 | 12 | 27 | (29 | ) | 18 | 23 | 1 | (19 | ) | 5 | 23 | ||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (8 | ) | (2 | ) | (14 | ) | 25 | 1 | — | — | — | — | 1 | |||||||||||||||||||||||||||
liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (4 | ) | — | (9 | ) | 10 | (3 | ) | (29 | ) | (101 | ) | 19 | (111 | ) | (114 | ) | |||||||||||||||||||||||
liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (12 | ) | (2 | ) | (23 | ) | 35 | (2 | ) | (29 | ) | (101 | ) | 19 | (111 | ) | (113 | ) | ||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | (4 | ) | $ | 10 | $ | 4 | $ | 6 | $ | 16 | $ | (6 | ) | $ | (100 | ) | $ | — | $ | (106 | ) | $ | (90 | ) | |||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||||||||||||||||
(b) | 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 and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013: | ||||||||||||||||||||||||||||||||||||||||
Generation | Other | Exelon | ||||||||||||||||||||||||||||||||||||||
Description | Derivatives | Economic | Proprietary | Collateral | Subtotal | Derivatives | Total | |||||||||||||||||||||||||||||||||
Designated as | Hedges | Trading (a) | and Netting (b) | Designated as | ||||||||||||||||||||||||||||||||||||
Hedging | Hedging | |||||||||||||||||||||||||||||||||||||||
Instruments | Instruments | |||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | $ | — | $ | 3 | $ | 15 | $ | (19 | ) | $ | (1 | ) | $ | — | $ | (1 | ) | |||||||||||||||||||||||
assets (current assets) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | 26 | 3 | 15 | (13 | ) | 31 | 7 | 38 | ||||||||||||||||||||||||||||||||
assets (noncurrent assets) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | 26 | 6 | 30 | (32 | ) | 30 | 7 | 37 | ||||||||||||||||||||||||||||||||
derivative assets | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (1 | ) | (1 | ) | (18 | ) | 19 | (1 | ) | — | (1 | ) | ||||||||||||||||||||||||||||
liabilities (current liabilities) | ||||||||||||||||||||||||||||||||||||||||
Mark-to-market derivative | (10 | ) | (1 | ) | (13 | ) | 13 | (11 | ) | (4 | ) | (15 | ) | |||||||||||||||||||||||||||
liabilities (noncurrent liabilities) | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | (11 | ) | (2 | ) | (31 | ) | 32 | (12 | ) | (4 | ) | (16 | ) | |||||||||||||||||||||||||||
derivative liabilities | ||||||||||||||||||||||||||||||||||||||||
Total mark-to-market | $ | 15 | $ | 4 | $ | (1 | ) | $ | — | $ | 18 | $ | 3 | $ | 21 | |||||||||||||||||||||||||
derivative net assets (liabilities) | ||||||||||||||||||||||||||||||||||||||||
_________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||||||||||||||||||
(b) | Represents the netting of fair value balances with the same counterparty and any associated cash collateral. | |||||||||||||||||||||||||||||||||||||||
Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense | 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: | |||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||
Income Statement Location | 2014 | 2013 | 2012 | 2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Gain (Loss) on Swaps | Gain (Loss) on Borrowings | |||||||||||||||||||||||||||||||||||||||
Generation | Interest expense (a) | $ | (16 | ) | $ | (15 | ) | $ | (6 | ) | $ | 2 | $ | (6 | ) | $ | — | |||||||||||||||||||||||
Exelon | Interest expense | $ | 3 | $ | (24 | ) | $ | (9 | ) | $ | 15 | $ | (3 | ) | $ | (1 | ) | |||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively. | |||||||||||||||||||||||||||||||||||||||
The activity of accumulated OCI related to cash flow hedges | The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2014 and 2013, 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. | |||||||||||||||||||||||||||||||||||||||
Income Statement | Total Cash Flow Hedge OCI Activity, | |||||||||||||||||||||||||||||||||||||||
Location | Net of Income Tax | |||||||||||||||||||||||||||||||||||||||
Generation | Exelon | |||||||||||||||||||||||||||||||||||||||
Energy-Related | Total Cash Flow | |||||||||||||||||||||||||||||||||||||||
Hedges | Hedges | |||||||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at January 1, 2013 | $ | 532 | (a)(d) | $ | 368 | |||||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | — | 29 | (e) | |||||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net | Operating Revenues | (413 | ) | (c)(b) | (277 | ) | ||||||||||||||||||||||||||||||||||
income | ||||||||||||||||||||||||||||||||||||||||
Ineffective portion recognized in income | Operating Revenues | — | — | |||||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2013 | 119 | (d) | 120 | |||||||||||||||||||||||||||||||||||||
Effective portion of changes in fair value | — | (31 | ) | (e) | ||||||||||||||||||||||||||||||||||||
Reclassifications from accumulated OCI to net income | Operating Revenues | (117 | ) | (b) | (117 | ) | ||||||||||||||||||||||||||||||||||
Accumulated OCI derivative gain at December 31, 2014 | $ | 2 | (d) | $ | (28 | ) | ||||||||||||||||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Includes $133 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. | |||||||||||||||||||||||||||||||||||||||
(b) | Amount is net of related income tax expense of $78 million and $270 million for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
(c) | Includes $133 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 year ended December 31, 2013. | |||||||||||||||||||||||||||||||||||||||
(d) | Excludes $20 million and $5 million,of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
(e) | Includes $15 million and $15 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 years ended December 31, 2014 and 2013, respectively. | |||||||||||||||||||||||||||||||||||||||
Change in fair value and reclassification of derivative contracts | 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 | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2014 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | (413 | ) | $ | (194 | ) | $ | — | $ | (607 | ) | $ | — | $ | — | $ | (607 | ) | ||||||||||||||||||||||
Reclassification to realized at settlement of | 231 | (223 | ) | — | 8 | — | — | 8 | ||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains (losses) | (182 | ) | (417 | ) | — | (599 | ) | — | — | (599 | ) | |||||||||||||||||||||||||||||
Change in fair value of treasury positions | 10 | — | (2 | ) | 8 | — | (100 | ) | (92 | ) | ||||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (2 | ) | — | — | (2 | ) | — | — | (2 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | 8 | — | (2 | ) | 6 | — | (100 | ) | (94 | ) | ||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | (174 | ) | $ | (417 | ) | $ | (2 | ) | $ | (593 | ) | $ | — | $ | (100 | ) | $ | (693 | ) | ||||||||||||||||||||
Generation | Intercompany | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2013 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | 286 | $ | 180 | $ | — | $ | 466 | $ | (6 | ) | $ | — | $ | 460 | |||||||||||||||||||||||||
Reclassification to realized at settlement of | (64 | ) | 104 | — | 40 | 13 | — | 53 | ||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains | 222 | 284 | — | 506 | 7 | — | 513 | |||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | (1 | ) | — | (4 | ) | (5 | ) | — | — | (5 | ) | |||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (1 | ) | — | — | (1 | ) | — | — | (1 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | (2 | ) | — | (4 | ) | (6 | ) | — | — | (6 | ) | |||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | 220 | $ | 284 | $ | (4 | ) | $ | 500 | $ | 7 | $ | — | $ | 507 | |||||||||||||||||||||||||
Generation | Intercompany | Exelon Corporate | Exelon | |||||||||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2012 | Operating | Purchased | Interest Expense | Total | Operating | Interest Expense | Total | |||||||||||||||||||||||||||||||||
Revenues | Power | Revenues (a) | ||||||||||||||||||||||||||||||||||||||
and Fuel | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | $ | (362 | ) | $ | 215 | $ | — | $ | (147 | ) | $ | (94 | ) | $ | — | $ | (241 | ) | ||||||||||||||||||||||
Reclassification to realized at settlement of | 432 | 238 | — | 670 | 101 | — | 771 | |||||||||||||||||||||||||||||||||
commodity positions | ||||||||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains | 70 | 453 | — | 523 | 7 | — | 530 | |||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | — | — | 6 | 6 | — | — | 6 | |||||||||||||||||||||||||||||||||
Reclassification to realized at settlement of | (3 | ) | — | — | (3 | ) | — | — | (3 | ) | ||||||||||||||||||||||||||||||
treasury positions | ||||||||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains | (3 | ) | — | 6 | 3 | — | — | 3 | ||||||||||||||||||||||||||||||||
(losses) | ||||||||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | $ | 67 | $ | 453 | $ | 6 | $ | 526 | $ | 7 | $ | — | $ | 533 | ||||||||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Prior to the Constellation merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation. | |||||||||||||||||||||||||||||||||||||||
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. | ||||||||||||||||||||||||||||||||||||||||
Location on Income | For the Years Ended | |||||||||||||||||||||||||||||||||||||||
Statement | December 31, | |||||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||||||
Change in fair value of commodity positions | Operating Revenues | $ | (1 | ) | $ | (22 | ) | $ | (13 | ) | ||||||||||||||||||||||||||||||
Reclassification to realized at settlement of commodity positions | Operating Revenues | (29 | ) | (15 | ) | 108 | ||||||||||||||||||||||||||||||||||
Net commodity mark-to-market gains (losses) | Operating Revenues | (30 | ) | (37 | ) | 95 | ||||||||||||||||||||||||||||||||||
Change in fair value of treasury positions | Operating Revenues | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||||
Reclassification to realized at settlement of treasury positions | Operating Revenues | 3 | (3 | ) | — | |||||||||||||||||||||||||||||||||||
Net treasury mark-to market gains (losses) | Operating Revenues | 4 | (2 | ) | 1 | |||||||||||||||||||||||||||||||||||
Net mark-to market gains (losses) | Operating Revenues | $ | (26 | ) | $ | (39 | ) | $ | 96 | |||||||||||||||||||||||||||||||
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 | The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and 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 exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively. | |||||||||||||||||||||||||||||||||||||||
Rating as of December 31, 2014 | Total | Credit | Net | Number of | Net Exposure of | |||||||||||||||||||||||||||||||||||
Exposure | Collateral (a) | Exposure | Counterparties | Counterparties | ||||||||||||||||||||||||||||||||||||
Before Credit | Greater than 10% | Greater than 10% | ||||||||||||||||||||||||||||||||||||||
Collateral | of Net Exposure | of Net Exposure | ||||||||||||||||||||||||||||||||||||||
Investment grade | $ | 1,629 | $ | 62 | $ | 1,567 | 1 | $ | 452 | |||||||||||||||||||||||||||||||
Non-investment grade | 49 | 19 | 30 | — | — | |||||||||||||||||||||||||||||||||||
No external ratings | ||||||||||||||||||||||||||||||||||||||||
Internally rated—investment grade | 479 | — | 479 | — | — | |||||||||||||||||||||||||||||||||||
Internally rated—non-investment | 60 | 4 | 56 | — | — | |||||||||||||||||||||||||||||||||||
grade | ||||||||||||||||||||||||||||||||||||||||
Total | $ | 2,217 | $ | 85 | $ | 2,132 | 1 | $ | 452 | |||||||||||||||||||||||||||||||
Net Credit Exposure by Type of Counterparty | 31-Dec-14 | |||||||||||||||||||||||||||||||||||||||
Financial institutions | $ | 295 | ||||||||||||||||||||||||||||||||||||||
Investor-owned utilities, marketers, power producers | 958 | |||||||||||||||||||||||||||||||||||||||
Energy cooperatives and municipalities | 862 | |||||||||||||||||||||||||||||||||||||||
Other | 17 | |||||||||||||||||||||||||||||||||||||||
Total | $ | 2,132 | ||||||||||||||||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 million of letters of credit. | |||||||||||||||||||||||||||||||||||||||
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 | 2014 | 2013 | ||||||||||||||||||||||||||||||||||||||
Gross Fair Value of Derivative Contracts Containing this Feature (a) | $ | (1,433 | ) | $ | (1,056 | ) | ||||||||||||||||||||||||||||||||||
Offsetting Fair Value of In-the-Money Contracts Under Master Netting | 1,140 | 846 | ||||||||||||||||||||||||||||||||||||||
Arrangements (b) | ||||||||||||||||||||||||||||||||||||||||
Net Fair Value of Derivative Contracts Containing This Feature (c) | $ | (293 | ) | $ | (210 | ) | ||||||||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||||||
(a) | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. | |||||||||||||||||||||||||||||||||||||||
(b) | 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. | |||||||||||||||||||||||||||||||||||||||
(c) | 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_Tab
Debt and Credit Agreements (Tables) | 12 Months Ended | |||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||
Debt Disclosure [Abstract] | ||||||||||||||||||||||
Schedule of Short-term Debt | The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2014, 2013 and 2012. PECO did not have any short-term borrowings during 2014, 2013 or 2012. | |||||||||||||||||||||
Exelon | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 571 | $ | 254 | $ | 199 | ||||||||||||||||
Maximum borrowings outstanding | 1,164 | 682 | 505 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.37 | % | 0.48 | % | ||||||||||||||||
Average interest rates, at December 31 | 0.53 | % | 0.35 | % | n.a. | |||||||||||||||||
Generation | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 93 | $ | 42 | $ | 4 | ||||||||||||||||
Maximum borrowings outstanding | 552 | 291 | 165 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.32 | % | 0.32 | % | 0.45 | % | ||||||||||||||||
Average interest rates, at December 31 | n.a. | n.a. | n.a. | |||||||||||||||||||
ComEd | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 415 | $ | 203 | $ | 110 | ||||||||||||||||
Maximum borrowings outstanding | 597 | 446 | 366 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.33 | % | 0.4 | % | 0.5 | % | ||||||||||||||||
Average interest rates, at December 31 | 0.5 | % | 0.37 | % | n.a. | |||||||||||||||||
BGE | ||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||
Average borrowings | $ | 64 | $ | 35 | $ | 6 | ||||||||||||||||
Maximum borrowings outstanding | 180 | 135 | 76 | |||||||||||||||||||
Average interest rates, computed on a daily basis | 0.29 | % | 0.31 | % | 0.43 | % | ||||||||||||||||
Average interest rates, computed at December 31 | 0.61 | % | 0.31 | % | n.a. | |||||||||||||||||
Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2014 and 2013: | ||||||||||||||||||||||
Maximum | Outstanding | Average Interest Rate on | ||||||||||||||||||||
Program Size at | Commercial | Commercial Paper Borrowings for | ||||||||||||||||||||
December 31, | Paper at | the Year Ended December 31, | ||||||||||||||||||||
December 31, | ||||||||||||||||||||||
Commercial Paper Issuer | 2014 (a)(b) | 2013 (a)(b) | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
Exelon Corporate | $ | 500 | $ | 500 | $ | — | $ | — | — | % | 0.27 | % | ||||||||||
Generation | 5,600 | 5,600 | — | — | 0.32 | % | 0.32 | % | ||||||||||||||
ComEd | 1,000 | 1,000 | 304 | 184 | 0.33 | % | 0.4 | % | ||||||||||||||
PECO | 600 | 600 | — | — | n.a. | n.a. | ||||||||||||||||
BGE | 600 | 600 | 120 | 135 | 0.29 | % | 0.31 | % | ||||||||||||||
Total | $ | 8,300 | $ | 8,300 | $ | 424 | $ | 319 | ||||||||||||||
_____________________ | ||||||||||||||||||||||
(a) | Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||||||
(b) | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||||||||||||||||||
Schedule of Line of Credit Facilities | At December 31, 2014, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements: | |||||||||||||||||||||
Available Capacity at December 31, 2014 | ||||||||||||||||||||||
Borrower | Aggregate Bank | Facility Draws | Outstanding | Actual | To Support | |||||||||||||||||
Commitment (a) | Letters of Credit(c) | Additional | ||||||||||||||||||||
Commercial | ||||||||||||||||||||||
Paper (b) | ||||||||||||||||||||||
Exelon Corporate | $ | 500 | $ | — | $ | 6 | $ | 494 | $ | 494 | ||||||||||||
Generation | 5,800 | — | 1,181 | 4,619 | 4,504 | |||||||||||||||||
ComEd | 1,000 | — | 2 | 998 | 694 | |||||||||||||||||
PECO | 600 | — | 1 | 599 | 599 | |||||||||||||||||
BGE | 600 | — | — | 600 | 480 | |||||||||||||||||
Total | $ | 8,500 | $ | — | $ | 1,190 | $ | 7,310 | $ | 6,771 | ||||||||||||
_______________________ | ||||||||||||||||||||||
(a) | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||||||||||||||||||
(b) | Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program. | |||||||||||||||||||||
(c) | Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind. | |||||||||||||||||||||
Schedule Of Credit Agreement Covenants | The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2014: | |||||||||||||||||||||
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, 2014, the interest coverage ratios at the Registrants were as follows: | ||||||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||||
Interest coverage ratio | 9.19 | 12.35 | 7.03 | 8.72 | 9.28 | |||||||||||||||||
Schedule of Long-term Debt Instruments | The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2014 and 2013: | |||||||||||||||||||||
Exelon | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Rate stabilization bonds | 5.72 | % | - | 5.82 | % | 2017 | $ | 195 | $ | 265 | ||||||||||||
First mortgage bonds (a)(b) | 1.2 | % | - | 6.45 | % | 2015 - 2044 | 8,079 | 7,746 | ||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2015 - 2042 | 7,071 | 7,571 | ||||||||||||||
Unsecured bonds | 2.8 | % | - | 6.35 | % | 2016 - 2036 | 1,750 | 1,750 | ||||||||||||||
Pollution control note | 4.1 | % | 2014 | — | 20 | |||||||||||||||||
Nuclear fuel procurement contracts | 3.25 | % | - | 3.35 | % | 2018 | 70 | — | ||||||||||||||
Junior subordinated notes | 6.5 | % | 2017 | 1,150 | — | |||||||||||||||||
Nonrecourse debt: | ||||||||||||||||||||||
Fixed rates | 2.33 | % | - | 6 | % | 2031 - 2037 | 1,166 | 1,077 | ||||||||||||||
Variable rates | 2.41 | % | - | 5 | % | 2019 - 2030 | 1,101 | 150 | ||||||||||||||
Notes payable and other (c) | 6.95 | % | - | 7.83 | % | 2015 - 2053 | 174 | 181 | ||||||||||||||
Total long-term debt | 20,756 | 18,760 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (37 | ) | (19 | ) | ||||||||||||||||||
Fair value adjustment | 441 | 384 | ||||||||||||||||||||
Fair value hedge carrying value adjustment, | 4 | 7 | ||||||||||||||||||||
net | ||||||||||||||||||||||
Long-term debt due within one year | (1,802 | ) | (1,509 | ) | ||||||||||||||||||
Long-term debt | $ | 19,362 | $ | 17,623 | ||||||||||||||||||
Long-term debt to financing trusts (d) | ||||||||||||||||||||||
Subordinated debentures to ComEd Financing | 6.35 | % | 2033 | $ | 206 | $ | 206 | |||||||||||||||
III | ||||||||||||||||||||||
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 $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | |||||||||||||||||||||
(d) | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. | |||||||||||||||||||||
ComEd | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
First mortgage bonds (a)(b) | 1.95 | % | - | 6.45 | % | 2015 - 2044 | $ | 5,829 | $ | 5,546 | ||||||||||||
Notes payable and other (c) | 6.95 | % | - | 7.49 | % | 2015 - 2053 | 148 | 148 | ||||||||||||||
Total long-term debt | 5,977 | 5,694 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (19 | ) | (19 | ) | ||||||||||||||||||
Long-term debt due within one year | (260 | ) | (617 | ) | ||||||||||||||||||
Long-term debt | $ | 5,698 | $ | 5,058 | ||||||||||||||||||
Long-term debt to financing trust (d) | ||||||||||||||||||||||
Subordinated debentures to ComEd Financing III | 6.35 | % | 2033 | $ | 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 both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053. | |||||||||||||||||||||
(d) | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. | |||||||||||||||||||||
BGE | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Rate stabilization bonds | 5.72 | % | - | 5.82 | % | 2017 | 195 | $ | 265 | |||||||||||||
Notes | 2.8 | % | - | 6.35 | % | 2016 - 2036 | $ | 1,750 | $ | 1,750 | ||||||||||||
Total long-term debt | 1,945 | 2,015 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (3 | ) | (4 | ) | ||||||||||||||||||
Long-term debt due within one year | (75 | ) | (70 | ) | ||||||||||||||||||
Long-term debt | $ | 1,867 | $ | 1,941 | ||||||||||||||||||
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 Long-term debt to financing trust within BGE’s Consolidated Balance Sheets. | |||||||||||||||||||||
Generation | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
Senior unsecured notes | 2 | % | - | 7.6 | % | 2015 - 2042 | $ | 5,771 | $ | 6,271 | ||||||||||||
Social Security Administration | 2.93 | % | 2015 | — | 1 | |||||||||||||||||
Pollution control notes | 4.1 | % | 2014 | — | 20 | |||||||||||||||||
Nuclear fuel procurement contracts | 3.25 | % | - | 3.35 | % | 2018 | 70 | — | ||||||||||||||
Nonrecourse debt: | ||||||||||||||||||||||
Fixed rates | 2.33 | % | - | 6 | % | 2031 - 2037 | 1,166 | 1,077 | ||||||||||||||
Variable rates | 2.41 | % | - | 5 | % | 2019 - 2030 | 1,101 | 150 | ||||||||||||||
Notes payable and other (a) | 7.83 | % | 2014 - 2020 | 26 | 33 | |||||||||||||||||
Total long-term debt | 8,134 | 7,552 | ||||||||||||||||||||
Fair value adjustment | 146 | 166 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (14 | ) | 11 | |||||||||||||||||||
Long-term debt due within one year | (614 | ) | (561 | ) | ||||||||||||||||||
Long-term debt | $ | 7,652 | $ | 7,168 | ||||||||||||||||||
______________________ | ||||||||||||||||||||||
(a) | Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | |||||||||||||||||||||
PECO | ||||||||||||||||||||||
Maturity | December 31, | |||||||||||||||||||||
Rates | Date | 2014 | 2013 | |||||||||||||||||||
Long-term debt | ||||||||||||||||||||||
First mortgage bonds (a)(b) | 1.2 | % | - | 5.95 | % | 2016 - 2044 | $ | 2,250 | $ | 2,200 | ||||||||||||
Total long-term debt | 2,250 | 2,200 | ||||||||||||||||||||
Unamortized debt discount and premium, net | (4 | ) | (3 | ) | ||||||||||||||||||
Long-term debt due within one year | — | (250 | ) | |||||||||||||||||||
Long-term debt | $ | 2,246 | $ | 1,947 | ||||||||||||||||||
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 Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. | |||||||||||||||||||||
Schedule of Maturities of Long-term Debt | Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2014 through 2019 and thereafter are as follows: | |||||||||||||||||||||
Year | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||||
2015 | $ | 1,739 | $ | 604 | $ | 260 | $ | — | $ | 75 | ||||||||||||
2016 | 1,269 | 4 | 665 | 300 | 300 | |||||||||||||||||
2017 | 2,400 | 705 | 425 | — | 120 | |||||||||||||||||
2018 | 1,415 | 75 | 840 | 500 | — | |||||||||||||||||
2019 | 982 | 682 | 300 | — | — | |||||||||||||||||
Thereafter | 13,599 | (a) | 6,064 | 3,693 | (b) | 1,634 | (c) | 1,708 | (d) | |||||||||||||
Total | $ | 21,404 | $ | 8,134 | $ | 6,183 | $ | 2,434 | $ | 2,203 | ||||||||||||
____________________ | ||||||||||||||||||||||
(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. |
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets. | |||||||||||||||||||
Net interest receivable (payable) as of | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
December 31, 2014 | $ | (310 | ) | $ | 40 | $ | (203 | ) | $ | 3 | $ | (1 | ) | |||||||
December 31, 2013 | (349 | ) | (37 | ) | (174 | ) | 3 | — | ||||||||||||
Income tax expense (benefit) from continuing operations is comprised of the following components: | ||||||||||||||||||||
For the Year Ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Included in operations: | ||||||||||||||||||||
Federal | ||||||||||||||||||||
Current | $ | 121 | $ | 360 | $ | (171 | ) | $ | 28 | $ | 24 | |||||||||
Deferred | 576 | (35 | ) | 395 | 87 | 90 | ||||||||||||||
Investment tax credit amortization | (20 | ) | (16 | ) | (2 | ) | — | (1 | ) | |||||||||||
State | ||||||||||||||||||||
Current | 42 | 35 | 7 | (2 | ) | — | ||||||||||||||
Deferred | (53 | ) | (137 | ) | 39 | 1 | 27 | |||||||||||||
Total | $ | 666 | $ | 207 | $ | 268 | $ | 114 | $ | 140 | ||||||||||
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 | ||||||||||
Interest Income and Interest Expense Disclosure [Table Text Block] | The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions. | |||||||||||||||||||
Net interest expense (income) for the years ended | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
December 31, 2014 | $ | (36 | ) | $ | (50 | ) | $ | 6 | $ | — | $ | 1 | ||||||||
December 31, 2013 | 391 | 17 | 281 | (1 | ) | — | ||||||||||||||
December 31, 2012 | (1 | ) | 11 | (20 | ) | (1 | ) | 9 | ||||||||||||
Effective Income Tax Rate Reconciliation | 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, 2014 | 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 | 1.3 | (1.9 | ) | 4.5 | (0.1 | ) | 5 | |||||||||||||
Qualified nuclear decommissioning trust fund income | 2.4 | 4.8 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.5 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | (2.0 | ) | (4.1 | ) | — | — | — | |||||||||||||
Health care reform legislation | 0.1 | — | 0.2 | — | 0.2 | |||||||||||||||
Amortization of investment tax credit, net deferred | (1.1 | ) | (2.0 | ) | (0.3 | ) | (0.1 | ) | (0.3 | ) | ||||||||||
taxes | ||||||||||||||||||||
Plant basis differences | (1.9 | ) | — | (0.1 | ) | (10.4 | ) | 0.2 | ||||||||||||
Production tax credits and other credits | (2.4 | ) | (4.8 | ) | — | — | — | |||||||||||||
Non-controlling interest | (1.8 | ) | (3.7 | ) | — | — | — | |||||||||||||
Statute of limitations expiration | (2.6 | ) | (5.3 | ) | — | — | — | |||||||||||||
Other | — | (0.6 | ) | 0.3 | 0.1 | (0.2 | ) | |||||||||||||
Effective income tax rate | 26.8 | % | 16.9 | % | 39.6 | % | 24.5 | % | 39.9 | % | ||||||||||
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 | 4.8 | 1.8 | 3.4 | 1.6 | 4.9 | |||||||||||||||
Qualified nuclear decommissioning trust fund income | 3.7 | 6.1 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.3 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | — | — | — | — | — | |||||||||||||||
Health care reform legislation | 0.1 | — | 0.7 | — | 0.2 | |||||||||||||||
Amortization of investment tax credit, net deferred | (1.9 | ) | (3.0 | ) | (0.6 | ) | (0.1 | ) | — | |||||||||||
taxes | ||||||||||||||||||||
Plant basis differences | (1.6 | ) | — | (0.8 | ) | (7.1 | ) | (0.2 | ) | |||||||||||
Production tax credits and other credits | (2.1 | ) | (3.4 | ) | (0.1 | ) | — | — | ||||||||||||
Statute of limitations expiration | (0.1 | ) | (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 | (3.5 | ) | 4.9 | 4.6 | 2 | 24.3 | ||||||||||||||
Qualified nuclear decommissioning trust fund income | 5.4 | 9.1 | — | — | — | |||||||||||||||
Tax exempt income | (0.2 | ) | (0.4 | ) | — | — | — | |||||||||||||
Domestic production activities deduction | — | — | — | — | — | |||||||||||||||
Health care reform legislation | 0.1 | — | 0.4 | — | 11.6 | |||||||||||||||
Amortization of investment tax credit | (1.1 | ) | (1.3 | ) | (0.4 | ) | (0.3 | ) | (8.6 | ) | ||||||||||
Plant basis differences | (2.4 | ) | — | (0.3 | ) | (11.5 | ) | (9.0 | ) | |||||||||||
Production tax credits and other credits | (2.2 | ) | (3.7 | ) | — | — | — | |||||||||||||
Fines and Penalties | 2.6 | 4.4 | — | — | — | |||||||||||||||
Merger expenses (c) | 2.4 | — | — | — | 24.2 | |||||||||||||||
Statute of limitations expiration | (0.1 | ) | (0.3 | ) | — | — | — | |||||||||||||
Other | (1.1 | ) | (0.4 | ) | (0.6 | ) | (0.2 | ) | (13.9 | ) | ||||||||||
Effective income tax rate | 34.9 | % | 47.3 | % | 38.7 | % | 25 | % | 63.6 | % | ||||||||||
_____________________ | ||||||||||||||||||||
(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. | |||||||||||||||||||
(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. | |||||||||||||||||||
Tax Effects of Temporary Differences | The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2014 and 2013 are presented below: | |||||||||||||||||||
For the Year Ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | |||||||||||||||
Plant basis differences | $ | (12,143 | ) | $ | (3,834 | ) | $ | (3,945 | ) | $ | (2,749 | ) | $ | (1,661 | ) | |||||
Accrual based contracts | (178 | ) | (178 | ) | — | — | — | |||||||||||||
Derivatives and other financial instruments | (46 | ) | (79 | ) | (4 | ) | — | — | ||||||||||||
Deferred pension and postretirement obligation | 1,914 | (390 | ) | (543 | ) | 2 | (53 | ) | ||||||||||||
Nuclear decommissioning activities | (726 | ) | (726 | ) | — | — | — | |||||||||||||
Deferred debt refinancing costs | 112 | 57 | (18 | ) | (2 | ) | (4 | ) | ||||||||||||
Regulatory assets and liabilities | (1,824 | ) | — | (286 | ) | 27 | (258 | ) | ||||||||||||
Tax loss carryforward | 111 | 48 | — | 11 | 39 | |||||||||||||||
Tax credit carryforward | 97 | 143 | — | — | — | |||||||||||||||
Investment in CENG | (563 | ) | (563 | ) | — | — | — | |||||||||||||
Other, net | 1,029 | 346 | 255 | 111 | 30 | |||||||||||||||
Deferred income tax liabilities (net) | $ | (12,217 | ) | $ | (5,176 | ) | $ | (4,541 | ) | $ | (2,600 | ) | $ | (1,907 | ) | |||||
Unamortized investment tax credits | (555 | ) | (528 | ) | (20 | ) | (2 | ) | (5 | ) | ||||||||||
Total deferred income tax liabilities (net) and | $ | (12,772 | ) | $ | (5,704 | ) | $ | (4,561 | ) | $ | (2,602 | ) | $ | (1,912 | ) | |||||
unamortized investment tax credits | ||||||||||||||||||||
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 postretirement obligation | 1,489 | (362 | ) | (522 | ) | — | (74 | ) | ||||||||||||
Nuclear decommissioning activities | (647 | ) | (646 | ) | — | — | — | |||||||||||||
Deferred debt refinancing costs | 173 | 79 | (21 | ) | (3 | ) | (5 | ) | ||||||||||||
Regulatory assets and liabilities | (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 | $ | (12,372 | ) | $ | (5,845 | ) | $ | (4,132 | ) | $ | (2,404 | ) | $ | (1,798 | ) | |||||
unamortized investment tax credits | ||||||||||||||||||||
Summary of Loss Carryforwards | The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2014. | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Federal | ||||||||||||||||||||
Federal general business credits carryforward | 184 | (a) | 184 | — | — | — | ||||||||||||||
State | ||||||||||||||||||||
State net operating losses and other credit carryforwards | 3,141 | 1,693 | — | 170 | 730 | (e) | ||||||||||||||
Deferred taxes on state tax attributes (net) | 169 | 96 | — | 11 | 39 | |||||||||||||||
Valuation allowance on state tax attributes | 50 | 48 | — | — | 1 | |||||||||||||||
_____________________ | ||||||||||||||||||||
(a) | Exelon’s federal general business credit carryforwards will expire beginning in 2032. | |||||||||||||||||||
(b) | Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015 | |||||||||||||||||||
(c) | Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015. | |||||||||||||||||||
(d) | PECO’s state net operating losses will expire beginning in 2031. | |||||||||||||||||||
(e) | BGE’s state net operating losses will expire beginning in 2026 | |||||||||||||||||||
Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Foll Forward | The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2014, 2013 and 2012: | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Unrecognized tax benefits at January 1, 2014 | $ | 2,175 | $ | 1,415 | $ | 324 | $ | 44 | $ | — | ||||||||||
Increases based on tax positions related to 2014 | 15 | 15 | — | — | — | |||||||||||||||
Change to positions that only affect timing | (255 | ) | 33 | (175 | ) | — | — | |||||||||||||
Increases based on tax positions prior to 2014 | 18 | 18 | — | — | — | |||||||||||||||
Decreases based on tax positions prior to 2014 | (1 | ) | (2 | ) | — | — | — | |||||||||||||
Decrease from settlements with taxing authorities | (35 | ) | (34 | ) | — | — | — | |||||||||||||
Decreases from expiration of statute of limitations | (88 | ) | (88 | ) | — | — | — | |||||||||||||
Unrecognized tax benefits at December 31, 2014 | $ | 1,829 | $ | 1,357 | $ | 149 | $ | 44 | $ | — | ||||||||||
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 | $ | — | ||||||||||
Summary of Open Tax Years by Jurisdiction | 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, 2001-2013 | |||||||||||||||||||
Constellation and subsidiaries consolidated Federal income tax returns | 2011-March 2012 | |||||||||||||||||||
Exelon and subsidiaries Illinois unitary income tax returns | 2007-2013 | |||||||||||||||||||
Constellation combined New York corporate income tax returns | 2008-2013 | |||||||||||||||||||
Various separate company Pennsylvania corporate net income tax returns | 2010-2013 | |||||||||||||||||||
BGE Maryland corporate net income tax returns | 2011-2013 | |||||||||||||||||||
Various Exelon Maryland corporate net income tax returns | 2012-2013 | |||||||||||||||||||
Various Constellation (Non-BGE) Maryland corporate net income tax returns | 2011-2013 | |||||||||||||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||
Nuclear Decommissioning Asset Retirement Obligation Rollforward | The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2013 to December 31, 2014: | |||||||||||||||||||
Exelon and | ||||||||||||||||||||
Generation | ||||||||||||||||||||
Nuclear decommissioning ARO at January 1, 2013 | $ | 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 | |||||||||||||||||||
Consolidation of CENG (b) | 1,760 | |||||||||||||||||||
Accretion expense | 334 | |||||||||||||||||||
Net increase due to changes in, and timing of, estimated future cash flows | 19 | |||||||||||||||||||
Costs incurred to decommission retired plants | (7 | ) | ||||||||||||||||||
Nuclear decommissioning ARO at December 31, 2014 (a) | $ | 6,961 | ||||||||||||||||||
_________________________ | ||||||||||||||||||||
(a) | Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. | |||||||||||||||||||
(b) | Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||||||||||||||||
Unrealized Gains Losses On Nuclear Decommissioning Trust Funds | The following table provides unrealized gains on NDT funds for 2014, 2013 and 2012: | |||||||||||||||||||
Exelon and Generation | ||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||
Net unrealized gains on decommissioning trust | $ | 180 | $ | 406 | $ | 386 | ||||||||||||||
funds—Regulatory Agreement Units (a) | ||||||||||||||||||||
Net unrealized gains on decommissioning trust | 134 | 146 | 105 | |||||||||||||||||
funds—Non-Regulatory Agreement Units (b)(c) | ||||||||||||||||||||
_______________________ | ||||||||||||||||||||
(a) | Net unrealized gains 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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, 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 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. | |||||||||||||||||||
Nuclear Decommissioning Pledged Assets | The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2014 and 2013: | |||||||||||||||||||
Exelon and Generation | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Carrying value of Zion Station pledged assets | $ | 319 | $ | 458 | ||||||||||||||||
Payable to Zion Solutions (a) | 292 | 414 | ||||||||||||||||||
Current portion of payable to Zion Solutions (b) | 137 | 109 | ||||||||||||||||||
Cumulative withdrawals by Zion Solutions to pay decommissioning costs | 666 | 498 | ||||||||||||||||||
___________________ | ||||||||||||||||||||
(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. | |||||||||||||||||||
Non Nuclear Decommissioning Asset Retirement Obligation Rollforward | The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2013 to December 31, 2014: | |||||||||||||||||||
Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Non-nuclear AROs at January 1, 2013 | $ | 343 | $ | 207 | $ | 99 | $ | 29 | $ | 8 | ||||||||||
Net increase (decrease) due to changes in, and | 1 | (11 | ) | — | — | 12 | ||||||||||||||
timing of, estimated future cash flows (a) | ||||||||||||||||||||
Development projects (b) | 2 | 2 | — | — | — | |||||||||||||||
Accretion expense (c) | 18 | 13 | 4 | 1 | — | |||||||||||||||
Payments | (13 | ) | (10 | ) | (2 | ) | — | (1 | ) | |||||||||||
Non-nuclear AROs at December 31, 2013 (d) | 351 | 201 | 101 | 30 | 19 | |||||||||||||||
Net increase (decrease) due to changes in, and | (1 | ) | (2 | ) | 2 | — | (1 | ) | ||||||||||||
timing of, estimated future cash flows (a) | ||||||||||||||||||||
Development projects (b) | 11 | 11 | — | — | — | |||||||||||||||
Accretion expense (c) | 15 | 11 | 3 | 1 | — | |||||||||||||||
Liabilities held for sale (e) | (4 | ) | (4 | ) | — | — | — | |||||||||||||
Sale of generating assets (f) | (20 | ) | (20 | ) | — | — | — | |||||||||||||
Payments | (6 | ) | (3 | ) | (2 | ) | (1 | ) | — | |||||||||||
Non-nuclear AROs at December 31, 2014 (d) | $ | 346 | $ | 194 | $ | 104 | $ | 30 | $ | 18 | ||||||||||
________________________ | ||||||||||||||||||||
(a) | During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013. | |||||||||||||||||||
(b) | Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites. | |||||||||||||||||||
(c) | 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. | |||||||||||||||||||
(d) | During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets. | |||||||||||||||||||
(e) | Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information. | |||||||||||||||||||
(f) | Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. |
Retirement_Benefits_Tables
Retirement Benefits (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Compensation and Retirement Disclosure [Abstract] | ||||||||||||||||||||||||
Schedule Of Pension And Other Postretirement Participation | ||||||||||||||||||||||||
Operating Company | ||||||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||||||
Qualified Pension Plans: | ||||||||||||||||||||||||
Exelon Corporation Retirement Program(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Cash Balance Pension Plan(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Pension Plan for Bargaining | X | X | X | |||||||||||||||||||||
Unit Employees(a) | ||||||||||||||||||||||||
Exelon New England Union Employees Pension | X | |||||||||||||||||||||||
Plan(a) | ||||||||||||||||||||||||
Exelon Employee Pension Plan for Clinton, TMI | X | X | X | |||||||||||||||||||||
and Oyster Creek(a) | ||||||||||||||||||||||||
Pension Plan of Constellation Energy Group, Inc.(b) | X | X | X | X | X | |||||||||||||||||||
Pension Plan of Constellation Energy Nuclear | X | X | X | |||||||||||||||||||||
Group, LLC(c) | ||||||||||||||||||||||||
Nine Mile Point Pension Plan(c) | X | X | ||||||||||||||||||||||
Constellation Mystic Power, LLC Union Employees | X | |||||||||||||||||||||||
Pension Plan Including Plan A and Plan B(b) | ||||||||||||||||||||||||
Non-Qualified Pension Plans: | ||||||||||||||||||||||||
Exelon Corporation Supplemental Pension Benefit | X | X | X | X | ||||||||||||||||||||
Plan and 2000 Excess Benefit Plan(a) | ||||||||||||||||||||||||
Exelon Corporation Supplemental Management | X | X | X | X | X | |||||||||||||||||||
Retirement Plan(a) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Senior Executive | X | X | X | |||||||||||||||||||||
Supplemental Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Supplemental | X | X | X | |||||||||||||||||||||
Pension Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Benefits | X | X | X | |||||||||||||||||||||
Restoration Plan(b) | ||||||||||||||||||||||||
Constellation Nuclear Plan, LLC Executive | X | X | ||||||||||||||||||||||
Retirement Plan(c) | ||||||||||||||||||||||||
Constellation Energy Nuclear Plan, LLC Benefits | X | X | ||||||||||||||||||||||
Restoration Plan(c) | ||||||||||||||||||||||||
Baltimore Gas & Electric Company Executive | X | X | X | |||||||||||||||||||||
Benefit Plan(b) | ||||||||||||||||||||||||
Baltimore Gas & Electric Company Manager | X | X | X | |||||||||||||||||||||
Benefit Plan(b) | ||||||||||||||||||||||||
Operating Company | ||||||||||||||||||||||||
Name of Plan: | Generation | ComEd | PECO | BGE | BSC | |||||||||||||||||||
Other Postretirement Benefit Plans: | ||||||||||||||||||||||||
PECO Energy Company Retiree Medical Plan(a) | X | X | X | X | X | |||||||||||||||||||
Exelon Corporation Health Care Program(a) | X | X | X | X | ||||||||||||||||||||
Exelon Corporation Employees’ Life Insurance | X | X | X | X | X | |||||||||||||||||||
Plan(a) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Retiree Medical | X | X | X | X | X | |||||||||||||||||||
Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Retiree Dental | X | X | X | |||||||||||||||||||||
Plan(b) | ||||||||||||||||||||||||
Constellation Energy Group, Inc. Employee Life | X | X | X | X | X | |||||||||||||||||||
Insurance Plan and Family Life Insurance Plan(b) | ||||||||||||||||||||||||
Constellation Mystic Power, LLC | X | |||||||||||||||||||||||
Post-Employment Medical Account Savings Plan(b) | ||||||||||||||||||||||||
Exelon New England Union Post-Employment | X | |||||||||||||||||||||||
Medical Savings Account Plan(a) | ||||||||||||||||||||||||
Retiree Medical Plan of Constellation Energy | X | X | X | |||||||||||||||||||||
Nuclear Group LLC(c) | ||||||||||||||||||||||||
Retiree Dental Plan of Constellation Energy | X | X | X | |||||||||||||||||||||
Nuclear Group LLC(c) | ||||||||||||||||||||||||
Nine Mile Point Nuclear Station, LLC Medical Care | X | X | ||||||||||||||||||||||
and Prescription Drug Plan for Retired | ||||||||||||||||||||||||
Employees(c) | ||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | These plans are collectively referred to as the Legacy Exelon plans. | |||||||||||||||||||||||
(b) | These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans. | |||||||||||||||||||||||
(c) | These plans are collectively referred to as the Legacy CENG plans. | |||||||||||||||||||||||
Defined Benefit Plan Change In Benefit Obligation RollForward | 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: | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Change in benefit obligation: | ||||||||||||||||||||||||
Net benefit obligation at beginning of year | $ | 15,459 | $ | 16,800 | $ | 4,451 | $ | 4,820 | ||||||||||||||||
Service cost | 293 | 317 | 117 | 162 | ||||||||||||||||||||
Interest cost | 749 | 650 | 186 | 194 | ||||||||||||||||||||
Plan participants’ contributions | — | — | 42 | 34 | ||||||||||||||||||||
Actuarial loss (gain) | 2,095 | (1,363 | ) | 502 | (551 | ) | ||||||||||||||||||
Plan amendments | — | 1 | (1,012 | ) | 15 | |||||||||||||||||||
Acquisitions/divestitures(a) | 594 | — | 142 | — | ||||||||||||||||||||
Curtailments | (8 | ) | — | — | — | |||||||||||||||||||
Settlements | (30 | ) | (69 | ) | — | — | ||||||||||||||||||
Gross benefits paid | (896 | ) | (877 | ) | (231 | ) | (223 | ) | ||||||||||||||||
Net benefit obligation at end of year | $ | 18,256 | $ | 15,459 | $ | 4,197 | $ | 4,451 | ||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Change in plan assets: | ||||||||||||||||||||||||
Fair value of net plan assets at beginning of year | $ | 13,571 | $ | 13,357 | $ | 2,238 | $ | 2,135 | ||||||||||||||||
Actual return on plan assets | 1,443 | 821 | 90 | 209 | ||||||||||||||||||||
Employer contributions | 332 | 339 | 291 | 83 | ||||||||||||||||||||
Plan participants’ contributions | — | — | 42 | 34 | ||||||||||||||||||||
Benefits paid | (896 | ) | (877 | ) | (231 | ) | (223 | ) | ||||||||||||||||
Acquisitions/divestitures(a) | 454 | — | — | — | ||||||||||||||||||||
Settlements | (30 | ) | (69 | ) | — | — | ||||||||||||||||||
Fair value of net plan assets at end of year | $ | 14,874 | $ | 13,571 | $ | 2,430 | $ | 2,238 | ||||||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information. | |||||||||||||||||||||||
Schedule of Amounts Recognized in Balance Sheet | Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items: | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Other current liabilities | $ | 16 | $ | 12 | $ | 25 | $ | 23 | ||||||||||||||||
Pension obligations | 3,366 | 1,876 | — | — | ||||||||||||||||||||
Non-pension postretirement benefit obligations | — | — | 1,742 | 2,190 | ||||||||||||||||||||
Unfunded status (net benefit obligation less net plan | $ | 3,382 | $ | 1,888 | $ | 1,767 | $ | 2,213 | ||||||||||||||||
assets) | ||||||||||||||||||||||||
Defined Benefit Plan Pension Plans With Projected Benefit Obligations And Accumulated Benefit Obligations In Excess Of 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 | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Projected benefit obligation | $ | 18,256 | $ | 15,452 | ||||||||||||||||||||
Fair value of net plan assets | 14,874 | 13,564 | ||||||||||||||||||||||
ABO in | ||||||||||||||||||||||||
excess of plan assets | ||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||
Projected benefit obligation | $ | 18,256 | $ | 15,452 | ||||||||||||||||||||
Accumulated benefit obligation | 17,191 | 14,552 | ||||||||||||||||||||||
Fair value of net plan assets | 14,874 | 13,564 | ||||||||||||||||||||||
Schedule of Defined Benefit Plans Disclosures | A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Components of net periodic | ||||||||||||||||||||||||
benefit cost: | ||||||||||||||||||||||||
Service cost | $ | 293 | $ | 317 | $ | 280 | $ | 117 | $ | 162 | $ | 156 | ||||||||||||
Interest cost | 749 | 650 | 698 | 186 | 194 | 205 | ||||||||||||||||||
Expected return on assets | (994 | ) | (1,015 | ) | (988 | ) | (154 | ) | (132 | ) | (115 | ) | ||||||||||||
Amortization of: | ||||||||||||||||||||||||
Transition obligation | — | — | — | — | — | 11 | ||||||||||||||||||
Prior service cost (credit) | 14 | 14 | 15 | (122 | ) | (19 | ) | (17 | ) | |||||||||||||||
Actuarial loss | 420 | 562 | 450 | 50 | 83 | 81 | ||||||||||||||||||
Curtailment benefits | — | — | — | — | — | (7 | ) | |||||||||||||||||
Settlement charges | 2 | 9 | 31 | — | — | — | ||||||||||||||||||
Contractual termination benefits (a) | — | — | 14 | — | — | 6 | ||||||||||||||||||
Net periodic benefit cost | $ | 484 | $ | 537 | $ | 500 | $ | 77 | $ | 288 | $ | 320 | ||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012. | |||||||||||||||||||||||
Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets | The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2014, 2013 and 2012 for all plans combined. | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Changes in plan assets and benefit | ||||||||||||||||||||||||
obligations recognized in AOCI and regulatory assets (liabilities): | ||||||||||||||||||||||||
Current year actuarial (gain) loss | $ | 1,639 | $ | (1,169 | ) | $ | 1,693 | $ | 561 | $ | (628 | ) | $ | 304 | ||||||||||
Amortization of actuarial loss | (420 | ) | (562 | ) | (450 | ) | (50 | ) | (83 | ) | (81 | ) | ||||||||||||
Current year prior service (credit) cost | — | — | 1 | (1,012 | ) | 15 | (109 | ) | ||||||||||||||||
Amortization of prior service (cost) | (14 | ) | (14 | ) | (15 | ) | 122 | 19 | 17 | |||||||||||||||
credit | ||||||||||||||||||||||||
Current year transition (asset) | — | — | — | — | — | 1 | ||||||||||||||||||
obligation | ||||||||||||||||||||||||
Amortization of transition asset | — | — | — | — | — | (11 | ) | |||||||||||||||||
(obligation) | ||||||||||||||||||||||||
Curtailments | — | — | (10 | ) | — | — | (1 | ) | ||||||||||||||||
Settlements | (2 | ) | (8 | ) | (31 | ) | — | — | — | |||||||||||||||
Total recognized in AOCI and | $ | 1,203 | $ | (1,753 | ) | $ | 1,188 | $ | (379 | ) | $ | (677 | ) | $ | 120 | |||||||||
regulatory assets (liabilities) (a) | ||||||||||||||||||||||||
______________________ | ||||||||||||||||||||||||
(a) | Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. 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. | |||||||||||||||||||||||
Changes In Plan Assets And Benefit Obligations Not Recognized In OCI And Regulatory Assets | 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, 2014 and 2013, respectively, for all plans combined: | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||
Prior service cost (credit) | $ | 49 | $ | 62 | $ | (963 | ) | $ | (73 | ) | ||||||||||||||
Actuarial loss | 7,407 | 6,192 | 985 | 474 | ||||||||||||||||||||
Total (a) | $ | 7,456 | $ | 6,254 | $ | 22 | $ | 401 | ||||||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. 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. | |||||||||||||||||||||||
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year | The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefit plans. | |||||||||||||||||||||||
Pension Benefits | Other | |||||||||||||||||||||||
Postretirement Benefits | ||||||||||||||||||||||||
Prior service cost (credit) | $ | 13 | $ | (175 | ) | |||||||||||||||||||
Actuarial loss | 562 | 74 | ||||||||||||||||||||||
Total (a) | $ | 575 | $ | (101 | ) | |||||||||||||||||||
___________________ | ||||||||||||||||||||||||
(a) | Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, respectively. | |||||||||||||||||||||||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation | The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. 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 | |||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Discount rate | 3.94 | % | 4.8 | % | 3.92 | % | 3.92 | % | 4.9 | % | 4 | % | ||||||||||||
Rate of | (a) | (b) | (c) | (a) | (b) | (c) | ||||||||||||||||||
compensation | ||||||||||||||||||||||||
increase | ||||||||||||||||||||||||
Mortality table | RP-2000 table with Scale BB-2D improvements (adjusted) | RP-2000 table with Scale AA | RP-2000 table with Scale AA improvements | RP-2000 table with Scale BB-2D improvements (adjusted) | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | ||||||||||||||||||
improvements | ||||||||||||||||||||||||
Health care cost | N/A | N/A | N/A | 6.00% | 6.00% | 6.50% | ||||||||||||||||||
trend on covered | decreasing | decreasing | decreasing | |||||||||||||||||||||
charges | to | to | to | |||||||||||||||||||||
ultimate | ultimate | ultimate | ||||||||||||||||||||||
trend of | trend of | trend of | ||||||||||||||||||||||
5.00% in | 5.00% in | 5.00% in | ||||||||||||||||||||||
2017 | 2017 | 2017 | ||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||
(a) | 3.25% for 2015-2019 and 3.75% thereafter. | |||||||||||||||||||||||
(b) | 3.25% for 2014-2018 and 3.75% thereafter. | |||||||||||||||||||||||
(c) | 3.25% for 2013-2017 and 3.75% thereafter. | |||||||||||||||||||||||
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost | The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
2014 | 2013 | 2012 | 2014 | 2013 | 2012 | |||||||||||||||||||
Discount rate | 4.8 | % | (a) | 3.92 | % | (b) | 4.74 | % | (c) | 4.9 | % | (a) | 4 | % | (b) | 4.8 | % | (c) | ||||||
Expected return on | 7 | % | (d) | 7.5 | % | (d) | 7.5 | % | (d) | 6.59 | % | (d) | 6.45 | % | (d) | 6.68 | % | (d) | ||||||
plan assets | ||||||||||||||||||||||||
Rate of | (e) | (f) | 3.75 | % | (e) | (f) | 3.75 | % | ||||||||||||||||
compensation | ||||||||||||||||||||||||
increase | ||||||||||||||||||||||||
Mortality table | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | RP-2000 table with Scale AA improvements | ||||||||||||||||||
Health care cost | N/A | N/A | N/A | 6.00% | 6.50% | 6.50% | ||||||||||||||||||
trend on covered | decreasing | decreasing | decreasing | |||||||||||||||||||||
charges | to | to | to | |||||||||||||||||||||
ultimate | ultimate | ultimate | ||||||||||||||||||||||
trend of | trend of | trend of | ||||||||||||||||||||||
5.00% in | 5.00% in | 5.00% in | ||||||||||||||||||||||
2017 | 2017 | 2017 | ||||||||||||||||||||||
___________________________ | ||||||||||||||||||||||||
(a) | The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information. | |||||||||||||||||||||||
(b) | 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 measurements. | |||||||||||||||||||||||
(c) | The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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. | |||||||||||||||||||||||
(d) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. | |||||||||||||||||||||||
(e) | 3.25% for 2014-2018 and 3.75% thereafter. | |||||||||||||||||||||||
(f) | 3.25% for 2013-2017 and 3.75% thereafter. | |||||||||||||||||||||||
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates | 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 2014 total service and interest cost components | $ | 35 | ||||||||||||||||||||||
on postretirement benefit obligation at December 31, 2014 | 162 | |||||||||||||||||||||||
Effect of a one percentage point decrease in assumed health care cost trend: | ||||||||||||||||||||||||
on 2014 total service and interest cost components | (24 | ) | ||||||||||||||||||||||
on postretirement benefit obligation at December 31, 2014 | (113 | ) | ||||||||||||||||||||||
Pension And Other Postretirement Benefit 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 | |||||||||||||||||||||||
2014(c) | 2013 | 2012 | 2014 | 2013 | 2012 (a) | |||||||||||||||||||
Generation | $ | 173 | $ | 119 | $ | 48 | $ | 124 | $ | 30 | $ | 135 | ||||||||||||
ComEd | 122 | 118 | 25 | 125 | 4 | 119 | ||||||||||||||||||
PECO | 11 | 11 | 13 | 5 | 20 | 33 | ||||||||||||||||||
BGE (b) | — | — | — | 17 | 24 | 12 | ||||||||||||||||||
BSC(d) | 26 | 91 | 63 | 20 | 5 | 24 | ||||||||||||||||||
Exelon | $ | 332 | $ | 339 | $ | 149 | $ | 291 | $ | 83 | $ | 323 | ||||||||||||
_________________________ | ||||||||||||||||||||||||
(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. Effective January 1, 2013, Exelon is no longer receiving this subsidy. | |||||||||||||||||||||||
(b) | BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements. | |||||||||||||||||||||||
(c) | Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG. | |||||||||||||||||||||||
(d) | Includes $9 million, $72 million, and $13 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||||||||||||||||||||
Defined Benefit Plan Estimated Future Benefit Payments | ||||||||||||||||||||||||
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2014 were: | ||||||||||||||||||||||||
Pension | Other | |||||||||||||||||||||||
Benefits | Postretirement | |||||||||||||||||||||||
Benefits | ||||||||||||||||||||||||
2015 | $ | 1,064 | $ | 217 | ||||||||||||||||||||
2016 | 962 | 223 | ||||||||||||||||||||||
2017 | 979 | 230 | ||||||||||||||||||||||
2018 | 1,004 | 236 | ||||||||||||||||||||||
2019 | 1,032 | 247 | ||||||||||||||||||||||
2020 through 2024 | 5,825 | 1,373 | ||||||||||||||||||||||
Total estimated future benefit payments through 2024 | $ | 10,866 | $ | 2,526 | ||||||||||||||||||||
Schedule Of Pension And Other Postretirement Benefit 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 | ||||||||||||||||||
2014 | $ | 250 | $ | 162 | $ | 36 | $ | 46 | $ | 67 | 561 | |||||||||||||
2013 | 347 | 309 | 43 | 71 | 55 | 825 | ||||||||||||||||||
2012 | 341 | 282 | 50 | 99 | 60 | 820 | ||||||||||||||||||
_____________________ | ||||||||||||||||||||||||
(a) | 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. | |||||||||||||||||||||||
(b) | The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 2012. | |||||||||||||||||||||||
(c) | 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 | Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2014 and 2013 asset allocations were as follows: | |||||||||||||||||||||||
Pension Plans | ||||||||||||||||||||||||
Percentage of Plan Assets | ||||||||||||||||||||||||
at December 31, | ||||||||||||||||||||||||
Asset Category | Target Allocation | 2014 | 2013 | |||||||||||||||||||||
Equity securities | 32 | % | 33 | % | 35 | % | ||||||||||||||||||
Fixed income securities | 37 | % | 37 | 37 | ||||||||||||||||||||
Alternative investments (a) | 31 | % | 30 | 28 | ||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||
Other Postretirement Benefit Plans | ||||||||||||||||||||||||
Percentage of Plan Assets | ||||||||||||||||||||||||
at December 31, | ||||||||||||||||||||||||
Asset Category | Target Allocation | 2014 | 2013 | |||||||||||||||||||||
Equity securities | 41 | % | 42 | % | 45 | % | ||||||||||||||||||
Fixed income securities | 34 | % | 34 | 37 | ||||||||||||||||||||
Alternative investments (a) | 25 | % | 24 | 18 | ||||||||||||||||||||
Total | 100 | % | 100 | % | ||||||||||||||||||||
___________________ | ||||||||||||||||||||||||
(a) | Alternative investments include private equity, hedge funds and real estate. | |||||||||||||||||||||||
Defined Benefit Plan Fair Value Of Plan Assets | ||||||||||||||||||||||||
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, 2014 and 2013: | ||||||||||||||||||||||||
At December 31, 2014 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Pension plan assets | ||||||||||||||||||||||||
Cash equivalents | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 1,556 | 1,133 | 2 | 2,691 | ||||||||||||||||||||
Foreign | 1,705 | 316 | — | 2,021 | ||||||||||||||||||||
Equities subtotal | 3,261 | 1,449 | 2 | 4,712 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 1,051 | 88 | — | 1,139 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 80 | — | 80 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Corporate debt securities | — | 3,125 | 120 | 3,245 | ||||||||||||||||||||
Other | — | 942 | 152 | 1,094 | ||||||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||||||
Assets | — | 4 | — | 4 | ||||||||||||||||||||
Liabilities | — | (16 | ) | — | (16 | ) | ||||||||||||||||||
Fixed income subtotal | 1,051 | 4,223 | 272 | 5,546 | ||||||||||||||||||||
Private equity | — | — | 904 | 904 | ||||||||||||||||||||
Hedge funds | — | 1,355 | 1,329 | 2,684 | ||||||||||||||||||||
Real estate | 243 | — | 744 | 987 | ||||||||||||||||||||
Pension plan assets subtotal | 4,556 | 7,027 | 3,251 | 14,834 | ||||||||||||||||||||
At December 31, 2014 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||||||
Cash equivalents | 11 | — | — | 11 | ||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 296 | 378 | — | 674 | ||||||||||||||||||||
Foreign | 184 | 147 | — | 331 | ||||||||||||||||||||
Equities subtotal | 480 | 525 | — | 1,005 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 15 | 59 | — | 74 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 197 | — | 197 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Corporate debt securities | — | 42 | — | 42 | ||||||||||||||||||||
Other | 253 | 272 | — | 525 | ||||||||||||||||||||
Fixed income subtotal | 268 | 570 | — | 838 | ||||||||||||||||||||
Hedge funds | — | 339 | 110 | 449 | ||||||||||||||||||||
Real estate | 8 | — | 116 | 124 | ||||||||||||||||||||
Other postretirement benefit plan assets subtotal | 767 | 1,434 | 226 | 2,427 | ||||||||||||||||||||
Total pension and other postretirement benefit plan assets (c) | $ | 5,323 | $ | 8,461 | $ | 3,477 | $ | 17,261 | ||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Pension plan assets | ||||||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | $ | 1,587 | $ | 865 | $ | 2 | $ | 2,454 | ||||||||||||||||
Foreign | 1,773 | 302 | — | 2,075 | ||||||||||||||||||||
Equities subtotal | 3,360 | 1,167 | 2 | 4,529 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 908 | 99 | — | 1,007 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 88 | — | 88 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Foreign debt securities | — | 205 | — | 205 | ||||||||||||||||||||
Corporate debt securities | — | 2,927 | 41 | 2,968 | ||||||||||||||||||||
Other | 5 | 899 | — | 904 | ||||||||||||||||||||
Derivative instruments (b): | ||||||||||||||||||||||||
Assets | — | 7 | — | 7 | ||||||||||||||||||||
Liabilities | — | (134 | ) | — | (134 | ) | ||||||||||||||||||
Fixed income subtotal | 913 | 4,091 | 41 | 5,045 | ||||||||||||||||||||
Private equity | — | — | 806 | 806 | ||||||||||||||||||||
Hedge funds | — | 1,266 | 1,039 | 2,305 | ||||||||||||||||||||
Real estate | 264 | 2 | 582 | 848 | ||||||||||||||||||||
Pension plan assets subtotal | 4,537 | 6,526 | 2,470 | 13,533 | ||||||||||||||||||||
At December 31, 2013 (a) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
Other postretirement benefit plan assets | ||||||||||||||||||||||||
Cash equivalents | 51 | — | — | 51 | ||||||||||||||||||||
Equities: | ||||||||||||||||||||||||
Domestic | 296 | 345 | — | 641 | ||||||||||||||||||||
Foreign | 154 | 170 | — | 324 | ||||||||||||||||||||
Equities subtotal | 450 | 515 | — | 965 | ||||||||||||||||||||
Fixed income: | ||||||||||||||||||||||||
Debt securities issued by the U.S. Treasury | 17 | 46 | — | 63 | ||||||||||||||||||||
and other U.S. government corporations and agencies | ||||||||||||||||||||||||
Debt securities issued by states of the | — | 149 | — | 149 | ||||||||||||||||||||
United States and by political subdivisions of the states | ||||||||||||||||||||||||
Foreign debt securities | — | 2 | — | 2 | ||||||||||||||||||||
Corporate debt securities | — | 50 | — | 50 | ||||||||||||||||||||
Other | 305 | 225 | — | 530 | ||||||||||||||||||||
Fixed income subtotal | 322 | 472 | — | 794 | ||||||||||||||||||||
Private equity | — | — | 2 | 2 | ||||||||||||||||||||
Hedge funds | — | 295 | 4 | 299 | ||||||||||||||||||||
Real estate | 8 | 5 | 109 | 122 | ||||||||||||||||||||
Other postretirement benefit plan assets subtotal | 831 | 1,287 | 115 | 2,233 | ||||||||||||||||||||
Total pension and other postretirement benefit | $ | 5,368 | $ | 7,813 | $ | 2,585 | $ | 15,766 | ||||||||||||||||
plan assets (c) | ||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||
(a) | See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. | |||||||||||||||||||||||
(b) | Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, 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. | |||||||||||||||||||||||
(c) | Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, 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 | 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, 2014 and 2013: | |||||||||||||||||||||||
Hedge | Private | Real | Fixed | Equities | Total | |||||||||||||||||||
funds | equity | estate | income | |||||||||||||||||||||
Pension Assets | ||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 1,039 | $ | 806 | $ | 582 | $ | 41 | $ | 2 | $ | 2,470 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 77 | 112 | 83 | 7 | — | 279 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Relating to assets sold during the | 3 | — | — | — | — | 3 | ||||||||||||||||||
period | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 311 | 173 | 136 | 227 | — | 847 | ||||||||||||||||||
Sales | (38 | ) | — | (19 | ) | (3 | ) | — | (60 | ) | ||||||||||||||
Settlements (a) | (33 | ) | (203 | ) | (65 | ) | — | — | (301 | ) | ||||||||||||||
Transfers into (out of) Level 3 (b)(c) | (30 | ) | 16 | 27 | — | — | 13 | |||||||||||||||||
Balance as of December 31, 2014 | $ | 1,329 | $ | 904 | $ | 744 | $ | 272 | $ | 2 | $ | 3,251 | ||||||||||||
Other Postretirement Benefits | ||||||||||||||||||||||||
Balance as of January 1, 2014 | $ | 4 | $ | 2 | $ | 109 | $ | — | $ | — | $ | 115 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 1 | — | 13 | — | — | 14 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 109 | 1 | 1 | — | — | 111 | ||||||||||||||||||
Sales | (4 | ) | (2 | ) | (7 | ) | — | — | (13 | ) | ||||||||||||||
Settlements (a) | — | (1 | ) | — | — | — | (1 | ) | ||||||||||||||||
Balance as of December 31, 2014 | $ | 110 | $ | — | $ | 116 | $ | — | $ | — | $ | 226 | ||||||||||||
Hedge | Private | Real | Fixed | Equities | Total | |||||||||||||||||||
funds | equity | estate | income | |||||||||||||||||||||
Pension Assets | ||||||||||||||||||||||||
Balance as of January 1, 2013 | $ | 1,235 | $ | 754 | $ | 426 | $ | — | $ | — | $ | 2,415 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 143 | 86 | 63 | — | — | 292 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Relating to assets sold during the | 3 | — | (4 | ) | — | — | (1 | ) | ||||||||||||||||
period | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | 360 | 123 | 226 | 41 | 2 | 752 | ||||||||||||||||||
Sales | (76 | ) | — | (91 | ) | — | — | (167 | ) | |||||||||||||||
Settlements (a) | (3 | ) | (157 | ) | (38 | ) | — | — | (198 | ) | ||||||||||||||
Transfers into (out of) Level 3 (c) | (623 | ) | — | — | — | — | (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 | $ | — | $ | — | $ | 108 | ||||||||||||
Actual return on plan assets: | ||||||||||||||||||||||||
Relating to assets still held at the | 1 | — | 11 | — | — | 12 | ||||||||||||||||||
reporting date | ||||||||||||||||||||||||
Purchases, sales and settlements: | ||||||||||||||||||||||||
Purchases | — | 1 | 3 | — | — | 4 | ||||||||||||||||||
Sales | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Settlements (a) | (4 | ) | — | — | — | — | (4 | ) | ||||||||||||||||
Transfers into (out of) Level 3 (c) | (4 | ) | — | — | — | — | (4 | ) | ||||||||||||||||
Balance as of December 31, 2013 | $ | 4 | $ | 2 | $ | 109 | $ | — | $ | — | $ | 115 | ||||||||||||
________________________ | ||||||||||||||||||||||||
(a) | Represents cash settlements only. | |||||||||||||||||||||||
(b) | In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million. | |||||||||||||||||||||||
(c) | As of January 1, 2014 and January 1, 2013, 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, 2014 and 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 $43 million and $627 million in 2014 and 2013 respectively. | |||||||||||||||||||||||
Schedule Of Defined Contributions | . The following table presents matching contributions to the savings plan for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation | ComEd | PECO | BGE (a) | BSC (b) | ||||||||||||||||||
2014 | $ | 103 | $ | 51 | $ | 26 | $ | 8 | $ | 8 | $ | 10 | ||||||||||||
2013 | 85 | 40 | 22 | 8 | 8 | 7 | ||||||||||||||||||
2012 | 67 | 30 | 19 | 7 | 7 | 5 | ||||||||||||||||||
_________________________ | ||||||||||||||||||||||||
(a) | BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012. | |||||||||||||||||||||||
(b) | 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_Tables
Severance (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Restructuring and Related Activities [Abstract] | |||||||||||||||||||||
Business Acquisition, Integration, Restructuring and Other Related Costs [Text Block] | ounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration: | ||||||||||||||||||||
Year Ended December 31, 2014 | Exelon and Generation | ||||||||||||||||||||
Severance Liability | |||||||||||||||||||||
Balance at December 31, 2013 | $ | 2 | |||||||||||||||||||
Integration of CENG (a) | 19 | ||||||||||||||||||||
Severance charges | 3 | ||||||||||||||||||||
Payments | (11 | ) | |||||||||||||||||||
Balance at December 31, 2014 | $ | 13 | |||||||||||||||||||
______________________ | |||||||||||||||||||||
(a) | Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||
Schedule of Restructuring and Related Costs | For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, 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 | — | 1 | ||||||||||||||||
Other charges | 7 | 4 | 1 | — | 1 | ||||||||||||||||
Total severance benefits | $ | 138 | $ | 88 | $ | 16 | $ | 7 | $ | 19 | |||||||||||
________________________ | |||||||||||||||||||||
(a) | 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. | ||||||||||||||||||||
(b) | 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 Corporate Restructuring Severance Obligations | 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, 2012 | $ | 111 | $ | 33 | $ | 1 | $ | — | $ | 11 | |||||||||||
Severance charges (a) | 5 | 1 | — | — | — | ||||||||||||||||
Stock compensation | 1 | — | — | — | — | ||||||||||||||||
Payments | (64 | ) | (24 | ) | (1 | ) | — | (5 | ) | ||||||||||||
Balance at December 31, 2013 | $ | 53 | $ | 10 | $ | — | $ | — | $ | 6 | |||||||||||
Payments | (41 | ) | (7 | ) | — | — | (4 | ) | |||||||||||||
Balance at December 31, 2014 | $ | 12 | $ | 3 | $ | — | $ | — | $ | 2 | |||||||||||
________________________ | |||||||||||||||||||||
(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, 2014 and December 31, 2013. | ||||||||||||||||||||
Schedule Of Severance Costs | For the years ended December 31, 2014, 2013, and 2012, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income: | ||||||||||||||||||||
Severance Benefits (a) | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Severance Charges-2014 | $ | 7 | $ | 5 | $ | 1 | $ | — | $ | 1 | |||||||||||
Severance Charges-2013 | 18 | 16 | 2 | — | — | ||||||||||||||||
Severance Charges-2012 | 19 | 14 | 2 | 1 | 3 | ||||||||||||||||
________________________ | |||||||||||||||||||||
(a) | The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material. | ||||||||||||||||||||
(b) | The amount of ongoing severance for Generation for the year ended December 31, 2014 includes a $3 million severance reserve as a result of anticipated employee position reductions due to recent acquisitions. |
Preferred_and_Preference_Secur1
Preferred and Preference Securities (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Equity [Abstract] | ||||||||||||||||||
Schedule of Stock by Class | ||||||||||||||||||
December 31, | ||||||||||||||||||
Redemption | 2014 | 2013 | 2014 | 2013 | ||||||||||||||
Price (a) | 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 | 400,000 | 400,000 | 40 | 40 | |||||||||||||
6.99%, 1995 Series | 100.35 | 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. | |||||||||||||||||
The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013: | ||||||||||||||||||
December 31, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
Par Value | Shares Authorized | Shares Outstanding | ||||||||||||||||
Common Stock | ||||||||||||||||||
Exelon | no par value | 2,000,000,000 | 859,833,343 | 857,290,484 | ||||||||||||||
ComEd | $ | 12.5 | 250,000,000 | 127,016,947 | 127,016,896 | |||||||||||||
PECO | no par value | 500,000,000 | 170,478,507 | 170,478,507 | ||||||||||||||
BGE | no par value | 175,000,000 | 1,000 | 1,000 | ||||||||||||||
Common_Stock_Tables
Common Stock (Tables) | 12 Months Ended | |||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||
Common Stock [Abstract] | ||||||||||||||||||
Schedule of Stock by Class | ||||||||||||||||||
December 31, | ||||||||||||||||||
Redemption | 2014 | 2013 | 2014 | 2013 | ||||||||||||||
Price (a) | 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 | 400,000 | 400,000 | 40 | 40 | |||||||||||||
6.99%, 1995 Series | 100.35 | 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. | |||||||||||||||||
The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013: | ||||||||||||||||||
December 31, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
Par Value | Shares Authorized | Shares Outstanding | ||||||||||||||||
Common Stock | ||||||||||||||||||
Exelon | no par value | 2,000,000,000 | 859,833,343 | 857,290,484 | ||||||||||||||
ComEd | $ | 12.5 | 250,000,000 | 127,016,947 | 127,016,896 | |||||||||||||
PECO | no par value | 500,000,000 | 170,478,507 | 170,478,507 | ||||||||||||||
BGE | no par value | 175,000,000 | 1,000 | 1,000 | ||||||||||||||
Stock Based Compensation Components | The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||
Year Ended | ||||||||||||||||||
December 31, | ||||||||||||||||||
Components of Stock-Based Compensation Expense | 2014 | 2013 | 2012 | |||||||||||||||
Performance share awards | $ | 59 | $ | 48 | $ | 46 | ||||||||||||
Restricted stock units | 61 | 61 | 50 | |||||||||||||||
Stock options | 2 | 3 | 15 | |||||||||||||||
Other stock-based awards | 5 | 6 | 4 | |||||||||||||||
Total stock-based compensation expense included in operating and | 127 | 118 | 115 | |||||||||||||||
maintenance expense | ||||||||||||||||||
Income tax benefit | (47 | ) | (44 | ) | (44 | ) | ||||||||||||
Total after-tax stock-based compensation expense | $ | 80 | $ | 74 | $ | 71 | ||||||||||||
Stock Based Compensation Expense Subsidiaries | The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||
Year Ended | ||||||||||||||||||
December 31, | ||||||||||||||||||
Subsidiaries | 2014 | 2013 | 2012 (a) | |||||||||||||||
Generation | $ | 52 | $ | 48 | $ | 42 | ||||||||||||
ComEd | 7 | 9 | 11 | |||||||||||||||
PECO | 3 | 5 | 5 | |||||||||||||||
BGE | 5 | 6 | 5 | |||||||||||||||
BSC (b) | 60 | 50 | 52 | |||||||||||||||
Total | $ | 127 | $ | 118 | $ | 115 | ||||||||||||
________________________ | ||||||||||||||||||
(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 table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary 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. | |||||||||||||||||
Stock Based Compensation Tax Benefit | The following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||
Year Ended | ||||||||||||||||||
December 31, | ||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||
Realized tax benefit when exercised/distributed: | ||||||||||||||||||
Stock options | $ | — | $ | — | $ | 3 | ||||||||||||
Restricted stock units | 17 | 11 | 11 | |||||||||||||||
Performance share awards | 11 | 11 | 7 | |||||||||||||||
Stock deferral plan | — | 1 | — | |||||||||||||||
Excess tax benefits included in other financing activities of Exelon’s | ||||||||||||||||||
Consolidated Statements of Cash Flows: | ||||||||||||||||||
Stock options | $ | — | $ | — | $ | 2 | ||||||||||||
Schedule of Assumptions Used | 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 year ended 2012: | |||||||||||||||||
Year ended December 31, 2012 | ||||||||||||||||||
Dividend yield | 5.28 | % | ||||||||||||||||
Expected volatility | 23.2 | % | ||||||||||||||||
Risk-free interest rate | 1.3 | % | ||||||||||||||||
Expected life (years) | 6.25 | |||||||||||||||||
Weighted average grant date fair value (per share) | 4.18 | |||||||||||||||||
Schedule of Share-based Compensation, Stock Options, Activity | The following table presents information with respect to stock option activity for the year ended December 31, 2014: | |||||||||||||||||
Shares | Weighted | Weighted | Aggregate | |||||||||||||||
Average | Average | Intrinsic | ||||||||||||||||
Exercise | Remaining | Value | ||||||||||||||||
Price | Contractual | |||||||||||||||||
(per | Life | |||||||||||||||||
share) | (years) | |||||||||||||||||
Balance of shares outstanding at December 31, 2013 | 21,035,445 | $ | 46.07 | |||||||||||||||
Options exercised | (291,805 | ) | 25.27 | |||||||||||||||
Options forfeited | (8,886 | ) | 55.78 | |||||||||||||||
Options expired | (1,903,787 | ) | 41.47 | |||||||||||||||
Balance of shares outstanding at December 31, 2014 | 18,830,967 | $ | 46.85 | 4.11 | $ | 29 | ||||||||||||
Exercisable at December 31, 2014 (a) | 18,398,932 | $ | 47.01 | 4.04 | $ | 29 | ||||||||||||
____________________ | ||||||||||||||||||
(a) | Includes stock options issued to retirement eligible employees. | |||||||||||||||||
Stock Options Exercised | The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||
Year Ended | ||||||||||||||||||
December 31, | ||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||
Intrinsic value(a) | $ | 3 | $ | 4 | $ | 19 | ||||||||||||
Cash received for exercise price | 7 | 19 | 47 | |||||||||||||||
______________________ | ||||||||||||||||||
(a) | The difference between the market value on the date of exercise and the option exercise price. | |||||||||||||||||
Schedule of Nonvested Share Activity | The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2014: | |||||||||||||||||
Shares | Weighted Average | |||||||||||||||||
Exercise Price | ||||||||||||||||||
(per share) | ||||||||||||||||||
Nonvested at December 31, 2013 (a) | 847,118 | $ | 40.22 | |||||||||||||||
Vested | (406,197 | ) | 40.21 | |||||||||||||||
Forfeited | (8,886 | ) | 55.78 | |||||||||||||||
Nonvested at December 31, 2014 (a) | 432,035 | $ | 39.91 | |||||||||||||||
_____________________ | ||||||||||||||||||
(a) | Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | |||||||||||||||||
Schedule of Nonvested Restricted Stock Units Activity | The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2014: | |||||||||||||||||
Shares | Weighted Average | |||||||||||||||||
Grant Date Fair | ||||||||||||||||||
Value (per share) | ||||||||||||||||||
Nonvested at December 31, 2013 (a) | 3,386,697 | $ | 34.1 | |||||||||||||||
Granted | 2,252,574 | 28.71 | ||||||||||||||||
Vested | (1,216,016 | ) | 35.36 | |||||||||||||||
Forfeited | (86,094 | ) | 31.99 | |||||||||||||||
Undistributed vested awards (b) | (578,943 | ) | 29.17 | |||||||||||||||
Nonvested at December 31, 2014 (a) | 3,758,218 | $ | 31.27 | |||||||||||||||
_______________________ | ||||||||||||||||||
(a) | Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | |||||||||||||||||
(b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014. | |||||||||||||||||
Schedule of Nonvested Performance-based Units Activity | The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2014: | |||||||||||||||||
Shares | Weighted Average | |||||||||||||||||
Grant Date Fair | ||||||||||||||||||
Value (per share) | ||||||||||||||||||
Nonvested at December 31, 2013 (a) | 2,014,190 | $ | 32.74 | |||||||||||||||
Granted | 1,712,085 | 28.75 | ||||||||||||||||
Change in performance | 98,227 | 31.85 | ||||||||||||||||
Vested | (497,714 | ) | 35.05 | |||||||||||||||
Forfeited | (29,476 | ) | 30.16 | |||||||||||||||
Undistributed vested awards (b) | (601,215 | ) | 28.96 | |||||||||||||||
Nonvested at December 31, 2014 (a) | 2,696,097 | $ | 30.62 | |||||||||||||||
_______________________ | ||||||||||||||||||
(a) | Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | |||||||||||||||||
(b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014. | |||||||||||||||||
Not Settled Performance Share Awards Balance Sheet Presentation | The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled: | |||||||||||||||||
December 31, | ||||||||||||||||||
2014 | 2013 | |||||||||||||||||
Current liabilities(a) | $ | 28 | $ | 13 | ||||||||||||||
Deferred credits and other liabilities (b) | 36 | 24 | ||||||||||||||||
Common stock | 33 | 32 | ||||||||||||||||
Total | $ | 97 | $ | 69 | ||||||||||||||
__________________________ | ||||||||||||||||||
(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_1
Earnings Per Share and Equity (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Earnings Per Share [Abstract] | ||||||||||||
Reconciliation of basic and diluted earnings per share | The following table sets forth the components of basic and diluted earnings per share and shows the effect of the 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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Net income attributable to common shareholders | $ | 1,623 | $ | 1,719 | $ | 1,160 | ||||||
Weighted average common shares outstanding—basic | 860 | 856 | 816 | |||||||||
Assumed exercise and/or distributions of stock-based awards | 4 | 4 | 3 | |||||||||
Weighted average common shares outstanding—diluted | 864 | 860 | 819 | |||||||||
Changes_in_Accumulated_Other_C1
Changes in Accumulated Other Comprehensive Income (Tables) | 12 Months Ended | |||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||
Equity [Abstract] | ||||||||||||||||||||||||
Schedule Of Accumulated Other Comprehensive Income (Loss) | The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014 and 2013: | |||||||||||||||||||||||
For the Year Ended December 31, 2014 | Gains and | Unrealized | Pension and | Foreign | AOCI of | Total | ||||||||||||||||||
(Losses) on | Gains and | Non-Pension | Currency | Equity | ||||||||||||||||||||
Cash Flow | (Losses) on | Postretirement | Items | Investments | ||||||||||||||||||||
Hedges | Marketable | Benefit Plan | ||||||||||||||||||||||
Securities | items | |||||||||||||||||||||||
Exelon (a) | ||||||||||||||||||||||||
Beginning balance | $ | 120 | $ | 2 | $ | (2,260 | ) | $ | (10 | ) | $ | 108 | $ | (2,040 | ) | |||||||||
OCI before reclassifications | (31 | ) | (1 | ) | (498 | ) | (9 | ) | 11 | (528 | ) | |||||||||||||
Amounts reclassified from AOCI (b) | (117 | ) | 2 | 118 | — | (119 | ) | (116 | ) | |||||||||||||||
Net current-period OCI | (148 | ) | 1 | (380 | ) | (9 | ) | (108 | ) | (644 | ) | |||||||||||||
Ending balance | $ | (28 | ) | $ | 3 | $ | (2,640 | ) | $ | (19 | ) | $ | — | $ | (2,684 | ) | ||||||||
Generation (a) | ||||||||||||||||||||||||
Beginning balance | $ | 114 | $ | 2 | $ | — | $ | (10 | ) | $ | 108 | $ | 214 | |||||||||||
OCI before reclassifications | (15 | ) | (1 | ) | — | (9 | ) | 11 | (14 | ) | ||||||||||||||
Amounts reclassified from AOCI (b) | (117 | ) | — | — | — | (119 | ) | (236 | ) | |||||||||||||||
Net current-period OCI | (132 | ) | (1 | ) | — | (9 | ) | (108 | ) | (250 | ) | |||||||||||||
Ending balance | $ | (18 | ) | $ | 1 | $ | — | $ | (19 | ) | $ | — | $ | (36 | ) | |||||||||
PECO (a) | ||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
OCI before reclassifications | — | — | — | — | — | — | ||||||||||||||||||
Amounts reclassified from AOCI (b) | — | — | — | — | — | — | ||||||||||||||||||
Net current-period OCI | — | — | — | — | — | — | ||||||||||||||||||
Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
For the Year Ended December 31, 2013 | Gains and | Unrealized | Pension and | Foreign | AOCI of | Total | ||||||||||||||||||
(Losses) on | Gains and | Non-Pension | Currency | Equity | ||||||||||||||||||||
Cash Flow | (Losses) on | Postretirement | Items | Investments | ||||||||||||||||||||
Hedges | Marketable | Benefit Plan | ||||||||||||||||||||||
Securities | items | |||||||||||||||||||||||
Exelon (a) | ||||||||||||||||||||||||
Beginning balance | $ | 368 | $ | — | $ | (3,137 | ) | $ | — | $ | 2 | $ | (2,767 | ) | ||||||||||
OCI before reclassifications | 29 | 2 | 669 | (10 | ) | 101 | 791 | |||||||||||||||||
Amounts reclassified from AOCI (b) | (277 | ) | — | 208 | — | 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 | $ | — | $ | — | $ | — | $ | 1 | 513 | |||||||||||||
OCI before reclassifications | 15 | 2 | — | (10 | ) | 102 | 109 | |||||||||||||||||
Amounts reclassified from AOCI (b) | (413 | ) | — | — | — | 5 | (408 | ) | ||||||||||||||||
Net current-period OCI | (398 | ) | 2 | — | (10 | ) | 107 | (299 | ) | |||||||||||||||
Ending balance | $ | 114 | $ | 2 | $ | — | $ | (10 | ) | $ | 108 | $ | 214 | |||||||||||
PECO (a) | ||||||||||||||||||||||||
Beginning balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
OCI before reclassifications | — | — | — | — | — | — | ||||||||||||||||||
Amounts reclassified from AOCI (b) | — | — | — | — | — | — | ||||||||||||||||||
Net current-period OCI | — | — | — | — | — | — | ||||||||||||||||||
Ending balance | $ | — | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||||
_______________________ | ||||||||||||||||||||||||
(a) | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||||||||||||||||||||
(b) | See next tables for details about these reclassifications. | |||||||||||||||||||||||
Reclassification Out Of Accumulated Other Comprehensive Income | The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2014 and 2013: | |||||||||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the Statements of Operations and Comprehensive Income | ||||||||||||||||||||||
Exelon | Generation | |||||||||||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||||||||||
Energy related hedges | $ | 195 | $ | 195 | Operating revenues | |||||||||||||||||||
195 | 195 | Total before tax | ||||||||||||||||||||||
(78 | ) | (78 | ) | Tax expense | ||||||||||||||||||||
$ | 117 | $ | 117 | Net of tax | ||||||||||||||||||||
Gains and (losses) on available | ||||||||||||||||||||||||
for sale securities | ||||||||||||||||||||||||
Other available securities for sale | $ | (2 | ) | $ | — | Other Income and Deductions | ||||||||||||||||||
$ | (2 | ) | $ | — | Net of tax | |||||||||||||||||||
Amortization of pension and other | ||||||||||||||||||||||||
postretirement benefit plan items | ||||||||||||||||||||||||
Prior service costs (b) | $ | 46 | $ | — | ||||||||||||||||||||
Actuarial losses (b) | (239 | ) | — | |||||||||||||||||||||
(193 | ) | — | Total before tax | |||||||||||||||||||||
75 | — | Tax benefit | ||||||||||||||||||||||
$ | (118 | ) | $ | — | Net of tax | |||||||||||||||||||
Equity investments | ||||||||||||||||||||||||
Sale of equity method investment | $ | 5 | $ | 5 | ||||||||||||||||||||
Reversal of CENG equity method AOCI | 193 | 193 | Equity in losses of unconsolidated affiliates | |||||||||||||||||||||
198 | 198 | Total before tax | ||||||||||||||||||||||
(79 | ) | (79 | ) | Tax expense | ||||||||||||||||||||
$ | 119 | $ | 119 | Net of tax | ||||||||||||||||||||
Total Reclassifications | $ | 116 | $ | 236 | Net of tax | |||||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||||||||||
Details about AOCI components | Items reclassified out of AOCI (a) | Affected line item in the Statements of Operations and Comprehensive Income | ||||||||||||||||||||||
Exelon | Generation | |||||||||||||||||||||||
Gains and (losses) on cash flow hedges | ||||||||||||||||||||||||
Energy related hedges | $ | 464 | $ | 683 | Operating revenues | |||||||||||||||||||
Other cash flow hedges | (3 | ) | — | Interest expense | ||||||||||||||||||||
461 | 683 | Total before tax | ||||||||||||||||||||||
(184 | ) | (270 | ) | Tax expense | ||||||||||||||||||||
$ | 277 | $ | 413 | Net of tax | ||||||||||||||||||||
Amortization of pension and other | ||||||||||||||||||||||||
postretirement benefit plan items | ||||||||||||||||||||||||
Prior service costs (b) | $ | (2 | ) | $ | — | |||||||||||||||||||
Actuarial losses (b) | (339 | ) | — | |||||||||||||||||||||
Deferred compensation unit plan (c) | (1 | ) | — | |||||||||||||||||||||
(342 | ) | — | Total before tax | |||||||||||||||||||||
134 | — | Tax benefit | ||||||||||||||||||||||
$ | (208 | ) | $ | — | 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 — Retirement Benefits for additional details). | |||||||||||||||||||||||
(c) | Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. | |||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2014 and 2013: | |||||||||||||||||||||||
For the Years Ended December 31, | ||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||
Exelon | ||||||||||||||||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||||||||||||
Prior service benefit reclassified to periodic benefit cost | $ | 19 | $ | — | $ | (1 | ) | |||||||||||||||||
Actuarial loss reclassified to periodic cost | (93 | ) | (133 | ) | (110 | ) | ||||||||||||||||||
Transition obligation reclassified to periodic cost | — | — | (2 | ) | ||||||||||||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment | 317 | (430 | ) | 237 | ||||||||||||||||||||
Change in unrealized loss on cash flow hedges | 96 | 166 | 68 | |||||||||||||||||||||
Change in marketable securities | — | — | 1 | |||||||||||||||||||||
Change in unrealized income on equity investments | 73 | (71 | ) | (1 | ) | |||||||||||||||||||
Total | $ | 412 | $ | (468 | ) | $ | 192 | |||||||||||||||||
Generation | ||||||||||||||||||||||||
Change in unrealized loss on cash flow hedges | $ | 84 | $ | 262 | $ | 262 | ||||||||||||||||||
Change in unrealized income on equity investments | 73 | (72 | ) | 1 | ||||||||||||||||||||
Total | $ | 157 | $ | 190 | $ | 263 | ||||||||||||||||||
Commitments_and_Contingencies_1
Commitments and Contingencies (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Environmental Loss Contingency Tables [Abstract] | ||||||||||||||||||||||||||||
Schedule of Government Settlement Agreements | Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows: | |||||||||||||||||||||||||||
Total | Net (a) | |||||||||||||||||||||||||||
Cumulative cash reimbursements (b) | $ | 836 | $ | 702 | ||||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(a) | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. | |||||||||||||||||||||||||||
(b) | Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG. | |||||||||||||||||||||||||||
As of December 31, 2014, and 2013, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows: | ||||||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | |||||||||||||||||||||||||||
DOE receivable - current (a) | $ | 82 | $ | 71 | ||||||||||||||||||||||||
DOE receivable - noncurrent (b) | 7 | — | ||||||||||||||||||||||||||
Amounts owed to co-owners (a)(c) | (5 | ) | (18 | ) | ||||||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(a) | Recorded in Accounts receivable, other. | |||||||||||||||||||||||||||
(b) | Recorded in Deferred debits and other assets, other | |||||||||||||||||||||||||||
(c) | Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. | |||||||||||||||||||||||||||
Energy Commitments | At December 31, 2014, 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 | Total | |||||||||||||||||||||||||
Purchases (a) | Purchases (b) | Purchases (c) | ||||||||||||||||||||||||||
2015 | $ | 418 | $ | 152 | $ | 20 | $ | 590 | ||||||||||||||||||||
2016 | 283 | 228 | 15 | 526 | ||||||||||||||||||||||||
2017 | 222 | 121 | 15 | 358 | ||||||||||||||||||||||||
2018 | 112 | 29 | 16 | 157 | ||||||||||||||||||||||||
2019 | 117 | 5 | 16 | 138 | ||||||||||||||||||||||||
Thereafter | 279 | 1 | 35 | 315 | ||||||||||||||||||||||||
Total | $ | 1,431 | $ | 536 | $ | 117 | $ | 2,084 | ||||||||||||||||||||
_____________________________ | ||||||||||||||||||||||||||||
(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, 2014, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of December 31, 2014, capacity offsets were $132 million, $133 million, $136 million, $137 million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. 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 | |||||||||||||||||||||||||||
Utility Energy Purchase Commitments | ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments as of December 31, 2014 are as follows: | |||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
ComEd | ||||||||||||||||||||||||||||
Electric supply procurement (a) | $ | 620 | $ | 329 | $ | 151 | $ | 140 | $ | — | $ | — | $ | — | ||||||||||||||
Renewable energy and RECs (b) | 1,517 | 75 | 76 | 77 | 78 | 84 | 1,127 | |||||||||||||||||||||
PECO | ||||||||||||||||||||||||||||
Electric supply procurement (c) | 609 | 527 | 82 | — | — | — | — | |||||||||||||||||||||
AECs (d) | 13 | 2 | 2 | 2 | 2 | 2 | 3 | |||||||||||||||||||||
BGE | ||||||||||||||||||||||||||||
Electric supply procurement (e) | 1,315 | 779 | 448 | 88 | — | — | — | |||||||||||||||||||||
Curtailment services (f) | 115 | 40 | 34 | 29 | 12 | — | — | |||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||
(a) | ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. | |||||||||||||||||||||||||||
(b) | Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. | |||||||||||||||||||||||||||
(c) | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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. | |||||||||||||||||||||||||||
(d) | 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. | |||||||||||||||||||||||||||
(e) | BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||
(f) | 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. | |||||||||||||||||||||||||||
Other Purchase Obligation | The Registrants’ other purchase obligations as of December 31, 2014, which primarily represent commitments for services, materials and information technology, are as follows: | |||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Exelon | $ | 894 | $ | 336 | $ | 258 | $ | 150 | $ | 36 | $ | 30 | $ | 84 | ||||||||||||||
Generation (a)(b) | 396 | 163 | 67 | 42 | 30 | 24 | 70 | |||||||||||||||||||||
ComEd (c) | 148 | 63 | 77 | 1 | 1 | 1 | 5 | |||||||||||||||||||||
PECO (c) | 7 | 3 | 4 | — | — | — | — | |||||||||||||||||||||
BGE (c) | 343 | 107 | 110 | 107 | 5 | 5 | 9 | |||||||||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(a) | Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information. | |||||||||||||||||||||||||||
(b) | Purchase obligations include commitments related to assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information. | |||||||||||||||||||||||||||
(c) | Purchase obligations include commitments related to smart meter installation. See Note 3 — Regulatory Matters for additional information. | |||||||||||||||||||||||||||
Fuel Purchase Commitments | As of December 31, 2014, these commitments were as follows: | |||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Generation | $ | 8,981 | $ | 1,404 | $ | 1,119 | $ | 1,124 | $ | 1,001 | $ | 888 | $ | 3,445 | ||||||||||||||
PECO | 428 | 146 | 103 | 60 | 34 | 14 | 71 | |||||||||||||||||||||
BGE | 611 | 111 | 82 | 67 | 57 | 54 | 240 | |||||||||||||||||||||
Commercial Commitments | PECO’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | |||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 22 | $ | 22 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 18 | 18 | — | — | — | — | — | |||||||||||||||||||||
Performance guarantees(c) | 178 | — | — | — | — | — | 178 | |||||||||||||||||||||
Total commercial commitments | $ | 218 | $ | 40 | $ | — | $ | — | $ | — | $ | — | $ | 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. | |||||||||||||||||||||||||||
ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 17 | $ | 17 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 5 | 3 | — | — | — | — | 2 | |||||||||||||||||||||
Performance guarantees (c) | 200 | — | — | — | — | — | 200 | |||||||||||||||||||||
Total commercial commitments | $ | 222 | $ | 20 | $ | — | $ | — | $ | — | $ | — | $ | 202 | ||||||||||||||
_________________________ | ||||||||||||||||||||||||||||
(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. | |||||||||||||||||||||||||||
Exelon’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,233 | $ | 1,151 | $ | 77 | $ | 5 | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds(b) | 596 | 545 | 10 | 4 | 1 | 2 | 34 | |||||||||||||||||||||
Performance guarantees (c) | 1,239 | 472 | 20 | 20 | 20 | 20 | 687 | |||||||||||||||||||||
Energy marketing contract | 3,220 | 3,220 | — | — | — | — | — | |||||||||||||||||||||
guarantees (d) | ||||||||||||||||||||||||||||
Lease guarantees(e) | 40 | — | — | — | — | — | 40 | |||||||||||||||||||||
Nuclear insurance premiums (f) | 3,014 | — | — | — | — | — | 3,014 | |||||||||||||||||||||
Underwriters discount (g) | 60 | 60 | — | — | — | — | — | |||||||||||||||||||||
Total commercial commitments | $ | 9,402 | $ | 5,448 | $ | 107 | $ | 29 | $ | 21 | $ | 22 | $ | 3,775 | ||||||||||||||
___________________________ | ||||||||||||||||||||||||||||
(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. Additionally includes $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 $3.2 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 $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 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. | |||||||||||||||||||||||||||
(g) | Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering. | |||||||||||||||||||||||||||
BGE’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1 | $ | 1 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds (b) | 11 | 11 | — | — | — | — | — | |||||||||||||||||||||
Performance guarantees (c) | 253 | 3 | — | — | — | — | 250 | |||||||||||||||||||||
Total commercial commitments | $ | 265 | $ | 15 | $ | — | $ | — | $ | — | $ | — | $ | 250 | ||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(a) | Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |||||||||||||||||||||||||||
(b) | Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds. | |||||||||||||||||||||||||||
(c) | Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE. | |||||||||||||||||||||||||||
Generation’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows: | ||||||||||||||||||||||||||||
Expiration within | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||||||
and beyond | ||||||||||||||||||||||||||||
Letters of credit (non-debt) (a) | $ | 1,187 | $ | 1,106 | $ | 76 | $ | 5 | $ | — | $ | — | $ | — | ||||||||||||||
Surety bonds | 481 | 468 | 3 | — | — | — | 10 | |||||||||||||||||||||
Performance guarantees (b) | 458 | 319 | 20 | 20 | 20 | 20 | 59 | |||||||||||||||||||||
Energy marketing contract | 1,244 | 1,244 | — | — | — | — | — | |||||||||||||||||||||
guarantees (c) | ||||||||||||||||||||||||||||
Nuclear insurance premiums (d) | 3,014 | — | — | — | — | — | 3,014 | |||||||||||||||||||||
Total commercial commitments | $ | 6,384 | $ | 3,137 | $ | 99 | $ | 25 | $ | 20 | $ | 20 | $ | 3,083 | ||||||||||||||
________________________ | ||||||||||||||||||||||||||||
(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. | |||||||||||||||||||||||||||
(c) | Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 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. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 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, including CENG sites, 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. | |||||||||||||||||||||||||||
Other Commitments | The commitment includes approximately $20 million of in-kind services. As of December 31, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows: | |||||||||||||||||||||||||||
Total | ||||||||||||||||||||||||||||
2015 | $ | 98 | ||||||||||||||||||||||||||
2016 | 38 | |||||||||||||||||||||||||||
2017 | 20 | |||||||||||||||||||||||||||
2018 | 11 | |||||||||||||||||||||||||||
Total | $ | 167 | ||||||||||||||||||||||||||
Operating Leases Of Lessee Disclosure | Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2014 were: | |||||||||||||||||||||||||||
Exelon | Generation (b) | ComEd (c) | PECO (c) | BGE (c)(d) | ||||||||||||||||||||||||
2015 | $ | 99 | $ | 51 | $ | 14 | $ | 3 | $ | 13 | ||||||||||||||||||
2016 | 102 | 57 | 13 | 3 | 11 | |||||||||||||||||||||||
2017 | 102 | 63 | 8 | 3 | 10 | |||||||||||||||||||||||
2018 | 86 | 57 | 4 | 3 | 9 | |||||||||||||||||||||||
2019 | 70 | 43 | 4 | 2 | 7 | |||||||||||||||||||||||
Remaining years | 699 | 628 | 2 | — | 27 | |||||||||||||||||||||||
Total minimum future lease payments | $ | 1,158 | (a) | $ | 899 | (a) | $ | 45 | $ | 14 | $ | 77 | ||||||||||||||||
______________________ | ||||||||||||||||||||||||||||
(a) | Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment. | |||||||||||||||||||||||||||
(b) | The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million . | |||||||||||||||||||||||||||
(c) | 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 2015—2019, was $2 million, $3 million, and $2 million respectively. | |||||||||||||||||||||||||||
(d) | Includes all future lease payments on a 99 year real estate lease that expires in 2106. | |||||||||||||||||||||||||||
Operating Leases Rent Expense | The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2014, 2013 and 2012: | |||||||||||||||||||||||||||
For the Year Ended December 31, | Exelon | Generation (a) | ComEd | PECO | BGE | |||||||||||||||||||||||
2014 | $ | 865 | $ | 806 | $ | 15 | $ | 14 | $ | 12 | ||||||||||||||||||
2013 | 806 | 744 | 15 | 21 | 11 | |||||||||||||||||||||||
2012 | 930 | 872 | 18 | 27 | 12 | |||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||
(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 $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively. | |||||||||||||||||||||||||||
Accrued environmental liabilities | As of December 31, 2014 and 2013, 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: | |||||||||||||||||||||||||||
December 31, 2014 | Total environmental | Portion of total related to MGP | ||||||||||||||||||||||||||
investigation | investigation and remediation | |||||||||||||||||||||||||||
and remediation reserve | ||||||||||||||||||||||||||||
Exelon | $ | 347 | $ | 277 | ||||||||||||||||||||||||
Generation | 63 | — | ||||||||||||||||||||||||||
ComEd | 238 | 235 | ||||||||||||||||||||||||||
PECO | 45 | 42 | ||||||||||||||||||||||||||
BGE | 1 | — | ||||||||||||||||||||||||||
31-Dec-13 | Total environmental | Portion of total related to MGP | ||||||||||||||||||||||||||
investigation | investigation and remediation | |||||||||||||||||||||||||||
and remediation reserve | ||||||||||||||||||||||||||||
Exelon | $ | 338 | $ | 273 | ||||||||||||||||||||||||
Generation | 56 | — | ||||||||||||||||||||||||||
ComEd | 234 | 229 | ||||||||||||||||||||||||||
PECO | 47 | 44 | ||||||||||||||||||||||||||
BGE | 1 | — | ||||||||||||||||||||||||||
Supplemental_Financial_Informa1
Supplemental Financial Information (Tables) | 12 Months Ended | ||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||
Supplemental Financial Information [Abstract] | |||||||||||||||||||||
Components of taxes other than income | The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012. | ||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Taxes other than income | |||||||||||||||||||||
Utility (a) | $ | 456 | $ | 89 | $ | 238 | $ | 128 | $ | 86 | |||||||||||
Property | 396 | 240 | 25 | 15 | 114 | ||||||||||||||||
Payroll | 200 | 118 | 28 | 14 | 18 | ||||||||||||||||
Other | 102 | 18 | 2 | 2 | 3 | ||||||||||||||||
Total taxes other than income | $ | 1,154 | $ | 465 | 293 | $ | 159 | $ | 221 | ||||||||||||
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 | |||||||||||
_____________________ | |||||||||||||||||||||
(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, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Other, Net | |||||||||||||||||||||
Decommissioning-related activities: | |||||||||||||||||||||
Net realized income on decommissioning | |||||||||||||||||||||
trust funds (a)— | |||||||||||||||||||||
Regulatory agreement units | $ | 216 | $ | 216 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 159 | 159 | — | — | — | ||||||||||||||||
Net unrealized gains on decommissioning | |||||||||||||||||||||
trust funds— | |||||||||||||||||||||
Regulatory agreement units | 180 | 180 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 134 | 134 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 29 | 29 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (358 | ) | (358 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 360 | 360 | — | — | — | ||||||||||||||||
Investment income | 1 | 1 | — | (1 | ) | 7 | (c) | ||||||||||||||
Long-term lease income | 24 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 40 | 54 | — | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 21 | — | 3 | 6 | 12 | ||||||||||||||||
Other | 9 | (9 | ) | 14 | 2 | (1 | ) | ||||||||||||||
Other, net | $ | 455 | $ | 406 | $ | 17 | $ | 7 | $ | 18 | |||||||||||
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 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 77 | 77 | — | — | — | ||||||||||||||||
Net unrealized gains on decommissioning trust | |||||||||||||||||||||
funds— | |||||||||||||||||||||
Regulatory agreement units | 406 | 406 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 146 | 146 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 7 | 7 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (546 | ) | (546 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 346 | 346 | — | — | — | ||||||||||||||||
Investment income | 8 | (1 | ) | — | (1 | ) | 9 | (c) | |||||||||||||
Long-term lease income | 28 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 24 | 4 | — | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 22 | — | 11 | 4 | 7 | ||||||||||||||||
Other | 32 | 6 | 15 | 3 | 1 | ||||||||||||||||
Other, net | $ | 460 | $ | 355 | $ | 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 | $ | — | $ | — | $ | — | |||||||||||
Non-regulatory agreement units | 102 | 102 | — | — | — | ||||||||||||||||
Net unrealized losses on decommissioning | |||||||||||||||||||||
trust funds— | |||||||||||||||||||||
Regulatory agreement units | 386 | 386 | — | — | — | ||||||||||||||||
Non-regulatory agreement units | 105 | 105 | — | — | — | ||||||||||||||||
Net unrealized gains on pledged assets— | |||||||||||||||||||||
Zion Station decommissioning | 73 | 73 | — | — | — | ||||||||||||||||
Regulatory offset to decommissioning trust | (530 | ) | (530 | ) | — | — | — | ||||||||||||||
fund-related activities (b) | |||||||||||||||||||||
Total decommissioning-related activities | 325 | 325 | — | — | — | ||||||||||||||||
Investment income | 20 | 3 | 1 | 2 | 11 | (c) | |||||||||||||||
Long-term lease income | 29 | — | — | — | — | ||||||||||||||||
Interest income related to uncertain income tax | 15 | 2 | 20 | — | — | ||||||||||||||||
positions | |||||||||||||||||||||
AFUDC—Equity | 17 | — | 6 | 4 | 10 | ||||||||||||||||
Credit Facility termination fees | (85 | ) | (85 | ) | — | — | — | ||||||||||||||
Other | 32 | 1 | 12 | 2 | 2 | ||||||||||||||||
Other, net | $ | 353 | $ | 246 | $ | 39 | $ | 8 | $ | 23 | |||||||||||
_________________________ | |||||||||||||||||||||
(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 | The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012. | ||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Depreciation, amortization, accretion and | |||||||||||||||||||||
depletion | |||||||||||||||||||||
Property, plant and equipment | $ | 2,080 | $ | 922 | $ | 588 | $ | 227 | $ | 288 | |||||||||||
Regulatory assets | 191 | — | 99 | 9 | 83 | ||||||||||||||||
Amortization of intangible assets, net | 44 | 44 | — | — | — | ||||||||||||||||
Amortization of energy contract assets and | 135 | 135 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 1,073 | 1,073 | — | — | — | ||||||||||||||||
ARO accretion (c) | 345 | 345 | — | — | — | ||||||||||||||||
Total depreciation, amortization, accretion and | $ | 3,868 | $ | 2,519 | $ | 687 | $ | 236 | $ | 371 | |||||||||||
depletion | |||||||||||||||||||||
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 | — | 119 | 9 | 84 | ||||||||||||||||
Amortization of intangible assets, net | 48 | 43 | 5 | — | — | ||||||||||||||||
Amortization of energy contract assets and | 430 | 507 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 921 | 921 | — | — | — | ||||||||||||||||
ARO accretion (c) | 275 | 275 | — | — | — | ||||||||||||||||
Total depreciation, amortization, accretion and | $ | 3,779 | $ | 2,559 | $ | 669 | $ | 228 | $ | 348 | |||||||||||
depletion | |||||||||||||||||||||
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 | — | 80 | 10 | 53 | ||||||||||||||||
Amortization of intangible assets, net | 40 | 35 | 5 | — | — | ||||||||||||||||
Amortization of energy contract assets and | 1,110 | 1,110 | — | — | — | ||||||||||||||||
liabilities (a) | |||||||||||||||||||||
Nuclear fuel (b) | 848 | 848 | — | — | — | ||||||||||||||||
ARO accretion (c) | 240 | 240 | — | — | — | ||||||||||||||||
Total depreciation, amortization and accretion | $ | 4,079 | $ | 2,966 | $ | 610 | $ | 217 | $ | 298 | |||||||||||
________________________ | |||||||||||||||||||||
(a) | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
(b) | Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
(c) | Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||||||||||||||||
Schedule of Cash Flow, Supplemental Disclosure | |||||||||||||||||||||
For the year ended December 31, 2014 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Cash paid (refunded) during the year: | |||||||||||||||||||||
Interest (net of amount capitalized) | $ | 940 | $ | 322 | $ | 292 | $ | 94 | $ | 111 | |||||||||||
Income taxes (net of refunds) | $ | 314 | 227 | (6 | ) | 85 | (21 | ) | |||||||||||||
Other non-cash operating activities: | |||||||||||||||||||||
Pension and non-pension postretirement benefit | $ | 560 | $ | 249 | 162 | $ | 36 | $ | 64 | ||||||||||||
costs | |||||||||||||||||||||
Loss from equity method investments | 22 | 20 | — | — | — | ||||||||||||||||
Provision for uncollectible accounts | 156 | 14 | 26 | 52 | 64 | ||||||||||||||||
Provision for excess and obsolete inventory | 5 | 5 | — | — | — | ||||||||||||||||
Stock-based compensation costs | 91 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (132 | ) | (132 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 122 | 122 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt | 11 | — | 8 | 3 | — | ||||||||||||||||
costs | |||||||||||||||||||||
Amortization of rate stabilization deferral | 65 | — | — | — | 65 | ||||||||||||||||
Amortization of debt fair value adjustment | (23 | ) | (23 | ) | — | — | — | ||||||||||||||
Merger-related commitments | 44 | 44 | — | — | — | ||||||||||||||||
Amortization of debt costs | 53 | 12 | 4 | 2 | 2 | ||||||||||||||||
Discrete impacts from EIMA (c) | 53 | — | 53 | — | — | ||||||||||||||||
Lower of cost or market inventory adjustment | 29 | 29 | — | — | — | ||||||||||||||||
Other | (2 | ) | 6 | 2 | (1 | ) | (15 | ) | |||||||||||||
Total other non-cash operating activities | $ | 1,054 | $ | 346 | $ | 255 | $ | 92 | $ | 180 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission | $ | 47 | $ | — | $ | 36 | $ | — | $ | 11 | |||||||||||
costs | |||||||||||||||||||||
Other regulatory assets and liabilities | (167 | ) | — | (13 | ) | (16 | ) | (121 | ) | ||||||||||||
Cash deposits (d) | (241 | ) | (241 | ) | — | — | — | ||||||||||||||
Other current assets | 7 | 81 | (10 | ) | (2 | ) | (44 | ) | |||||||||||||
Other noncurrent assets and liabilities | (204 | ) | (89 | ) | 32 | 1 | (9 | ) | |||||||||||||
Total changes in other assets and liabilities | $ | (558 | ) | $ | (249 | ) | $ | 45 | $ | (17 | ) | $ | (163 | ) | |||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | 72 | $ | 72 | $ | — | $ | — | $ | — | |||||||||||
Change in capital expenditures not paid | 220 | (61 | ) | (e) | 78 | — | 25 | ||||||||||||||
Fair value of net assets recorded upon CENG | (3,400 | ) | (3,400 | ) | — | — | — | ||||||||||||||
consolidation (f) | |||||||||||||||||||||
Issuance of equity units (g) | 131 | — | — | — | — | ||||||||||||||||
Nuclear fuel procurement (h) | 70 | 70 | — | — | — | ||||||||||||||||
Indemnification of like-kind exchange position (i) | — | — | 5 | — | — | ||||||||||||||||
____________________________ | |||||||||||||||||||||
(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 primarily to cash deposits made to ISO's/RTO's. | ||||||||||||||||||||
(e) | Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley. | ||||||||||||||||||||
(f) | See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||||||||||||||||
(g) | Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information. | ||||||||||||||||||||
(h) | Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018. | ||||||||||||||||||||
(i) | See Note 14 — Income Taxes for discussion of the like-kind exchange tax position. | ||||||||||||||||||||
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 | |||||||||||
Gain from equity method investments | (10 | ) | (10 | ) | — | — | — | ||||||||||||||
Provision for uncollectible accounts | 101 | 10 | (15 | ) | 61 | 44 | |||||||||||||||
Provision for excess and obsolete inventory | 9 | 9 | — | — | — | ||||||||||||||||
Stock-based compensation costs | 120 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (169 | ) | (169 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 104 | 104 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt | 12 | — | 9 | 3 | — | ||||||||||||||||
costs | |||||||||||||||||||||
Amortization of rate stabilization deferral | 66 | — | — | — | 66 | ||||||||||||||||
Amortization of debt fair value adjustment | (34 | ) | (34 | ) | — | — | — | ||||||||||||||
Discrete impacts from EIMA (c) | (271 | ) | — | (271 | ) | — | — | ||||||||||||||
Amortization of debt costs | 18 | 10 | 1 | 2 | 2 | ||||||||||||||||
Other | (53 | ) | 5 | (4 | ) | (1 | ) | (15 | ) | ||||||||||||
Total other non-cash operating activities | $ | 718 | $ | 270 | $ | 28 | $ | 108 | $ | 153 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission | $ | 12 | $ | — | $ | (35 | ) | $ | 9 | $ | 38 | ||||||||||
costs | |||||||||||||||||||||
Other regulatory assets and liabilities | (64 | ) | — | (43 | ) | (16 | ) | (71 | ) | ||||||||||||
Other current assets | (165 | ) | (151 | ) | 51 | 13 | (8 | ) | |||||||||||||
Other noncurrent assets and liabilities | 322 | 15 | 268 | (d) | (12 | ) | (23 | ) | |||||||||||||
Total changes in other assets and liabilities | $ | 105 | $ | (136 | ) | $ | 241 | $ | (6 | ) | $ | (64 | ) | ||||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | (128 | ) | $ | (128 | ) | $ | — | $ | — | $ | 4 | |||||||||
Change in capital expenditures not paid | (38 | ) | (107 | ) | (e) | (8 | ) | 13 | (48 | ) | |||||||||||
Consolidated VIE dividend to noncontrolling interest | 63 | 63 | — | — | — | ||||||||||||||||
Indemnification of like-kind exchange position (f) | — | — | 176 | — | — | ||||||||||||||||
______________________ | |||||||||||||||||||||
(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 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. | ||||||||||||||||||||
(e) | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | ||||||||||||||||||||
(f) | See Note 14 — Income Taxes for discussion of the like-kind exchanged 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 | |||||||||||
Earnings from equity method investments | 91 | 91 | — | — | — | ||||||||||||||||
Provision for uncollectible accounts | 164 | 22 | 42 | 60 | 44 | ||||||||||||||||
Provision for excess and obsolete inventory | 6 | 6 | 1 | — | — | ||||||||||||||||
Stock-based compensation costs | 94 | — | — | — | — | ||||||||||||||||
Other decommissioning-related activity (a) | (145 | ) | (145 | ) | — | — | — | ||||||||||||||
Energy-related options (b) | 160 | 160 | — | — | — | ||||||||||||||||
Amortization of regulatory asset related to debt costs | 18 | — | 13 | 3 | 2 | ||||||||||||||||
Amortization of rate stabilization deferral | 57 | — | — | — | 67 | ||||||||||||||||
Amortization of debt fair value adjustment | (34 | ) | (34 | ) | — | — | — | ||||||||||||||
Merger-related commitments (c) | 141 | 32 | — | — | 27 | ||||||||||||||||
Severance costs | 99 | 34 | — | — | — | ||||||||||||||||
Discrete impacts from EIMA (d) | (96 | ) | — | (96 | ) | — | — | ||||||||||||||
Amortization of debt costs | 19 | 11 | 5 | 3 | 2 | ||||||||||||||||
Other | (30 | ) | — | 5 | 9 | (6 | ) | ||||||||||||||
Total other non-cash operating activities | $ | 1,364 | $ | 518 | $ | 252 | $ | 125 | $ | 193 | |||||||||||
Changes in other assets and liabilities: | |||||||||||||||||||||
Under/over-recovered energy and transmission costs | $ | 71 | $ | — | $ | 28 | $ | 20 | $ | 26 | |||||||||||
Other regulatory assets and liabilities | (404 | ) | $ | — | (68 | ) | 18 | (112 | ) | ||||||||||||
Other current assets | 213 | (30 | ) | 33 | (12 | ) | (7 | ) | |||||||||||||
Other noncurrent assets and liabilities | (248 | ) | (98 | ) | (95 | ) | (10 | ) | 8 | ||||||||||||
Total changes in other assets and liabilities | $ | (368 | ) | $ | (128 | ) | $ | (102 | ) | $ | 16 | $ | (85 | ) | |||||||
Non-cash investing and financing activities: | |||||||||||||||||||||
Change in ARC | $ | 781 | $ | 781 | $ | 2 | $ | — | $ | — | |||||||||||
Change in capital expenditures not paid | 160 | 103 | (e) | 15 | 26 | (4 | ) | ||||||||||||||
Consolidated VIE dividend to noncontrolling interest | 7,365 | 5,264 | — | — | — | ||||||||||||||||
_________________________ | |||||||||||||||||||||
(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) | Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments. | ||||||||||||||||||||
(d) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters. | ||||||||||||||||||||
(e) | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | ||||||||||||||||||||
Investments | The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2014 and 2013. | ||||||||||||||||||||
31-Dec-14 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Investments | |||||||||||||||||||||
Equity method investments: | |||||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | — | $ | 6 | $ | 8 | $ | 8 | |||||||||||
Bloom Energy | 13 | 13 | — | — | — | ||||||||||||||||
Net Power | 9 | 9 | — | — | — | ||||||||||||||||
Sunnyside | 5 | 5 | — | — | — | ||||||||||||||||
Other equity method investments | 1 | 1 | — | — | — | ||||||||||||||||
Total equity method investments | 50 | 28 | 6 | 8 | 8 | ||||||||||||||||
Other investments: | |||||||||||||||||||||
Net investment in leases | 367 | 7 | — | — | — | ||||||||||||||||
Employee benefit trusts and investments (b) | 85 | 27 | — | 23 | 4 | ||||||||||||||||
Other investments (c) | 42 | 42 | — | — | — | ||||||||||||||||
Total investments | $ | 544 | $ | 104 | $ | 6 | $ | 31 | $ | 12 | |||||||||||
31-Dec-13 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Investments | |||||||||||||||||||||
Equity method investments: | |||||||||||||||||||||
Financing trusts (a) | $ | 22 | $ | — | $ | 6 | $ | 8 | $ | 8 | |||||||||||
Keystone Fuels, LLC | 32 | 32 | — | — | — | ||||||||||||||||
Conemaugh Fuels, LLC | 21 | 21 | — | — | — | ||||||||||||||||
CENG | 1,925 | 1,925 | — | — | — | ||||||||||||||||
Safe Harbor | 285 | 285 | — | — | — | ||||||||||||||||
Malacha | 8 | 8 | — | — | — | ||||||||||||||||
Other equity method investments | 2 | 2 | — | — | — | ||||||||||||||||
Total equity method investments | 2,295 | 2,273 | 6 | 8 | 8 | ||||||||||||||||
Other investments: | |||||||||||||||||||||
Net investment in leases | 705 | 7 | — | — | — | ||||||||||||||||
Employee benefit trusts and investments (b) | 90 | 23 | 5 | 23 | 5 | ||||||||||||||||
Other investments (c) | 22 | 22 | — | — | — | ||||||||||||||||
Total investments | $ | 3,112 | $ | 2,325 | $ | 11 | $ | 31 | $ | 13 | |||||||||||
_________________________ | |||||||||||||||||||||
(a) | Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments 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. | ||||||||||||||||||||
(c) | Includes cost method and available-for-sale investments. | ||||||||||||||||||||
Accrued Liabilities Current | The following tables provide additional information about liabilities of the Registrants at December 31, 2014 and 2013. | ||||||||||||||||||||
31-Dec-14 | Exelon | Generation | ComEd | PECO | BGE | ||||||||||||||||
Accrued expenses | |||||||||||||||||||||
Compensation-related accruals (a) | $ | 832 | $ | 447 | $ | 153 | $ | 50 | $ | 58 | |||||||||||
Taxes accrued | 305 | 248 | 59 | 3 | 42 | ||||||||||||||||
Interest accrued | 240 | 66 | 102 | 33 | 29 | ||||||||||||||||
Severance accrued | 49 | 33 | 2 | 1 | 2 | ||||||||||||||||
Other accrued expenses | 113 | (b) | 92 | (b) | 15 | 4 | — | ||||||||||||||
Total accrued expenses | $ | 1,539 | $ | 886 | $ | 331 | $ | 91 | $ | 131 | |||||||||||
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 | |||||||||||
_______________________ | |||||||||||||||||||||
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. | ||||||||||||||||||||
(b) | Includes $19 million and $228 million for amounts accrued related to Antelope Valley as of December 31, 2014 and December 31, 2013, respectively. |
Segment_Information_Tables
Segment Information (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||||||||||||||||||||||
Analysis and reconciliation of reportable segment information | 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, 2014, 2013, and 2012 is as follows: | |||||||||||||||||||||||||||||||||||
Generation (a) | ComEd | PECO | BGE (b) | Other (c) | Intersegment | Exelon | ||||||||||||||||||||||||||||||
Eliminations | ||||||||||||||||||||||||||||||||||||
Operating revenues(d): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 17,393 | $ | 4,564 | 3,094 | $ | 3,165 | $ | 1,285 | $ | (2,072 | ) | $ | 27,429 | ||||||||||||||||||||||
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 | ||||||||||||||||||||||||||||
Intersegment revenues(e): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 762 | $ | 4 | $ | 2 | $ | 25 | $ | 1,280 | $ | (2,067 | ) | $ | 6 | |||||||||||||||||||||
2013 | 1,367 | 3 | 1 | 13 | 1,237 | (2,607 | ) | 14 | ||||||||||||||||||||||||||||
2012 | 1,660 | 2 | 3 | 9 | 1,381 | (3,049 | ) | 6 | ||||||||||||||||||||||||||||
Depreciation and amortization | ||||||||||||||||||||||||||||||||||||
2014 | $ | 967 | $ | 687 | $ | 236 | $ | 371 | $ | 53 | $ | — | $ | 2,314 | ||||||||||||||||||||||
2013 | 856 | 669 | 228 | 348 | 52 | — | 2,153 | |||||||||||||||||||||||||||||
2012 | 768 | 610 | 217 | 238 | 48 | — | 1,881 | |||||||||||||||||||||||||||||
Operating expenses (d): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 16,923 | $ | 3,586 | $ | 2,522 | $ | 2,726 | $ | 1,353 | $ | (2,071 | ) | $ | 25,039 | |||||||||||||||||||||
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 | ||||||||||||||||||||||||||||
Equity in earnings (losses) of | ||||||||||||||||||||||||||||||||||||
unconsolidated affiliates | ||||||||||||||||||||||||||||||||||||
2014 | $ | (20 | ) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (20 | ) | ||||||||||||||||||||
2013 | 10 | — | — | — | — | — | 10 | |||||||||||||||||||||||||||||
2012 | (91 | ) | — | — | — | — | — | (91 | ) | |||||||||||||||||||||||||||
Interest expense, net: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 356 | $ | 321 | $ | 113 | $ | 106 | $ | 169 | $ | — | $ | 1,065 | ||||||||||||||||||||||
2013 | 357 | 579 | 115 | 122 | 183 | — | 1,356 | |||||||||||||||||||||||||||||
2012 | 301 | 307 | 123 | 111 | 86 | — | 928 | |||||||||||||||||||||||||||||
Income (loss) before income | ||||||||||||||||||||||||||||||||||||
taxes: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 1,226 | $ | 676 | $ | 466 | $ | 351 | $ | (227 | ) | $ | (6 | ) | $ | 2,486 | ||||||||||||||||||||
2013 | 1,675 | 401 | 557 | 344 | (191 | ) | (13 | ) | 2,773 | |||||||||||||||||||||||||||
2012 | 1,058 | 618 | 508 | (54 | ) | (325 | ) | (7 | ) | 1,798 | ||||||||||||||||||||||||||
Income taxes: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 207 | $ | 268 | $ | 114 | $ | 140 | $ | (63 | ) | $ | — | $ | 666 | |||||||||||||||||||||
2013 | 615 | 152 | 162 | 134 | (20 | ) | 1 | 1,044 | ||||||||||||||||||||||||||||
2012 | 500 | 239 | 127 | (23 | ) | (215 | ) | (1 | ) | 627 | ||||||||||||||||||||||||||
Net income (loss): | ||||||||||||||||||||||||||||||||||||
2014 | $ | 1,019 | $ | 408 | $ | 352 | $ | 211 | $ | (164 | ) | $ | (6 | ) | $ | 1,820 | ||||||||||||||||||||
2013 | 1,060 | 249 | 395 | 210 | (171 | ) | (14 | ) | 1,729 | |||||||||||||||||||||||||||
2012 | 558 | 379 | 381 | (31 | ) | (110 | ) | (6 | ) | 1,171 | ||||||||||||||||||||||||||
Capital expenditures: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 3,012 | $ | 1,689 | $ | 661 | $ | 620 | $ | 95 | $ | — | 6,077 | |||||||||||||||||||||||
2013 | 2,752 | 1,433 | 537 | 587 | 86 | — | 5,395 | |||||||||||||||||||||||||||||
2012 | 3,554 | 1,246 | 422 | 500 | 67 | — | 5,789 | |||||||||||||||||||||||||||||
Total assets: | ||||||||||||||||||||||||||||||||||||
2014 | $ | 45,348 | $ | 25,392 | $ | 9,943 | $ | 8,078 | $ | 9,794 | $ | (11,741 | ) | $ | 86,814 | |||||||||||||||||||||
2013 | 41,232 | 24,118 | 9,617 | 7,861 | 8,317 | (11,221 | ) | 79,924 | ||||||||||||||||||||||||||||
__________________________ | ||||||||||||||||||||||||||||||||||||
(a) | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million 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, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million 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. | |||||||||||||||||||||||||||||||||||
(b) | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014. | |||||||||||||||||||||||||||||||||||
(c) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. | |||||||||||||||||||||||||||||||||||
(d) | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $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 and Comprehensive Income. | |||||||||||||||||||||||||||||||||||
Analysis and reconciliation of reportable segment revenues for Generation | As of April 1, 2014, Generation total revenues and Generation total revenues net of purchased power and fuel expense includes 100% of the activity from CENG. | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
Revenues | Intersegment | Total | Revenues | Intersegment | Total | Revenues | Intersegment | Total | ||||||||||||||||||||||||||||
from | revenues | Revenues | from | revenues | Revenues | from | revenues | Revenues | ||||||||||||||||||||||||||||
external | external | external | ||||||||||||||||||||||||||||||||||
customers (a) | customers (a) | customers (a) | ||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 5,265 | $ | (6 | ) | $ | 5,259 | $ | 5,182 | $ | 22 | $ | 5,204 | $ | 5,082 | $ | (44 | ) | $ | 5,038 | ||||||||||||||||
Midwest | 4,467 | 8 | 4,475 | 4,280 | (10 | ) | 4,270 | 4,824 | 24 | 4,848 | ||||||||||||||||||||||||||
New England | 1,417 | 5 | 1,422 | 1,245 | (8 | ) | 1,237 | 1,048 | 45 | 1,093 | ||||||||||||||||||||||||||
New York | 843 | — | 843 | 735 | (21 | ) | 714 | 582 | (25 | ) | 557 | |||||||||||||||||||||||||
ERCOT | 938 | (3 | ) | 935 | 1,222 | (6 | ) | 1,216 | 1,365 | 2 | 1,367 | |||||||||||||||||||||||||
Other Regions (b) | 1,319 | (10 | ) | 1,309 | 946 | 22 | 968 | 755 | 78 | 833 | ||||||||||||||||||||||||||
Total Revenues | $ | 14,249 | $ | (6 | ) | $ | 14,243 | $ | 13,610 | $ | (1 | ) | $ | 13,609 | $ | 13,656 | $ | 80 | $ | 13,736 | ||||||||||||||||
for Reportable Segments | ||||||||||||||||||||||||||||||||||||
Other (c) | 3,144 | 6 | 3,150 | 2,020 | 1 | 2,021 | 781 | (80 | ) | 701 | ||||||||||||||||||||||||||
Total | $ | 17,393 | $ | — | $ | 17,393 | $ | 15,630 | $ | — | $ | 15,630 | $ | 14,437 | $ | — | $ | 14,437 | ||||||||||||||||||
Generation Consolidated Operating Revenues | ||||||||||||||||||||||||||||||||||||
_______________________ | ||||||||||||||||||||||||||||||||||||
(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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||||||||||||||||||||||||
Reconciliation of revenues from segments to consolidated | Generation total revenues net of purchased power and fuel expense: | |||||||||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||||||||||
RNF from | Intersegment | Total | RNF from | Intersegment | Total | RNF from | Intersegment | Total | ||||||||||||||||||||||||||||
external | RNF | RNF | external | RNF | RNF | external | RNF | RNF | ||||||||||||||||||||||||||||
customers (a) | customers (a) | customers (a) | ||||||||||||||||||||||||||||||||||
Mid-Atlantic | $ | 3,466 | $ | (49 | ) | $ | 3,417 | $ | 3,273 | $ | (3 | ) | $ | 3,270 | $ | 3,477 | $ | (44 | ) | $ | 3,433 | |||||||||||||||
Midwest | 2,580 | 14 | 2,594 | 2,585 | 1 | 2,586 | 2,974 | 24 | 2,998 | |||||||||||||||||||||||||||
New England | 432 | (81 | ) | 351 | 217 | (32 | ) | 185 | 151 | 45 | 196 | |||||||||||||||||||||||||
New York | 457 | 26 | 483 | 14 | (18 | ) | (4 | ) | 101 | (25 | ) | 76 | ||||||||||||||||||||||||
ERCOT | 573 | (256 | ) | 317 | 604 | (168 | ) | 436 | 403 | 2 | 405 | |||||||||||||||||||||||||
Other Regions (b) | 611 | (284 | ) | 327 | 334 | (133 | ) | 201 | 53 | 78 | 131 | |||||||||||||||||||||||||
Total Revenues net of | $ | 8,119 | $ | (630 | ) | $ | 7,489 | $ | 7,027 | $ | (353 | ) | $ | 6,674 | $ | 7,159 | $ | 80 | $ | 7,239 | ||||||||||||||||
purchased power and fuel expense for Reportable Segments | ||||||||||||||||||||||||||||||||||||
Other (c) | (651 | ) | 630 | (21 | ) | 406 | 353 | 759 | 217 | (80 | ) | 137 | ||||||||||||||||||||||||
Total Generation | $ | 7,468 | $ | — | $ | 7,468 | $ | 7,433 | $ | — | $ | 7,433 | $ | 7,376 | $ | — | $ | 7,376 | ||||||||||||||||||
Revenues net of purchased power and fuel expense | ||||||||||||||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||||||
(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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense. |
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Related Party Transactions [Abstract] | ||||||||||||
Related Party Transactions Income Statement Disclosure | The financial statements of PECO include related party transactions as presented in the tables below: | |||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
Generation (a) | $ | 2 | $ | 1 | $ | 3 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (b) | $ | 194 | $ | 392 | $ | 533 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
BSC (c) | $ | 96 | $ | 98 | $ | 107 | ||||||
Generation | 3 | 3 | 4 | |||||||||
Total operating and maintenance from affiliates | $ | 99 | $ | 101 | $ | 111 | ||||||
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 | ||||||
Capitalized costs | ||||||||||||
BSC (c) | $ | 39 | $ | 46 | $ | 54 | ||||||
Cash dividends paid to parent | $ | 320 | $ | 332 | $ | 343 | ||||||
Contribution from parent | $ | 24 | $ | 27 | $ | 9 | ||||||
The financial statements of Generation include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
ComEd (a) | $ | 176 | $ | 506 | $ | 795 | ||||||
PECO (b) | 198 | 405 | 543 | |||||||||
BGE (c) | 387 | 455 | 322 | |||||||||
CENG (d) | 17 | 56 | 42 | |||||||||
BSC | 1 | 1 | — | |||||||||
Total operating revenues from affiliates | $ | 779 | $ | 1,423 | $ | 1,702 | ||||||
Purchase power and fuel from affiliates: | ||||||||||||
ComEd | $ | 1 | $ | 1 | $ | — | ||||||
BGE | 25 | 13 | 8 | |||||||||
CENG (e) | 282 | 992 | 793 | |||||||||
Keystone Fuels, LLC (i) | 138 | 144 | 119 | |||||||||
Conemaugh Fuels, LLC (i) | 99 | 98 | 101 | |||||||||
Safe Harbor Water Power Corporation (i) | 12 | 22 | 23 | |||||||||
Total purchase power and fuel from affiliates | $ | 557 | $ | 1,270 | $ | 1,044 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
ComEd (f) | $ | 3 | $ | 2 | $ | 2 | ||||||
PECO (f) | 2 | 1 | 3 | |||||||||
BSC (g) | 618 | 571 | 625 | |||||||||
Total operating and maintenance from affiliates | $ | 623 | $ | 574 | $ | 630 | ||||||
Interest expense to affiliates, net: | ||||||||||||
Exelon Corporate | $ | 53 | $ | 59 | $ | 75 | ||||||
Earnings (losses) in equity method investments | ||||||||||||
CENG (h) | $ | (19 | ) | $ | 9 | $ | (99 | ) | ||||
Qualifying facilities and domestic power projects | (1 | ) | 1 | 8 | ||||||||
Total earnings (losses) in equity method investments | $ | (20 | ) | $ | 10 | $ | (91 | ) | ||||
Capitalized costs | ||||||||||||
BSC (g) | $ | 91 | $ | 93 | $ | 80 | ||||||
Cash distribution paid to member | $ | 645 | $ | 625 | $ | 1,626 | ||||||
Contribution from member | $ | 53 | $ | 26 | $ | 48 | ||||||
The financial statements of BGE include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
Generation (a) | $ | 25 | $ | 13 | $ | 10 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (b) | $ | 382 | $ | 452 | $ | 396 | ||||||
Operating and maintenance from affiliates: | ||||||||||||
BSC (c) | $ | 103 | $ | 83 | $ | 106 | ||||||
Interest expense to affiliates, net: | ||||||||||||
BGE Capital Trust II | $ | 16 | $ | 16 | $ | 16 | ||||||
Capitalized costs | ||||||||||||
BSC (c) | $ | 19 | $ | 15 | $ | 21 | ||||||
Contribution from parent | $ | — | $ | — | $ | 66 | ||||||
The financial statements of ComEd include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates | ||||||||||||
Generation | $ | 4 | $ | 3 | $ | 2 | ||||||
Purchased power from affiliate | ||||||||||||
Generation (a) | $ | 176 | $ | 512 | $ | 789 | ||||||
Operating and maintenance from affiliate | ||||||||||||
BSC (b) | $ | 166 | $ | 157 | $ | 163 | ||||||
Interest expense to affiliates, net: | ||||||||||||
ComEd Financing III | $ | 13 | $ | 13 | $ | 13 | ||||||
Capitalized costs | ||||||||||||
BSC (b) | $ | 77 | $ | 69 | $ | 92 | ||||||
Cash dividends paid to parent | $ | 307 | $ | 220 | $ | 105 | ||||||
Contribution from parent | $ | 273 | $ | — | $ | 11 | ||||||
The financial statements of Exelon include related party transactions as presented in the tables below: | ||||||||||||
For the Years Ended | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Operating revenues from affiliates: | ||||||||||||
PECO (a) | $ | 1 | $ | 10 | $ | 6 | ||||||
CENG (b) | 17 | 56 | 42 | |||||||||
BGE (a) | 5 | 4 | — | |||||||||
Total operating revenues from affiliates | $ | 23 | $ | 70 | $ | 48 | ||||||
Purchase power and fuel from affiliates: | ||||||||||||
CENG (c) | $ | 282 | $ | 992 | $ | 793 | ||||||
Keystone Fuels, LLC (d) | 138 | 144 | 119 | |||||||||
Conemaugh Fuels, LLC (d) | 99 | 98 | 101 | |||||||||
Safe Harbor Water Power Corp (d) | 12 | 22 | 23 | |||||||||
Total purchase power and fuel from affiliates | $ | 531 | $ | 1,256 | $ | 1,036 | ||||||
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 | 16 | 12 | |||||||||
Total interest expense to affiliates, net | $ | 41 | $ | 41 | $ | 37 | ||||||
Earnings (losses) in equity method investments: | ||||||||||||
CENG (e) | $ | (19 | ) | $ | 9 | $ | (99 | ) | ||||
Qualifying facilities and domestic power projects | (1 | ) | 1 | 8 | ||||||||
Total earnings (losses) in equity method investments | $ | (20 | ) | $ | 10 | $ | (91 | ) | ||||
Related Party Transactions Balance Sheet Disclosure | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (c) | $ | 13 | $ | 13 | ||||||||
Receivable from affiliates (current): | ||||||||||||
Voluntary employee beneficiary association trust | $ | 2 | $ | 3 | ||||||||
Generation | 12 | — | ||||||||||
Total receivable from affiliates (current) | $ | 14 | $ | 3 | ||||||||
Receivable from affiliates (noncurrent): | ||||||||||||
Generation (d) | $ | 2,389 | $ | 2,293 | ||||||||
Exelon Corporate (e) | 182 | 176 | ||||||||||
Total receivable from affiliates (noncurrent) | $ | 2,571 | $ | 2,469 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (a) | $ | 43 | $ | 38 | ||||||||
BSC (b) | 32 | 30 | ||||||||||
ComEd Financing III | 4 | 4 | ||||||||||
PECO | 2 | — | ||||||||||
Exelon Corporate | 3 | 9 | ||||||||||
Other | — | 2 | ||||||||||
Total payables to affiliates (current) | $ | 84 | $ | 83 | ||||||||
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, which expired in 2013. 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 Registrants. 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) | Represents indemnification from Exelon Corporate related to the like-kind exchange transaction. | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Receivables from affiliates (current): | ||||||||||||
CENG (d) | $ | — | $ | 3 | ||||||||
ComEd (a) | 43 | 38 | ||||||||||
PECO (b) | 29 | 38 | ||||||||||
BGE (c) | 40 | 27 | ||||||||||
Other | 1 | 2 | ||||||||||
Total receivables from affiliates (current) | $ | 113 | $ | 108 | ||||||||
Long-term debt due to affiliates (current): | ||||||||||||
Exelon Corporate (l) | 556 | — | ||||||||||
Payables to affiliates (current): | ||||||||||||
CENG (e) | $ | — | $ | 85 | ||||||||
Exelon Corporate (j) | 12 | 7 | ||||||||||
BSC (g) | 83 | 66 | ||||||||||
ComEd | 12 | — | ||||||||||
Keystone Fuels, LLC (i) | — | 12 | ||||||||||
Conemaugh Fuels, LLC (i) | — | 9 | ||||||||||
Other | — | 2 | ||||||||||
Total payables to affiliates (current) | $ | 107 | $ | 181 | ||||||||
Long-term debt due to affiliates (noncurrent): | ||||||||||||
Exelon Corporate (l) | 943 | 1,523 | ||||||||||
Payables to affiliates (noncurrent): | ||||||||||||
BSC (g) | $ | 1 | $ | — | ||||||||
ComEd (k) | 2,389 | 2,293 | ||||||||||
PECO (k) | 490 | 447 | ||||||||||
Total payables to affiliates (noncurrent) | $ | 2,880 | $ | 2,740 | ||||||||
_______________________ | ||||||||||||
(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) | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. 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. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. 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) | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(i) | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | |||||||||||
(j) | The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation. | |||||||||||
(k) | 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. | |||||||||||
(l) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 1 | $ | 1 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (b) | $ | 40 | $ | 27 | ||||||||
BSC (c) | 17 | 20 | ||||||||||
Exelon Corporate | 5 | 1 | ||||||||||
PECO | 1 | 3 | ||||||||||
BGE Capital Trust II | 3 | 4 | ||||||||||
Total payables to affiliates (current) | $ | 66 | $ | 55 | ||||||||
Long-term debt to BGE financing trust | ||||||||||||
BGE Capital Trust II | $ | 258 | $ | 258 | ||||||||
______________________ | ||||||||||||
(a) | BGE provides energy to Generation for Generation’s own use. | |||||||||||
(b) | 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. | |||||||||||
(c) | 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. | |||||||||||
(d) | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’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. | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Receivables from affiliates (current): | ||||||||||||
CENG (b) | $ | — | $ | 3 | ||||||||
Payables to affiliates (current): | ||||||||||||
CENG (c) | $ | — | $ | 85 | ||||||||
ComEd Financing III | 4 | 4 | ||||||||||
PECO Trust III | 1 | 1 | ||||||||||
BGE Capital Trust II | 3 | 4 | ||||||||||
Keystone Fuels, LLC (d) | — | 12 | ||||||||||
Conemaugh Fuels, LLC (d) | — | 9 | ||||||||||
Other | — | 1 | ||||||||||
Total payables to affiliates (current) | $ | 8 | $ | 116 | ||||||||
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 | ||||||||
____________________________ | ||||||||||||
(a) | The intersegment profit associated with the 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 Statement of Operations. See Note 3—Regulatory Matters for additional information. | |||||||||||
(b) | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(c) | CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(d) | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | |||||||||||
(e) | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||
(f) | The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Prepaid voluntary employee beneficiary association trust (d) | $ | 3 | $ | 3 | ||||||||
Receivable from affiliate (current): | ||||||||||||
ComEd | $ | 2 | $ | — | ||||||||
BGE | 1 | 3 | ||||||||||
Total receivable from affiliates (current) | $ | 3 | $ | 3 | ||||||||
Receivable from affiliate (noncurrent): | ||||||||||||
Generation (e) | $ | 490 | $ | 447 | ||||||||
Payables to affiliates (current): | ||||||||||||
Generation (b) | $ | 29 | $ | 38 | ||||||||
BSC (c) | 20 | 17 | ||||||||||
Exelon Corporate | 2 | 2 | ||||||||||
PECO Trust III | 1 | 1 | ||||||||||
Total payables to affiliates (current) | $ | 52 | $ | 58 | ||||||||
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 Registrants. 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. |
Quarterly_Data_Unaudited_Table
Quarterly Data (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information | 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: | |||||||||||||||||||||||||||||||
Operating Revenues | Operating Income | Net (Loss) Income | ||||||||||||||||||||||||||||||
on Common | ||||||||||||||||||||||||||||||||
Stock | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 7,237 | $ | 6,082 | $ | 168 | (a) | $ | 513 | (b) | $ | 90 | $ | (4 | ) | (c) | ||||||||||||||||
30-Jun | 6,024 | 6,141 | 842 | (a) | 1,005 | 522 | 490 | |||||||||||||||||||||||||
30-Sep | 6,912 | 6,502 | 1,739 | (a) | 1,262 | (b) | 993 | 738 | ||||||||||||||||||||||||
31-Dec | 7,255 | 6,163 | 348 | 889 | 18 | (d) | 495 | |||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock. | |||||||||||||||||||||||||||||||
(b) | In the first and third quarter of 2013, Exelon reclassified $5 million and $8 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock. | |||||||||||||||||||||||||||||||
(c) | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||||||||||||||||||
(d) | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||||||||||||||||||
Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share | ||||||||||||||||||||||||||||||||
Average Basic Shares | Net (Loss) Income | |||||||||||||||||||||||||||||||
Outstanding | per Basic Share | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | 858 | 855 | $ | 0.1 | $ | (0.01 | ) | |||||||||||||||||||||||||
30-Jun | 860 | 856 | 0.61 | 0.57 | ||||||||||||||||||||||||||||
30-Sep | 861 | 857 | 1.15 | 0.86 | ||||||||||||||||||||||||||||
31-Dec | 861 | 856 | 0.02 | 0.6 | ||||||||||||||||||||||||||||
Average Diluted Shares | Net (Loss) Income | |||||||||||||||||||||||||||||||
Outstanding | per Diluted Share | |||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | 861 | 855 | $ | 0.1 | $ | (0.01 | ) | |||||||||||||||||||||||||
30-Jun | 864 | 860 | 0.6 | 0.57 | ||||||||||||||||||||||||||||
30-Sep | 863 | 860 | 1.15 | 0.86 | ||||||||||||||||||||||||||||
31-Dec | 868 | 860 | 0.02 | 0.59 | ||||||||||||||||||||||||||||
Per Share Information | The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis: | |||||||||||||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||||||||||||||
Fourth | Third | Second | First | Fourth | Third | Second | First | |||||||||||||||||||||||||
Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | |||||||||||||||||||||||||
High price | $ | 38.93 | $ | 36.26 | $ | 37.73 | $ | 33.94 | $ | 30.59 | $ | 32.42 | $ | 37.8 | $ | 34.56 | ||||||||||||||||
Low price | 33.07 | 30.66 | 33.11 | 26.45 | 26.64 | 29.42 | 29.84 | 29.1 | ||||||||||||||||||||||||
Close | 37.08 | 34.09 | 36.48 | 33.56 | 27.39 | 29.64 | 30.88 | 34.48 | ||||||||||||||||||||||||
Dividends | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.31 | 0.525 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information | The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts: | |||||||||||||||||||||||||||||||
Operating Revenues | Operating (Loss) Income | Net (Loss) Income | ||||||||||||||||||||||||||||||
on Membership | ||||||||||||||||||||||||||||||||
Interest | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 (a) | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 4,390 | $ | 3,533 | $ | (384 | ) | (a) | $ | (59 | ) | (b) | $ | (185 | ) | $ | (18 | ) | ||||||||||||||
30-Jun | 3,789 | 4,070 | 441 | (a) | 603 | 340 | 330 | |||||||||||||||||||||||||
30-Sep | 4,412 | 4,255 | 1,225 | (a) | 729 | (b) | 771 | 490 | ||||||||||||||||||||||||
31-Dec | 4,802 | 3,772 | (105 | ) | 405 | (91 | ) | 269 | ||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest. | |||||||||||||||||||||||||||||||
(b) | In the first and third quarter of 2013, Generation reclassified $5 million and $8 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest. | |||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information | 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 | ||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 1,134 | $ | 1,160 | $ | 238 | $ | 209 | $ | 98 | $ | (81 | ) | |||||||||||||||||||
30-Jun | 1,128 | 1,080 | 259 | (a) | 232 | 111 | 96 | |||||||||||||||||||||||||
30-Sep | 1,222 | 1,156 | 288 | (a) | 278 | 126 | 126 | |||||||||||||||||||||||||
31-Dec | 1,079 | 1,068 | 196 | 236 | 73 | 109 | ||||||||||||||||||||||||||
____________________________ | ||||||||||||||||||||||||||||||||
(a) | In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income. | |||||||||||||||||||||||||||||||
PECO Energy Co [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information | The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts: | |||||||||||||||||||||||||||||||
Operating Revenues | Operating Income | Net Income | ||||||||||||||||||||||||||||||
on Common | ||||||||||||||||||||||||||||||||
Stock | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 993 | $ | 895 | $ | 149 | $ | 203 | $ | 89 | $ | 121 | ||||||||||||||||||||
30-Jun | 656 | 672 | 134 | 138 | 84 | 72 | ||||||||||||||||||||||||||
30-Sep | 693 | 728 | 133 | 155 | 81 | 92 | ||||||||||||||||||||||||||
31-Dec | 750 | 805 | 156 | 168 | 98 | 102 | ||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||||||||||||||||||||||
Quarterly Financial Data [Line Items] | ||||||||||||||||||||||||||||||||
Quarterly Financial Information | The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts: | |||||||||||||||||||||||||||||||
Operating Revenues | Operating | Net Income | ||||||||||||||||||||||||||||||
Income | attributable to | |||||||||||||||||||||||||||||||
Common Shareholders | ||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||
Quarter ended: | ||||||||||||||||||||||||||||||||
31-Mar | $ | 1,054 | $ | 880 | $ | 169 | $ | 163 | $ | 85 | $ | 77 | ||||||||||||||||||||
30-Jun | 653 | 653 | 55 | 69 | 16 | 22 | ||||||||||||||||||||||||||
30-Sep | 697 | 737 | 102 | 114 | 46 | 50 | ||||||||||||||||||||||||||
31-Dec | 761 | 794 | 113 | 101 | 52 | 47 | ||||||||||||||||||||||||||
Significant_Accounting_Policie3
Significant Accounting Policies - Narrative (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Percentage ownership of consolidated subsidiaries | 100.00% | ||
Percentage ownership of common stock | 100.00% | ||
Third Party interest in ComEd (less than $1 million) | $1,332,000,000 | $15,000,000 | |
Minimum expectation of tax position to be realized | 50.00% | ||
Commonwealth Edison Company [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Percentage ownership of consolidated subsidiaries | 99.00% | ||
Third Party interest in ComEd (less than $1 million) | 1,000,000 | 1,000,000 | |
CENG [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Ownership interest | 50.01% | ||
RITELine Illinois LLC [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Third Party interest in ComEd (less than $1 million) | 1,000,000 | 1,000,000 | |
Minority interest ownership percentage by parent | 12.50% | ||
Exelon Generation Co L L C [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Third Party interest in ComEd (less than $1 million) | 1,333,000,000 | 17,000,000 | |
Ownership interest upper bound | 99.00% | ||
Ownership interest | 50.01% | ||
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | -0.001 | ||
Development costs expensed | $13,000,000 | $10,000,000 | $4,000,000 |
Commonwealth Edison Co [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Percentage ownership of consolidated subsidiaries | 100.00% | ||
Commonwealth Edison Co [Member] | RITELine Illinois LLC [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Percentage ownership of consolidated subsidiaries | 75.00% | ||
Third-party percentage interest in subsidiaries | 25.00% | ||
Minimum [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Ownership interest | 20.00% | ||
Maximum [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Ownership interest | 50.00% | ||
Nuclear-Fuel Generating Facilities License Extension [Member] | Exelon Generation Co L L C [Member] | |||
Significant Accounting Policies Additional Narrative Information [Line Items] | |||
Useful life | 20 years |
Significant_Accounting_Policie4
Significant Accounting Policies - Summary of Capitalized Software Costs (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Capitalized Software [Line Items] | ||||||
Net unamortized software costs | $596 | [1] | $479 | [1] | ||
Amortization of capitalized software costs | 186 | [1],[2] | 198 | [1],[2] | 208 | [1],[2] |
Exelon Generation Co L L C [Member] | ||||||
Capitalized Software [Line Items] | ||||||
Net unamortized software costs | 193 | [1] | 129 | [1] | ||
Amortization of capitalized software costs | 59 | [1],[2] | 67 | [1],[2] | 81 | [1],[2] |
Commonwealth Edison Co [Member] | ||||||
Capitalized Software [Line Items] | ||||||
Net unamortized software costs | 133 | 101 | ||||
Amortization of capitalized software costs | 45 | 52 | 56 | |||
PECO Energy Co [Member] | ||||||
Capitalized Software [Line Items] | ||||||
Net unamortized software costs | 84 | 71 | ||||
Amortization of capitalized software costs | 28 | 33 | 30 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Capitalized Software [Line Items] | ||||||
Net unamortized software costs | 163 | 155 | ||||
Amortization of capitalized software costs | $43 | [2] | $36 | [2] | $32 | [2] |
[1] | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | |||||
[2] | 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 year ended December 31, 2012. |
Significant_Accounting_Policie5
Significant Accounting Policies - Summary of Total Interest Incurred, Capitalized and Credits to AFUDC (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Capitalized Interest And AFUDC [Line Items] | ||||||
Total interest incurred | $1,144 | [1],[2],[3] | $1,423 | [1],[2],[3] | $1,003 | [1],[2],[3] |
Capitalized interest | 63 | [1],[2] | 54 | [1],[2] | 67 | [1],[2] |
Credits to AFUDC debt and equity | 37 | [1],[2] | 35 | [1],[2] | 25 | [1],[2] |
Exelon Generation Co L L C [Member] | ||||||
Capitalized Interest And AFUDC [Line Items] | ||||||
Total interest incurred | 419 | [1],[2],[3] | 411 | [1],[2],[3] | 368 | [1],[2],[3] |
Capitalized interest | 63 | [1],[2] | 54 | [1],[2] | 67 | [1],[2] |
Credits to AFUDC debt and equity | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] |
Commonwealth Edison Co [Member] | ||||||
Capitalized Interest And AFUDC [Line Items] | ||||||
Total interest incurred | 323 | [3] | 584 | [3] | 310 | [3] |
Capitalized interest | 0 | 0 | 0 | |||
Credits to AFUDC debt and equity | 5 | 16 | 9 | |||
PECO Energy Co [Member] | ||||||
Capitalized Interest And AFUDC [Line Items] | ||||||
Total interest incurred | 115 | [3] | 117 | [3] | 125 | [3] |
Capitalized interest | 0 | 0 | 0 | |||
Credits to AFUDC debt and equity | 8 | 6 | 6 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Capitalized Interest And AFUDC [Line Items] | ||||||
Total interest incurred | 118 | [1],[3] | 129 | [1],[3] | 149 | [1],[3] |
Capitalized interest | 0 | [1] | 0 | [1] | 0 | [1] |
Credits to AFUDC debt and equity | $24 | [1] | $13 | [1] | $15 | [1] |
[1] | 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 year ended December 31, 2012. | |||||
[2] | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | |||||
[3] | Includes interest expense to affiliates. |
Variable_Interest_Entities_Nar
Variable Interest Entities - Narrative (Details) (USD $) | 12 Months Ended | 0 Months Ended | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Apr. 01, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
VIE | ||||
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract] | ||||
Number of variable interest entities not consolidated by equity holders | 6 | 8 | ||
Number of variable interest entities consolidated | 6 | 4 | ||
Consolidated Variable Interest Entity [Abstract] | ||||
Parental guarantee provided | $75 | |||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | |||
Purchase of nuclear output by EDF | 49.99% | |||
Guarantee obligations maximum exposure | 9,402 | |||
Other Severance Charges [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Severance charges recorded | 6 | |||
Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Guarantee obligations maximum exposure | 165 | |||
Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Due to affiliate | 245 | |||
Exelon Generation Co L L C [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Parental guarantee provided | 5 | |||
Ownership Percentage Of Consolidated Variable Interest Entities | 100.00% | |||
Debt and Capital Lease Obligations | 7,652 | 7,168 | ||
Wind project entities with noncontrolling equity interests | 9 | |||
Noncontrolling equity interest ownership percentage held by third parties | 1.00% | |||
Number of projects with significant economic power | 8 | |||
Ownership interests in project entities | 99.00% | |||
Ownership interest | 50.01% | |||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | 85.00% | ||
Severance charges recorded | 3 | |||
Purchase of nuclear output by EDF | 49.99% | |||
Guarantee obligations maximum exposure | 6,384 | |||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Due from affiliates | 400 | 400 | ||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Due to affiliate | 205 | |||
Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Business Acquisitions, Megawatts Acquired | 242 | |||
Ownership Percentage Of Consolidated Variable Interest Entities | 100.00% | |||
Debt and Capital Lease Obligations | 642 | |||
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Parental guarantee provided | 7 | 7 | ||
Remeasurement gain from derecognition of equity method investment | 261 | |||
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Equity Method Investment Variable Interest Entities [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Parental guarantee provided | 637 | |||
Baltimore Gas and Electric Company [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Debt and Capital Lease Obligations | 2,011 | |||
Guarantee obligations maximum exposure | 265 | |||
Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member] | ||||
Consolidated Variable Interest Entity [Abstract] | ||||
Remittance of payments received from customers for rate stabilization to BondCo. | $85 | $83 | $85 |
Variable_Interest_Entities_Car
Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Variable Interest Entity [Line Items] | ||||
Current assets | $1,271 | [1],[2] | $484 | [1] |
Noncurrent assets | 7,580 | [1],[2] | 1,905 | [1] |
Total assets | 8,851 | [1],[2] | 2,389 | [1] |
Current liabilities | 611 | [1],[2] | 566 | [1] |
Noncurrent liabilities | 2,730 | [1],[2] | 774 | [1] |
Total liabilities | 3,341 | [1],[2] | 1,340 | [1] |
Assets | 86,814 | [3] | 79,924 | [3] |
Liabilities | 62,681 | [3] | 56,984 | [3] |
Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Assets | 6,100 | |||
Liabilities | 2,100 | |||
Exelon Generation Co L L C [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Current assets | 1,242 | [2] | 446 | |
Noncurrent assets | 7,566 | [2] | 1,884 | |
Total assets | 8,808 | [2] | 2,330 | |
Current liabilities | 526 | [2] | 481 | |
Noncurrent liabilities | 2,600 | [2] | 562 | |
Total liabilities | 3,126 | [2] | 1,043 | |
Assets | 45,348 | [4] | 41,232 | [4] |
Liabilities | 31,297 | [4] | 28,490 | [4] |
Baltimore Gas and Electric Company [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Current assets | 21 | 28 | ||
Noncurrent assets | 3 | 3 | ||
Total assets | 24 | 31 | ||
Current liabilities | 77 | 74 | ||
Noncurrent liabilities | 120 | 195 | ||
Total liabilities | 197 | 269 | ||
Assets | 8,078 | [5] | 7,861 | [5] |
Liabilities | $5,325 | [5] | $5,306 | [5] |
[1] | Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. | |||
[2] | Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||
[3] | Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. | |||
[4] | Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities. | |||
[5] | BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities. |
Variable_Interest_Entities_Ass
Variable Interest Entities - Assets and Liabilities of VIEs which Creditors or Beneficiaries have No Recourse (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
In Millions, unless otherwise specified | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | $1,878 | $1,609 | $1,486 | $1,016 | ||
Customer | 3,482 | 2,981 | ||||
Other | 1,227 | 1,175 | ||||
Mark-to-market derivative assets | 1,279 | 727 | ||||
Materials and supplies | 1,024 | 829 | ||||
Other current assets | 865 | 652 | ||||
Total current assets | 12,097 | 10,137 | ||||
Property, plant and equipment, net | 52,087 | 47,330 | ||||
Nuclear decommissioning trust funds | 10,537 | 8,071 | ||||
Goodwill | 2,672 | 2,625 | ||||
Mark-to-market derivative assets | 773 | 607 | ||||
Other noncurrent assets | 1,160 | 964 | ||||
Total deferred debits and other assets | 22,630 | 22,457 | ||||
Total assets | 86,814 | [1] | 79,924 | [1] | ||
Long-term debt due within one year | 1,802 | 1,509 | ||||
Accounts payable | 3,048 | 2,484 | ||||
Accrued expenses | 1,539 | 1,633 | ||||
Mark-to-market derivative liabilities | 234 | 159 | ||||
Energy Marketing Contract Liabilities, Current | 238 | 261 | ||||
Other current liabilities | 1,123 | 858 | ||||
Total current liabilities | 8,762 | 7,728 | ||||
Long-term debt | 19,362 | 17,623 | ||||
Asset retirement obligations | 7,295 | 5,194 | ||||
Pension obligations | 3,366 | 1,876 | ||||
Energy Marketing Contract Liabilities, Noncurrent | 211 | 266 | ||||
Other noncurrent liabilities | 2,147 | 2,540 | ||||
Total deferred credits and other liabilities | 33,909 | 30,985 | ||||
Total liabilities | 62,681 | [1] | 56,984 | [1] | ||
Variable Interest Entity, Primary Beneficiary [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | 392 | 62 | ||||
Restricted cash | 117 | 80 | ||||
Customer | 297 | 260 | ||||
Other | 57 | 0 | ||||
Mark-to-market derivative assets | 171 | 21 | ||||
Materials and supplies | 172 | 0 | ||||
Other current assets | 33 | 34 | ||||
Total current assets | 1,239 | 457 | ||||
Property, plant and equipment, net | 4,638 | 1,171 | ||||
Nuclear decommissioning trust funds | 2,097 | 0 | ||||
Goodwill | 47 | 0 | ||||
Mark-to-market derivative assets | 44 | 0 | ||||
Other noncurrent assets | 95 | 127 | ||||
Total deferred debits and other assets | 6,921 | 1,298 | ||||
Total assets | 8,160 | 1,755 | ||||
Long-term debt due within one year | 87 | 85 | ||||
Accounts payable | 292 | 170 | ||||
Accrued expenses | 111 | 26 | ||||
Mark-to-market derivative liabilities | 24 | 29 | ||||
Energy Marketing Contract Liabilities, Current | 22 | 5 | ||||
Other current liabilities | 25 | 5 | ||||
Total current liabilities | 561 | 320 | ||||
Long-term debt | 212 | 298 | ||||
Asset retirement obligations | 1,763 | 0 | ||||
Pension obligations | 9 | [2] | 0 | [2] | ||
Energy Marketing Contract Liabilities, Noncurrent | 51 | 28 | ||||
Other noncurrent liabilities | 127 | 12 | ||||
Total deferred credits and other liabilities | 2,162 | 338 | ||||
Total liabilities | 2,723 | 658 | ||||
Exelon Generation Co L L C [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | 780 | 1,258 | 671 | 496 | ||
Restricted cash | 158 | 71 | ||||
Customer | 2,295 | 1,689 | ||||
Other | 318 | 353 | ||||
Mark-to-market derivative assets | 1,276 | 727 | ||||
Materials and supplies | 847 | 671 | ||||
Other current assets | 658 | 491 | ||||
Total current assets | 7,638 | 6,439 | ||||
Property, plant and equipment, net | 22,945 | 20,111 | ||||
Nuclear decommissioning trust funds | 10,537 | 8,071 | ||||
Goodwill | 47 | 0 | ||||
Mark-to-market derivative assets | 771 | 600 | ||||
Other noncurrent assets | 731 | 645 | ||||
Total deferred debits and other assets | 14,765 | 14,682 | ||||
Total assets | 45,348 | [3] | 41,232 | [3] | ||
Long-term debt due within one year | 58 | 561 | ||||
Accounts payable | 1,759 | 1,322 | ||||
Accrued expenses | 886 | 976 | ||||
Mark-to-market derivative liabilities | 214 | 142 | ||||
Energy Marketing Contract Liabilities, Current | 238 | 249 | ||||
Other current liabilities | 605 | 389 | ||||
Total current liabilities | 4,459 | 3,867 | ||||
Long-term debt | 6,709 | 5,645 | ||||
Asset retirement obligations | 7,146 | 5,047 | ||||
Energy Marketing Contract Liabilities, Noncurrent | 211 | 266 | ||||
Other noncurrent liabilities | 719 | 811 | ||||
Total deferred credits and other liabilities | 19,186 | 17,455 | ||||
Total liabilities | 31,297 | [3] | 28,490 | [3] | ||
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | 392 | 62 | ||||
Restricted cash | 96 | 52 | ||||
Customer | 297 | 260 | ||||
Other | 57 | 0 | ||||
Mark-to-market derivative assets | 171 | 21 | ||||
Materials and supplies | 172 | 0 | ||||
Other current assets | 26 | 23 | ||||
Total current assets | 1,211 | 418 | ||||
Property, plant and equipment, net | 4,638 | 1,171 | ||||
Nuclear decommissioning trust funds | 2,097 | 0 | ||||
Goodwill | 47 | 0 | ||||
Mark-to-market derivative assets | 44 | 0 | ||||
Other noncurrent assets | 82 | 106 | ||||
Total deferred debits and other assets | 6,908 | 1,277 | ||||
Total assets | 8,119 | 1,695 | ||||
Long-term debt due within one year | 5 | 5 | ||||
Accounts payable | 292 | 170 | ||||
Accrued expenses | 108 | 22 | ||||
Mark-to-market derivative liabilities | 24 | 29 | ||||
Energy Marketing Contract Liabilities, Current | 22 | |||||
Other current liabilities | 25 | 5 | ||||
Total current liabilities | 476 | 236 | ||||
Long-term debt | 81 | 86 | ||||
Asset retirement obligations | 1,763 | 0 | ||||
Pension obligations | 9 | [2] | 0 | [2] | ||
Energy Marketing Contract Liabilities, Noncurrent | 51 | 28 | ||||
Other noncurrent liabilities | 127 | 12 | ||||
Total deferred credits and other liabilities | 2,031 | 126 | ||||
Total liabilities | 2,507 | 362 | ||||
Baltimore Gas and Electric Company [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | 64 | 31 | 89 | 49 | ||
Customer | 390 | 480 | ||||
Other | 82 | 114 | ||||
Materials and supplies | 30 | 28 | ||||
Other current assets | 5 | 7 | ||||
Total current assets | 957 | 1,011 | ||||
Property, plant and equipment, net | 6,204 | 5,864 | ||||
Other noncurrent assets | 25 | 26 | ||||
Total deferred debits and other assets | 917 | 986 | ||||
Total assets | 8,078 | [4] | 7,861 | [4] | ||
Accounts payable | 215 | 270 | ||||
Accrued expenses | 131 | 111 | ||||
Other current liabilities | 51 | 35 | ||||
Total current liabilities | 846 | 827 | ||||
Long-term debt | 1,867 | 1,941 | ||||
Asset retirement obligations | 17 | 19 | ||||
Other noncurrent liabilities | 60 | 67 | ||||
Total deferred credits and other liabilities | 2,354 | 2,280 | ||||
Total liabilities | 5,325 | [4] | 5,306 | [4] | ||
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member] | ||||||
Variable Interest Entity [Line Items] | ||||||
Cash and cash equivalents | 0 | 0 | ||||
Restricted cash | 21 | 28 | ||||
Customer | 0 | 0 | ||||
Other | 0 | 0 | ||||
Mark-to-market derivative assets | 0 | 0 | ||||
Materials and supplies | 0 | 0 | ||||
Other current assets | 0 | 0 | ||||
Total current assets | 21 | 28 | ||||
Property, plant and equipment, net | 0 | 0 | ||||
Nuclear decommissioning trust funds | 0 | 0 | ||||
Goodwill | 0 | 0 | ||||
Mark-to-market derivative assets | 0 | 0 | ||||
Other noncurrent assets | 3 | 3 | ||||
Total deferred debits and other assets | 3 | 3 | ||||
Total assets | 24 | 31 | ||||
Long-term debt due within one year | 75 | 70 | ||||
Accounts payable | 0 | 0 | ||||
Accrued expenses | 2 | 4 | ||||
Mark-to-market derivative liabilities | 0 | 0 | ||||
Energy Marketing Contract Liabilities, Current | 0 | 0 | ||||
Other current liabilities | 0 | 0 | ||||
Total current liabilities | 77 | 74 | ||||
Long-term debt | 120 | 195 | ||||
Asset retirement obligations | 0 | 0 | ||||
Pension obligations | 0 | [2] | 0 | [2] | ||
Energy Marketing Contract Liabilities, Noncurrent | 0 | 0 | ||||
Other noncurrent liabilities | 0 | 0 | ||||
Total deferred credits and other liabilities | 120 | 195 | ||||
Total liabilities | $197 | $269 | ||||
[1] | Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. | |||||
[2] | Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details | |||||
[3] | Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities. | |||||
[4] | BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities. |
Variable_Interest_Entities_Sum
Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Variable Interest Entity [Line Items] | ||||
Total assets | $597 | [1] | $460 | [1] |
Total liabilities | 286 | [1] | 140 | [1] |
Our ownership interest | 9 | [1] | 86 | [1] |
Other ownership interests | 302 | [1] | 234 | [1] |
Pledged assets for Zion Station decommissioning | 319 | 458 | ||
Exelon Generation Co L L C [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Pledged assets for Zion Station decommissioning | 319 | 458 | ||
Payable To Thirdparty To Decommission Nuclear Plant Funded By Pledged Assets | 292 | [2] | 414 | [2] |
Commercial Agreement Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Total assets | 506 | [1] | 128 | [1] |
Total liabilities | 237 | [1] | 17 | [1] |
Our ownership interest | 0 | [1] | 0 | [1] |
Other ownership interests | 269 | [1] | 111 | [1] |
Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Total assets | 91 | [1] | 332 | [1] |
Total liabilities | 49 | [1] | 123 | [1] |
Our ownership interest | 9 | [1] | 86 | [1] |
Other ownership interests | 33 | [1] | 123 | [1] |
Investments [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 13 | 74 | ||
Investments [Member] | Commercial Agreement Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 0 | 7 | ||
Investments [Member] | Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 13 | 67 | ||
Contract Intangible Asset [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 9 | 9 | ||
Contract Intangible Asset [Member] | Commercial Agreement Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 9 | 9 | ||
Contract Intangible Asset [Member] | Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 0 | 0 | ||
Payment Guarantee [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 3 | 5 | ||
Payment Guarantee [Member] | Commercial Agreement Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 0 | 0 | ||
Payment Guarantee [Member] | Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 3 | 5 | ||
Asset Held In Trust Noncurrent [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 27 | [3] | 44 | [3] |
Asset Held In Trust Noncurrent [Member] | Commercial Agreement Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | 27 | [3] | 44 | [3] |
Asset Held In Trust Noncurrent [Member] | Equity Method Investment Variable Interest Entities [Member] | ||||
Variable Interest Entity [Line Items] | ||||
Our maximum exposure to loss | $0 | [3] | $0 | [3] |
[1] | 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. | |||
[2] | 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. | |||
[3] | 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 $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. |
Regulatory_Matters_Narrative_D
Regulatory Matters - Narrative (Details) (USD $) | 1 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 12 Months Ended | 60 Months Ended | 65 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | ||||||||||||||||||||||||||||||||||||||||
Jan. 31, 2014 | Sep. 30, 2008 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 11, 2014 | Apr. 16, 2014 | Dec. 19, 2013 | Jun. 30, 2013 | Apr. 29, 2013 | Dec. 19, 2012 | Jul. 31, 2012 | Apr. 30, 2014 | Apr. 30, 2013 | Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 02, 2013 | Mar. 29, 2013 | Mar. 15, 2013 | Dec. 05, 2012 | Aug. 09, 2011 | Sep. 30, 2012 | Dec. 08, 2014 | Oct. 17, 2014 | Aug. 23, 2014 | Dec. 13, 2013 | Feb. 27, 2013 | Feb. 22, 2013 | Aug. 31, 2010 | Dec. 31, 2007 | Nov. 30, 2010 | Nov. 30, 2005 | Apr. 12, 2012 | Mar. 31, 2011 | Dec. 31, 2014 | Jan. 13, 2015 | Mar. 31, 2013 | Sep. 18, 2014 | Apr. 01, 2014 | Mar. 31, 2014 | Oct. 31, 2013 | Apr. 01, 2013 | Dec. 20, 2012 | Jun. 02, 2011 | Aug. 15, 2013 | Jun. 19, 2013 | Dec. 16, 2010 | Jun. 01, 2009 | Sep. 15, 2014 | Aug. 21, 2014 | Jul. 02, 2014 | Apr. 28, 2014 | Apr. 27, 2014 | Feb. 26, 2014 | Aug. 23, 2013 | Feb. 28, 2010 | Jun. 03, 2014 | |
V | MW | V | MWh | smart_meter | smart_meter | |||||||||||||||||||||||||||||||||||||||||||||||||||||
mi | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue reduction | $8,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric revenues increase order | 274,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Substation kilovolt | 500,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Near zero emissions coal fueled generation plant | 166 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Parent company pension OPEB regulatory assets noncurrent | 3,256,000,000 | 3,256,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 6,076,000,000 | 5,910,000,000 | 6,076,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 310,000,000 | 327,000,000 | 310,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 19,000,000 | 28,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Efficiency Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 25,000,000 | 53,000,000 | 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 11,000,000 | 9,000,000 | 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 159,000,000 | 148,000,000 | 159,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-severance Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P5Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 6,000,000 | 9,000,000 | 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset recovery, period one | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory asset recovery, period two | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Generation Related Regulatory Asset [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 20,000,000 | 30,000,000 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 2,000,000 | 3,000,000 | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Severance Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P5Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory assets | 35,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under Recovered Distribution Service Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 120,000,000 | 285,000,000 | 120,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
AMI Expenses [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | ten | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 271,000,000 | 159,000,000 | 271,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 115,000,000 | 102,000,000 | 115,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional revenue requirement allowed by updated government order | 88,000,000 | 35,000,000 | 232,000,000 | 269,000,000 | 341,000,000 | 353,000,000 | 73,000,000 | 22,000,000 | 68,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||
Current year revenue adjustment | 160,000,000 | 160,000,000 | 36,000,000 | 38,000,000 | 80,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Prior year revenue adjustment | 72,000,000 | 14,000,000 | 30,000,000 | -181,000,000 | -7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average debt and equity return | 7.06% | 6.94% | 8.91% | 8.62% | 8.70% | 8.70% | 7.54% | |||||||||||||||||||||||||||||||||||||||||||||||||||
Rate of return on common equity | 9.25% | 8.72% | 9.81% | 11.50% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual revenue requirement reduction | 14,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Contribution to technology innovation trust | 15,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsequent contribution to technology innovation trust | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility annual customer assistance | 10,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart meters installed | 550,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate of return on common equity electric distribution | 10.30% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated refund obligation to customers | 37,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Collections under rider AMP | 24,000,000 | 24,000,000 | 9,500,000 | 14,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased accounts receivables for PORCB | 139,000,000 | 139,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of contract | 20 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual energy savings requirement | 0.20% | 0.20% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Demand response peak demand reduction | 2.00% | 2.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Low income sector consumption reduction targets Act 129 Phase II | 0.10% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable energy procurement | 2.00% | 2.00% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 852,000,000 | 933,000,000 | 852,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Common equity component cap | 55.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 125,000,000 | 170,000,000 | 125,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under over recovered distribution service costs | 377,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer refundable fees | 3,000,000 | 37,000,000 | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer refundable fees, interest | 1,000,000 | 1,000,000 | 1,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Under over recovered distribution service costs | 286,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost recovery for significant one-time events | 85,000,000 | 86,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable energy resources cumulatively increase | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Renewable energy resources cumulatively increase | 25.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 25,000,000 | 45,000,000 | 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Energy Related Derivative [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of contract | 20 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | FutureGen Industry Alliance [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term of contract | 20 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Northern Illinois Project [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Length of transmission line | 60 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Substation kilovolt | 345,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 7,000,000 | 6,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 7,000,000 | 6,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Deferred Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Transmission Rate Formula [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory assets | 21,000,000 | 17,000,000 | 21,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Severance Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory assets | 16,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 120,000,000 | 285,000,000 | 120,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets due to deferred storm costs | 66,000,000 | 58,000,000 | 66,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | AMI Expenses [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 81,000,000 | 35,000,000 | 81,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory asset | 371,000,000 | 463,000,000 | 371,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 73,000,000 | 67,000,000 | 73,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Transmission Costs Under-Recovery | 3,000,000 | 3,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company [Member] | Renewable Energy Program [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 16,000,000 | 9,000,000 | 16,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company [Member] | Under-Recovered Electric Supply Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Transmission Costs Under-Recovery | 4,000,000 | 35,000,000 | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 19,000,000 | 19,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison Company [Member] | Under Recovered Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 33,000,000 | 58,000,000 | 33,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric Transmission Costs Under-Recovery | 22,000,000 | 17,000,000 | 22,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Low income sector consumption reduction targets Act 129 Phase II | 4.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in electric delivery service revenue resulting from rate case settlement or order. | 225,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in gas delivery service revenue resulting from rate case settlement or order. | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Electric distribution tax repairs | 171,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gas distribution tax repairs refund | 54,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart meters initial phase deployment | 1,600,000 | 1,600,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated number of smart meters to be installed | 1,700,000 | 1,700,000 | 600,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected investment in smart meters | 583,000,000 | 583,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected investment in smart grid infrastructure | 155,000,000 | 155,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total smart grid smart meter investment grant awarded | 200,000,000 | 200,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total smart meter spend on investment | 540,000,000 | 540,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total smart grid spend on investment | 119,000,000 | 119,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart grid investment grant awarded | 60,000,000 | 60,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart grid sub recipient investment | 4,000,000 | 4,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart meter investment grant awarded | 140,000,000 | 140,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Carrying value of smart meters excluding DOE reimbursements | 17,000,000 | 17,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
DOE reimbursements use for original meter installment | 16,000,000 | 16,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation related to original meters | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Vendor refund | 12,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cost recoveries sought under direct load control program | 12,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cumulative consumption reduction targets | 1,125,852 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public sector maximum consumption reduction targets Act 129 Phase II | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proposed funding Of direct load control program costs | 10,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total alternative energy credits purchased annually | 452,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Solar tier 1 alternative energy credits purchased annually | 8,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 1,529,000,000 | 1,448,000,000 | 1,529,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 90,000,000 | 106,000,000 | 90,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual energy savings requirement | 3.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Demand response peak demand reduction | 4.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | OverRecoveredNaturalGasSupply [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 16,000,000 | 16,000,000 | 16,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | DSP Program costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 39,000,000 | 34,000,000 | 39,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Over-Recovered Electric Transmission Cost [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 3,000,000 | 8,000,000 | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Minimum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Tier I alternative energy resources | 3.50% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Tier II alternative energy resources | 6.20% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Low income sector consumption reduction targets Act 129 Phase II | 2.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Tier I alternative energy resources | 8.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage Tier II alternative energy resources | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum civil penalty under Act 129 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 0 | 8,000,000 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Deferred Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | AMI Expenses [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P10Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 62,000,000 | 58,000,000 | 62,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
PECO Energy Co [Member] | Asset Retirement Obligations [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 26,000,000 | 25,000,000 | 26,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average debt and equity return | 8.53% | 8.35% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate of return on common equity | 11.30% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in electric delivery service revenue resulting from rate case settlement or order. | 34,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in gas delivery service revenue resulting from rate case settlement or order. | 12,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Estimated number of smart meters to be installed | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested increase in electric revenues | 22,000,000 | 81,000,000 | 99,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested increase in gas revenues | 38,000,000 | 32,000,000 | 68,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual depreciation expense decrease regulated property | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Adjustment to electric revenues increase requested | 83,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public utilities, requested rate increase (decrease), amount | 24,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested rate of return on common equity | 9.75% | 9.75% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate of return common equity gas distribution | 9.60% | 9.60% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total projected smart meter smart grid spend | 480,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reimbursements received from the DOE | 200,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 510,000,000 | 524,000,000 | 510,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Upfront fee | 75 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recurring fee | 11 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gross transmission revenue requirement | 9,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transmission revenue true up | 5,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net transmission revenue requirement | 14,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate of return on common equity in federal energy regulatory committee complaint | 8.80% | 8.70% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer refund liability | 14,000,000 | 14,000,000 | 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 44,000,000 | 48,000,000 | 44,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Smart grid incremental cost | 11,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Site contingency, recovery from third party of environmental remediation cost | 1,000,000 | 5,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred costs, noncurrent | 16,000,000 | 8,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate cap imposed on public utility subsidiary | 15.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred purchased power costs | 306,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental costs recognized, recovery credited to expense | 65,000,000 | 66,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | OverRecoveredNaturalGasSupply [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 7,000,000 | 11,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | FERC Transmission Complaint [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Public utilities, approved return on equity, percentage | 10.80% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Electric Revenue [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 7,000,000 | 7,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Gas Revenue [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 12,000,000 | 9,000,000 | 12,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Under-Recovered Electric Revenue Decoupling [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Liabilities | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Waldorf Project [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity of natural gas fired combined cycle generation plant (in MW) | 700 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Initial term of proposed contract | 20 years | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Under Recovered Electric Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 10,000,000 | 10,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 15,000,000 | 4,000,000 | 15,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 4,000,000 | 3,000,000 | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P5Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 159,000,000 | 148,000,000 | 159,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Comprehensive Rate Order [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 19,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Non-severance Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 8,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase (decrease) in regulatory asset | 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Merger Integration Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 4,000,000 | 3,000,000 | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 6,000,000 | 9,000,000 | 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 28,000,000 | 37,000,000 | 28,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 20,000,000 | 30,000,000 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 16,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P5Y | 5 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 2,000,000 | 3,000,000 | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Transmission Rate Formula [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory assets | 1,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Severance Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory assets | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net regulatory assets | 19,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Pension and Other Postretirement Benefits [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P12Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 0 | 0 | 0 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | AMI Expenses [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization period | P10Y | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 128,000,000 | 66,000,000 | 128,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Noncurrent regulatory assets | 16,000,000 | 10,000,000 | 16,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum purchase obligation | 25,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum purchase obligation | 35,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
License costs | 39,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 19,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commonwealth Edison and Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory liabilities | 88,000,000 | 88,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Scenario, Forecast [Member] | Baltimore Gas and Electric Company [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Matters Additional Narrative Information [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revenue reduction | ($11,000,000) |
Regulatory_Matters_Estimated_C
Regulatory Matters - Estimated Commitments related to PJM Agreements (Details) (Construction Expansion Plans [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Commonwealth Edison Co [Member] | |
Other Commitments [Line Items] | |
Total | $335 |
2015 | 150 |
2016 | 172 |
2017 | 5 |
2018 | 4 |
2019 | 4 |
PECO Energy Co [Member] | |
Other Commitments [Line Items] | |
Total | 100 |
2015 | 32 |
2016 | 31 |
2017 | 25 |
2018 | 8 |
2019 | 4 |
Baltimore Gas and Electric Company [Member] | |
Other Commitments [Line Items] | |
Total | 351 |
2015 | 77 |
2016 | 104 |
2017 | 77 |
2018 | 57 |
2019 | $36 |
Regulatory_Matters_Schedule_of
Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 28, 2010 | ||
In Millions, unless otherwise specified | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | $847 | $760 | |||
Noncurrent regulatory assets | 6,076 | 5,910 | |||
Other Postretirement Benefits [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 247 | 221 | |||
Noncurrent regulatory assets | 3,009 | 2,794 | |||
Deferred Income Taxes [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 6 | 10 | |||
Noncurrent regulatory assets | 1,536 | 1,459 | |||
AMI Expenses [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 25 | 5 | |||
Noncurrent regulatory assets | 271 | 159 | |||
AMI Meter Events [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 5 | ||||
Under Recovered Distribution Service Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 251 | 178 | |||
Noncurrent regulatory assets | 120 | 285 | |||
Debt Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 8 | 12 | |||
Noncurrent regulatory assets | 49 | 56 | |||
Fair Value Of Long Term Debt [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 7 | 0 | |||
Noncurrent regulatory assets | 183 | 219 | |||
Fair Value Of Supply Contract [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 4 | 12 | |||
Noncurrent regulatory assets | 8 | 0 | |||
Severance [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 16 | ||||
Noncurrent regulatory assets | 12 | ||||
Asset Retirement Obligations [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | 1 | |||
Noncurrent regulatory assets | 115 | 102 | |||
MGP Remediation Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 36 | 40 | |||
Noncurrent regulatory assets | 221 | 212 | |||
RTO Startup Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 2 | ||||
Noncurrent regulatory assets | 0 | ||||
Under Recovered Uncollectible Accounts Expense [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 67 | 48 | |||
Renewable Energy And Associated REC [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 20 | 17 | |||
Noncurrent regulatory assets | 187 | 176 | |||
Under Recovered Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 37 | 53 | |||
Noncurrent regulatory assets | 11 | 9 | |||
Deferred Storm Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | 3 | |||
Noncurrent regulatory assets | 2 | 3 | |||
Electric Generation Related Regulatory Asset [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 10 | 13 | |||
Noncurrent regulatory assets | 20 | 30 | |||
Rate Stabilization Deferral [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 75 | 71 | |||
Noncurrent regulatory assets | 85 | 154 | |||
Energy Efficiency And Demand Response Programs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 89 | 73 | |||
Noncurrent regulatory assets | 159 | 148 | |||
Merger Integration Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 2 | 2 | |||
Noncurrent regulatory assets | 6 | 9 | |||
Conservation Voltage Reductio [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | ||||
Noncurrent regulatory assets | 1 | ||||
Under Recovered Decoupling Revenue [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 7 | ||||
Noncurrent regulatory assets | 0 | ||||
Other Assets [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 20 | [1] | 31 | [1] | |
Noncurrent regulatory assets | 26 | [1] | 30 | [1] | |
Commonwealth Edison Co [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 349 | 329 | |||
Noncurrent regulatory assets | 852 | 933 | |||
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Deferred Income Taxes [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 2 | |||
Noncurrent regulatory assets | 64 | 65 | |||
Commonwealth Edison Co [Member] | AMI Expenses [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 10 | 5 | |||
Noncurrent regulatory assets | 81 | 35 | |||
Commonwealth Edison Co [Member] | AMI Meter Events [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 251 | 178 | |||
Noncurrent regulatory assets | 120 | 285 | |||
Commonwealth Edison Co [Member] | Debt Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 6 | 9 | |||
Noncurrent regulatory assets | 47 | 53 | |||
Commonwealth Edison Co [Member] | Fair Value Of Long Term Debt [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Fair Value Of Supply Contract [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Commonwealth Edison Co [Member] | Severance [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 12 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | 1 | |||
Noncurrent regulatory assets | 73 | 67 | |||
Commonwealth Edison Co [Member] | MGP Remediation Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 30 | 33 | |||
Noncurrent regulatory assets | 189 | 178 | |||
Commonwealth Edison Co [Member] | RTO Startup Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 2 | ||||
Noncurrent regulatory assets | 0 | ||||
Commonwealth Edison Co [Member] | Under Recovered Uncollectible Accounts Expense [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 67 | 48 | |||
Commonwealth Edison Co [Member] | Renewable Energy And Associated REC [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 20 | 17 | |||
Noncurrent regulatory assets | 187 | 176 | |||
Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 26 | 52 | |||
Noncurrent regulatory assets | 7 | 6 | |||
Commonwealth Edison Co [Member] | Deferred Storm Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Rate Stabilization Deferral [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Commonwealth Edison Co [Member] | Merger Integration Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Regulatory assets | 7 | 6 | |||
Commonwealth Edison Co [Member] | Conservation Voltage Reductio [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Commonwealth Edison Co [Member] | Under Recovered Decoupling Revenue [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | |||||
Noncurrent regulatory assets | |||||
Commonwealth Edison Co [Member] | Other Assets [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 5 | [1] | 18 | [1] | |
Noncurrent regulatory assets | 17 | [1] | 20 | [1] | |
Commonwealth Edison Co [Member] | Purchase of Receivable Program [Member] | |||||
Regulatory Assets [Line Items] | |||||
Regulatory assets | 14 | 27 | |||
Commonwealth Edison Company [Member] | |||||
Regulatory Assets [Line Items] | |||||
Electric Transmission Costs Under-Recovery | 3 | ||||
Commonwealth Edison Company [Member] | Under Recovered Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Regulatory assets | 33 | 58 | |||
Electric Transmission Costs Under-Recovery | 22 | 17 | |||
Commonwealth Edison Company [Member] | Under-Recovered Electric Supply Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Electric Transmission Costs Under-Recovery | 4 | 35 | |||
Commonwealth Edison Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Regulatory Liabilities | 19 | ||||
PECO Energy Co [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 29 | 17 | |||
Noncurrent regulatory assets | 1,529 | 1,448 | |||
PECO Energy Co [Member] | Other Postretirement Benefits [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Deferred Income Taxes [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 1,400 | 1,317 | |||
PECO Energy Co [Member] | AMI Expenses [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 15 | 0 | |||
Noncurrent regulatory assets | 62 | 58 | |||
PECO Energy Co [Member] | AMI Meter Events [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 5 | ||||
PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Debt Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 2 | 3 | |||
Noncurrent regulatory assets | 2 | 3 | |||
PECO Energy Co [Member] | Fair Value Of Long Term Debt [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Fair Value Of Supply Contract [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
PECO Energy Co [Member] | Severance [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
PECO Energy Co [Member] | Asset Retirement Obligations [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 26 | 25 | |||
PECO Energy Co [Member] | MGP Remediation Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 6 | 6 | |||
Noncurrent regulatory assets | 31 | 33 | |||
PECO Energy Co [Member] | RTO Startup Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
PECO Energy Co [Member] | Under Recovered Uncollectible Accounts Expense [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Renewable Energy And Associated REC [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Deferred Storm Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Rate Stabilization Deferral [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Merger Integration Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
PECO Energy Co [Member] | Conservation Voltage Reductio [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
PECO Energy Co [Member] | Under Recovered Decoupling Revenue [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
PECO Energy Co [Member] | Other Assets [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 6 | [1] | 8 | [1] | |
Noncurrent regulatory assets | 8 | [1] | 7 | [1] | |
Baltimore Gas and Electric Company [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 214 | 181 | |||
Noncurrent regulatory assets | 510 | 524 | |||
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Baltimore Gas and Electric Company [Member] | Deferred Income Taxes [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 6 | 8 | |||
Noncurrent regulatory assets | 72 | 77 | |||
Baltimore Gas and Electric Company [Member] | AMI Expenses [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 128 | 66 | |||
Baltimore Gas and Electric Company [Member] | AMI Meter Events [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Baltimore Gas and Electric Company [Member] | Debt Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | 1 | |||
Noncurrent regulatory assets | 8 | 8 | |||
Baltimore Gas and Electric Company [Member] | Fair Value Of Long Term Debt [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Baltimore Gas and Electric Company [Member] | Fair Value Of Supply Contract [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Baltimore Gas and Electric Company [Member] | Severance [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 4 | 4 | |||
Noncurrent regulatory assets | 8 | 12 | |||
Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 16 | 10 | |||
Baltimore Gas and Electric Company [Member] | MGP Remediation Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 1 | |||
Noncurrent regulatory assets | 1 | 1 | |||
Regulatory assets | 1 | 1 | |||
Baltimore Gas and Electric Company [Member] | RTO Startup Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Baltimore Gas and Electric Company [Member] | Under Recovered Uncollectible Accounts Expense [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | ||||
Noncurrent regulatory assets | 0 | ||||
Baltimore Gas and Electric Company [Member] | Renewable Energy And Associated REC [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 0 | 0 | |||
Noncurrent regulatory assets | 0 | 0 | |||
Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 11 | 1 | |||
Noncurrent regulatory assets | 4 | 3 | |||
Regulatory assets | 15 | 4 | |||
Baltimore Gas and Electric Company [Member] | Under Recovered Electric Energy And Transmission Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Regulatory assets | 10 | ||||
Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | 3 | |||
Noncurrent regulatory assets | 2 | 3 | |||
Regulatory assets | 16 | ||||
Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 10 | 13 | |||
Noncurrent regulatory assets | 20 | 30 | |||
Regulatory assets | 28 | 37 | |||
Baltimore Gas and Electric Company [Member] | Rate Stabilization Deferral [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 75 | 71 | |||
Noncurrent regulatory assets | 85 | 154 | |||
Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 89 | 73 | |||
Noncurrent regulatory assets | 159 | 148 | |||
Baltimore Gas and Electric Company [Member] | Merger Integration Costs [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 2 | 2 | |||
Noncurrent regulatory assets | 6 | 9 | |||
Regulatory assets | 4 | 3 | |||
Baltimore Gas and Electric Company [Member] | Conservation Voltage Reductio [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 1 | ||||
Noncurrent regulatory assets | 1 | ||||
Baltimore Gas and Electric Company [Member] | Under Recovered Decoupling Revenue [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 7 | ||||
Noncurrent regulatory assets | 0 | ||||
Baltimore Gas and Electric Company [Member] | Other Assets [Member] | |||||
Regulatory Assets [Line Items] | |||||
Current regulatory assets | 7 | [1] | 4 | [1] | |
Noncurrent regulatory assets | 0 | [1] | 3 | [1] | |
Baltimore Gas and Electric Company [Member] | Purchase of Receivable Program [Member] | |||||
Regulatory Assets [Line Items] | |||||
Regulatory assets | $7 | $0 | |||
[1] | For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively. |
Regulatory_Matters_Schedule_of1
Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | $310 | $327 |
Noncurrent regulatory liabilities | 4,550 | 4,388 |
Other Postretirement Benefits [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 51 | 2 |
Noncurrent regulatory liabilities | 37 | 43 |
Nuclear Decommissioning [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 2,879 | 2,740 |
Removal Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 118 | 99 |
Noncurrent regulatory liabilities | 1,448 | 1,423 |
Energy Efficiency Demand Response Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 25 | 53 |
Noncurrent regulatory liabilities | 2 | 0 |
Dlc Program Cost [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 1 |
Noncurrent regulatory liabilities | 10 | 10 |
Energy Efficiency Phase [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 32 | 21 |
Electric Transmission And Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 8 | 20 |
Noncurrent regulatory liabilities | 94 | 114 |
Gas Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 20 | 8 |
Noncurrent regulatory liabilities | 29 | 37 |
Over Recovered Energy And Transmission Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 68 | 78 |
Noncurrent regulatory liabilities | 16 | 0 |
Over-Recovered Universal Service Fund Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 2 | 8 |
Noncurrent regulatory liabilities | 0 | 0 |
Revenue Subject to Refund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 3 | 38 |
Noncurrent regulatory liabilities | 0 | 0 |
Over Recovered Decoupling Revenue [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 12 | 16 |
Noncurrent regulatory liabilities | 0 | 0 |
Regulatory Liabilities Other [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 3 | 4 |
Noncurrent regulatory liabilities | 3 | 0 |
Commonwealth Edison Co [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 125 | 170 |
Noncurrent regulatory liabilities | 3,655 | 3,512 |
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 2,389 | 2,293 |
Commonwealth Edison Co [Member] | Removal Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 94 | 78 |
Noncurrent regulatory liabilities | 1,249 | 1,219 |
Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 25 | 45 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Dlc Program Cost [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Energy Efficiency Phase [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Gas Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 3 | 9 |
Noncurrent regulatory liabilities | 16 | 0 |
Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Revenue Subject to Refund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 3 | 38 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Over Recovered Decoupling Revenue [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Regulatory Liabilities Other [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 1 | 0 |
PECO Energy Co [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 90 | 106 |
Noncurrent regulatory liabilities | 657 | 629 |
PECO Energy Co [Member] | Other Postretirement Benefits [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Nuclear Decommissioning [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 490 | 447 |
PECO Energy Co [Member] | Removal Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 8 |
Noncurrent regulatory liabilities | 2 | 0 |
PECO Energy Co [Member] | Dlc Program Cost [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 1 |
Noncurrent regulatory liabilities | 10 | 10 |
PECO Energy Co [Member] | Energy Efficiency Phase [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 32 | 21 |
PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 8 | 20 |
Noncurrent regulatory liabilities | 94 | 114 |
PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 20 | 8 |
Noncurrent regulatory liabilities | 29 | 37 |
PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 58 | 58 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 2 | 8 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Revenue Subject to Refund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Over Recovered Decoupling Revenue [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
PECO Energy Co [Member] | Regulatory Liabilities Other [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 2 | 3 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 44 | 48 |
Noncurrent regulatory liabilities | 200 | 204 |
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Removal Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 24 | 21 |
Noncurrent regulatory liabilities | 199 | 204 |
Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Dlc Program Cost [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Energy Efficiency Phase [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Gas Distribution Tax Repairs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | |
Noncurrent regulatory liabilities | 0 | |
Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 7 | 11 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Revenue Subject to Refund [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 0 | 0 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Revenue [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 12 | 16 |
Noncurrent regulatory liabilities | 0 | 0 |
Baltimore Gas and Electric Company [Member] | Regulatory Liabilities Other [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory liabilities | 1 | 0 |
Noncurrent regulatory liabilities | 1 | 0 |
Renewable Energy Program [Member] | Commonwealth Edison Company [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | 16 | 9 |
Over Recovered Electric Energy And Transmission Costs [Member] | Commonwealth Edison Company [Member] | ||
Regulatory Liabilities [Line Items] | ||
Regulatory Liabilities | $19 |
Regulatory_Matters_Purchase_of
Regulatory Matters - Purchase of Receivables Programs (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Purchase Of Receivables [Line Items] | ||||
Purchased receivables | $290 | [1] | $263 | [1] |
Allowance for uncollectible accounts | -42 | [2] | -30 | [2] |
Purchased receivables, net | 248 | 233 | ||
Commonwealth Edison Co [Member] | ||||
Purchase Of Receivables [Line Items] | ||||
Purchased receivables | 139 | [1] | 105 | [1] |
Allowance for uncollectible accounts | -21 | [2] | -16 | [2] |
Purchased receivables, net | 118 | 89 | ||
PECO Energy Co [Member] | ||||
Purchase Of Receivables [Line Items] | ||||
Purchased receivables | 76 | [1] | 72 | [1] |
Allowance for uncollectible accounts | -8 | [2] | -7 | [2] |
Purchased receivables, net | 68 | 65 | ||
Baltimore Gas and Electric Company [Member] | ||||
Purchase Of Receivables [Line Items] | ||||
Purchased receivables | 75 | [1] | 86 | [1] |
Allowance for uncollectible accounts | -13 | [2] | -7 | [2] |
Purchased receivables, net | $62 | $79 | ||
[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. |
Mergers_Acquisitions_and_Dispo2
Mergers, Acquisitions and Dispositions - Narrative (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 2 Months Ended | ||||||||||||||||||||||||||
Share data in Millions, except Per Share data, unless otherwise specified | Jun. 11, 2014 | Mar. 20, 2013 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Nov. 01, 2014 | Dec. 31, 2014 | 31-May-14 | Jun. 30, 2012 | Jul. 26, 2013 | Dec. 27, 2013 | Dec. 12, 2014 | 30-May-12 | Jan. 14, 2015 | Jul. 18, 2014 | Nov. 30, 2012 | Feb. 28, 2012 | |||||
MW | MW | MW | |||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Other noncurrent assets | $1,160,000,000 | $964,000,000 | $1,160,000,000 | $964,000,000 | $1,160,000,000 | $1,160,000,000 | |||||||||||||||||||||||||
Business Combination, Integration Related Costs | 19,000,000 | 28,000,000 | |||||||||||||||||||||||||||||
Equity security units | 57.5 | ||||||||||||||||||||||||||||||
Bridge loan | 3,200,000,000 | 7,200,000,000 | |||||||||||||||||||||||||||||
Revenues | 7,255,000,000 | 6,912,000,000 | 6,024,000,000 | 7,237,000,000 | 6,163,000,000 | 6,502,000,000 | 6,141,000,000 | 6,082,000,000 | 27,429,000,000 | [1] | 24,888,000,000 | [1] | 23,489,000,000 | [1] | |||||||||||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 1,176,000,000 | 2,456,000,000 | 854,000,000 | ||||||||||||||||||||||||||||
Net income | 18,000,000 | [2] | 993,000,000 | 522,000,000 | 90,000,000 | 495,000,000 | 738,000,000 | 490,000,000 | -4,000,000 | [3] | 1,820,000,000 | 1,729,000,000 | 1,171,000,000 | ||||||||||||||||||
Merger and integration related costs | 44,000,000 | 141,000,000 | [4] | ||||||||||||||||||||||||||||
Generating assets net book value | 1,800,000,000 | 1,800,000,000 | 1,800,000,000 | 1,800,000,000 | |||||||||||||||||||||||||||
Expected pre-tax proceeds | 1,800,000,000 | ||||||||||||||||||||||||||||||
Expected after-tax proceeds | 1,400,000,000 | ||||||||||||||||||||||||||||||
Construction costs | 66,000,000 | ||||||||||||||||||||||||||||||
Construction time frame | 20 years | ||||||||||||||||||||||||||||||
Loss contingency accrual | 44,000,000 | 44,000,000 | 44,000,000 | 44,000,000 | |||||||||||||||||||||||||||
Maximum loss contingency | 105,000,000 | 105,000,000 | 105,000,000 | 105,000,000 | |||||||||||||||||||||||||||
Estimated future period for payment | 20 years | ||||||||||||||||||||||||||||||
Change in capital expenditures not paid | 220,000,000 | -38,000,000 | 160,000,000 | ||||||||||||||||||||||||||||
Operating And Maintenance Expense [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Change in capital expenditures not paid | 185,000,000 | 24,000,000 | |||||||||||||||||||||||||||||
Development costs expensed | 3,000,000 | 6,000,000 | |||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Other noncurrent assets | 731,000,000 | 645,000,000 | 731,000,000 | 645,000,000 | 731,000,000 | 731,000,000 | |||||||||||||||||||||||||
Business Combination, Integration Related Costs | 19,000,000 | ||||||||||||||||||||||||||||||
Revenues | 4,802,000,000 | 4,412,000,000 | 3,789,000,000 | 4,390,000,000 | 3,772,000,000 | 4,255,000,000 | 4,070,000,000 | 3,533,000,000 | 17,393,000,000 | 15,630,000,000 | 14,437,000,000 | ||||||||||||||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 769,000,000 | 761,000,000 | 156,000,000 | ||||||||||||||||||||||||||||
Net income | -91,000,000 | 771,000,000 | 340,000,000 | -185,000,000 | 269,000,000 | 490,000,000 | 330,000,000 | -18,000,000 | 1,019,000,000 | 1,060,000,000 | 558,000,000 | ||||||||||||||||||||
Merger and integration related costs | 44,000,000 | 32,000,000 | [4] | ||||||||||||||||||||||||||||
Expected period of completion | 10 years | ||||||||||||||||||||||||||||||
Loss contingency accrual | 44,000,000 | 44,000,000 | 44,000,000 | 44,000,000 | |||||||||||||||||||||||||||
Capacity of energy construction project | 150 | 150 | 150 | 150 | |||||||||||||||||||||||||||
Change in capital expenditures not paid | -61,000,000 | [5] | -107,000,000 | [6] | 103,000,000 | [7] | |||||||||||||||||||||||||
Development costs expensed | 13,000,000 | 10,000,000 | 4,000,000 | ||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Perryman Construction [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Capacity of energy construction project | 120 | ||||||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Fourmile Wind Project [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Capacity of energy construction project | 40 | 40 | 40 | 40 | 40 | ||||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Fair Wind Project [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Capacity of energy construction project | 30 | 30 | 30 | 30 | 30 | ||||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Other noncurrent assets | 25,000,000 | 26,000,000 | 25,000,000 | 26,000,000 | 25,000,000 | 25,000,000 | |||||||||||||||||||||||||
Revenues | 761,000,000 | 697,000,000 | 653,000,000 | 1,054,000,000 | 794,000,000 | 737,000,000 | 653,000,000 | 880,000,000 | 3,165,000,000 | 3,065,000,000 | 2,735,000,000 | ||||||||||||||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 211,000,000 | 210,000,000 | 4,000,000 | ||||||||||||||||||||||||||||
Net income | 52,000,000 | 46,000,000 | 16,000,000 | 85,000,000 | 47,000,000 | 50,000,000 | 22,000,000 | 77,000,000 | 211,000,000 | 210,000,000 | 4,000,000 | ||||||||||||||||||||
Merger and integration related costs | 0 | 27,000,000 | [4] | ||||||||||||||||||||||||||||
Maximum loss contingency | 1,700,000 | ||||||||||||||||||||||||||||||
Change in capital expenditures not paid | 25,000,000 | -48,000,000 | -4,000,000 | ||||||||||||||||||||||||||||
Regulatory assets transfer changes | 8,000,000 | 272,000,000 | |||||||||||||||||||||||||||||
Commonwealth Edison Co [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Other noncurrent assets | 271,000,000 | 291,000,000 | 271,000,000 | 291,000,000 | 271,000,000 | 271,000,000 | |||||||||||||||||||||||||
Revenues | 1,079,000,000 | 1,222,000,000 | 1,128,000,000 | 1,134,000,000 | 1,068,000,000 | 1,156,000,000 | 1,080,000,000 | 1,160,000,000 | 4,564,000,000 | 4,464,000,000 | 5,443,000,000 | ||||||||||||||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 408,000,000 | 249,000,000 | 380,000,000 | ||||||||||||||||||||||||||||
Net income | 73,000,000 | 126,000,000 | 111,000,000 | 98,000,000 | 109,000,000 | 126,000,000 | 96,000,000 | -81,000,000 | 408,000,000 | 249,000,000 | 379,000,000 | ||||||||||||||||||||
Merger and integration related costs | 0 | 0 | [4] | ||||||||||||||||||||||||||||
Change in capital expenditures not paid | 78,000,000 | -8,000,000 | 15,000,000 | ||||||||||||||||||||||||||||
PECO Energy Co [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Other noncurrent assets | 34,000,000 | 38,000,000 | 34,000,000 | 38,000,000 | 34,000,000 | 34,000,000 | |||||||||||||||||||||||||
Revenues | 750,000,000 | 693,000,000 | 656,000,000 | 993,000,000 | 805,000,000 | 728,000,000 | 672,000,000 | 895,000,000 | 3,094,000,000 | 3,100,000,000 | 3,186,000,000 | ||||||||||||||||||||
Comprehensive Income (Loss), Net of Tax, Attributable to Parent | 352,000,000 | 395,000,000 | 382,000,000 | ||||||||||||||||||||||||||||
Net income | 98,000,000 | 81,000,000 | 84,000,000 | 89,000,000 | 102,000,000 | 92,000,000 | 72,000,000 | 121,000,000 | 352,000,000 | 395,000,000 | 381,000,000 | ||||||||||||||||||||
Merger and integration related costs | 0 | 0 | [4] | ||||||||||||||||||||||||||||
Change in capital expenditures not paid | 0 | 13,000,000 | 26,000,000 | ||||||||||||||||||||||||||||
Minimum [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Construction costs | 95,000,000 | 95,000,000 | 95,000,000 | 95,000,000 | |||||||||||||||||||||||||||
Development of new generation cost | 600,000,000 | 600,000,000 | 600,000,000 | 600,000,000 | |||||||||||||||||||||||||||
Expected new generation (in MW) | 285 | ||||||||||||||||||||||||||||||
Maximum [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Construction costs | 120,000,000 | 120,000,000 | 120,000,000 | 120,000,000 | |||||||||||||||||||||||||||
Development of new generation cost | 650,000,000 | 650,000,000 | 650,000,000 | 650,000,000 | |||||||||||||||||||||||||||
Expected new generation (in MW) | 300 | ||||||||||||||||||||||||||||||
Subsequent Event [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Aggregate value of customer rate credit programs | 62,000,000 | ||||||||||||||||||||||||||||||
Aggregate value of energy efficiency programs | 15,000,000 | ||||||||||||||||||||||||||||||
Pepco Holdings [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Share price | $35 | $27.25 | |||||||||||||||||||||||||||||
Other noncurrent assets | 126,000,000 | 126,000,000 | 126,000,000 | 126,000,000 | |||||||||||||||||||||||||||
Other long-term investments | 18,000,000 | ||||||||||||||||||||||||||||||
Other long-term investments, maximum | 180,000,000 | ||||||||||||||||||||||||||||||
Total acquisition costs | 7,200,000,000 | ||||||||||||||||||||||||||||||
Proposed customer benefit package | 100,000,000 | ||||||||||||||||||||||||||||||
Business Acquisition, Transaction Costs | 179,000,000 | 179,000,000 | 179,000,000 | 179,000,000 | |||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 48,000,000 | ||||||||||||||||||||||||||||||
Business Combination, Acquisition Related Costs | 131,000,000 | ||||||||||||||||||||||||||||||
Expected debt issuance | 3,500,000,000 | ||||||||||||||||||||||||||||||
Cash funding from non-core asset sale | 1,000,000,000 | 1,000,000,000 | 1,000,000,000 | 1,000,000,000 | |||||||||||||||||||||||||||
Equity security units | 23 | ||||||||||||||||||||||||||||||
Subordinated junior notes | 1,200,000,000 | ||||||||||||||||||||||||||||||
Pepco Holdings [Member] | Exelon Generation Co L L C [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Capacity of energy construction project | 125 | 125 | 125 | 125 | |||||||||||||||||||||||||||
Pepco Holdings [Member] | Bridge Loan [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 7,200,000,000 | ||||||||||||||||||||||||||||||
Pepco Holdings [Member] | Minimum [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business exit costs | 259,000,000 | ||||||||||||||||||||||||||||||
Pepco Holdings [Member] | Maximum [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business exit costs | 293,000,000 | ||||||||||||||||||||||||||||||
Intergrys Energy Group Inc [Member] | Exelon Generation Co L L C [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Total consideration transferred | 332,000,000 | ||||||||||||||||||||||||||||||
Payments to acquire businesses | 319,000,000 | ||||||||||||||||||||||||||||||
Liabilities incurred in acquisition | 13,000,000 | ||||||||||||||||||||||||||||||
Bargain purchase gain (after-tax) | 28,000,000 | ||||||||||||||||||||||||||||||
Revenues | 386,000,000 | ||||||||||||||||||||||||||||||
Net income | -42,000,000 | ||||||||||||||||||||||||||||||
Derivative, Loss on Derivative | 108,000,000 | ||||||||||||||||||||||||||||||
Merger and integration related costs | 7,000,000 | ||||||||||||||||||||||||||||||
Constellation Energy Group Acquisition [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 22,000,000 | 142,000,000 | 804,000,000 | ||||||||||||||||||||||||||||
Estimated direct investment in the State of Maryland | 1,000,000,000 | ||||||||||||||||||||||||||||||
Proceeds assets held for sale | 371,000,000 | ||||||||||||||||||||||||||||||
Regulatory assets transfer changes | 17,000,000 | 58,000,000 | |||||||||||||||||||||||||||||
Constellation Energy Group Acquisition [Member] | Exelon Generation Co L L C [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 106,000,000 | 340,000,000 | |||||||||||||||||||||||||||||
Constellation Energy Group Acquisition [Member] | Baltimore Gas and Electric Company [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 6,000,000 | 182,000,000 | |||||||||||||||||||||||||||||
Revenues | 3,065,000,000 | 2,091,000,000 | |||||||||||||||||||||||||||||
Net income | 210,000,000 | -31,000,000 | |||||||||||||||||||||||||||||
Regulatory assets transfer changes | 6,000,000 | 22,000,000 | |||||||||||||||||||||||||||||
Constellation Energy Group Acquisition [Member] | Commonwealth Edison Co [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | 16,000,000 | 41,000,000 | |||||||||||||||||||||||||||||
Regulatory assets transfer changes | 11,000,000 | 36,000,000 | |||||||||||||||||||||||||||||
Constellation Energy Group Acquisition [Member] | PECO Energy Co [Member] | |||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||
Business Combination, Integration Related Costs | $9,000,000 | $17,000,000 | |||||||||||||||||||||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | ||||||||||||||||||||||||||||||
[2] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||||||||||||||
[3] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||||||||||||||
[4] | Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments. | ||||||||||||||||||||||||||||||
[5] | Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley. | ||||||||||||||||||||||||||||||
[6] | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | ||||||||||||||||||||||||||||||
[7] | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. |
Mergers_Acquisitions_and_Dispo3
Mergers, Acquisitions and Dispositions - Summary of Integrys Energy Group Acquisition (Details) (Exelon Generation Co L L C [Member], Intergrys Energy Group Inc [Member], USD $) | 0 Months Ended | |
In Millions, unless otherwise specified | Nov. 01, 2014 | Nov. 01, 2014 |
Exelon Generation Co L L C [Member] | Intergrys Energy Group Inc [Member] | ||
Business Acquisition [Line Items] | ||
Total consideration transferred | $332 | |
Working capital assets | 389 | 389 |
Mark-to-market derivative assets | 185 | 185 |
Unamortized energy contracts | 115 | 115 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles | 48 | 48 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities | -195 | -195 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Liabilities | -57 | -57 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities | -109 | -109 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent | -16 | -16 |
Total net assets | 360 | 360 |
Bargain purchase gain (after-tax) | $28 |
Mergers_Acquisitions_and_Dispo4
Mergers, Acquisitions and Dispositions - Costs Recognized after Closing of Merger (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2012 | Jun. 30, 2012 | ||
Business Acquisition [Line Items] | |||
BGE rate credit of $100 per residential customer | $113,000,000 | [1] | |
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | 114,000,000 | ||
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 | ||
State funding for offshore wind development projects | 32,000,000 | ||
Miscellaneous tax benefits | -2,000,000 | ||
Total | 329,000,000 | ||
Rate credit per residential customer (in usd per customer) | 100 | ||
Charitable contributions, per year | 7,000,000 | ||
Period for charitable contributions | 10 years | ||
Construction costs | 66,000,000 | ||
Baltimore Gas and Electric Company [Member] | |||
Business Acquisition [Line Items] | |||
BGE rate credit of $100 per residential customer | 113,000,000 | [1] | |
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | 0 | ||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | 0 | ||
Charitable contributions at $7 million per year for 10 years | 28,000,000 | ||
State funding for offshore wind development projects | 0 | ||
Miscellaneous tax benefits | -2,000,000 | ||
Total | 139,000,000 | ||
Rate credit per residential customer (in usd per customer) | 100 | ||
Charitable contributions, per year | 7,000,000 | ||
Period for charitable contributions | 10 years | ||
Exelon Generation Co L L C [Member] | |||
Business Acquisition [Line Items] | |||
BGE rate credit of $100 per residential customer | 0 | [1] | |
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers | 0 | ||
Contribution for renewable energy, energy efficiency or related projects in Baltimore | 0 | ||
Charitable contributions at $7 million per year for 10 years | 35,000,000 | ||
State funding for offshore wind development projects | 0 | ||
Miscellaneous tax benefits | 0 | ||
Total | 35,000,000 | ||
Rate credit per residential customer (in usd per customer) | 100 | ||
Charitable contributions, per year | $7,000,000 | ||
Period for charitable contributions | 10 years | ||
[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. |
Mergers_Acquisitions_and_Dispo5
Mergers, Acquisitions and Dispositions - Purchase Price Allocation of Merger with Constellation (Details) (Constellation Energy Group LLC [Member], USD $) | Dec. 31, 2012 |
In Millions, unless otherwise specified | |
Business Acquisition [Line Items] | |
Current assets | $4,936 |
Property, plant and equipment | 9,342 |
Unamortized energy contracts | 3,218 |
Other intangibles, trade name and retail relationships | 457 |
Investment in affiliates | 1,942 |
Asset retirement obligation | 740 |
Other assets | 2,265 |
Total assets | 22,900 |
Current liabilities | 3,408 |
Unamortized energy contract liabilities | 1,722 |
Long-term debt, including current maturities | 5,632 |
Noncontrolling interest | 90 |
Other liabilities | 4,683 |
Total liabilities | 15,535 |
Total net assets | 7,365 |
Exelon Generation Co L L C [Member] | |
Business Acquisition [Line Items] | |
Current assets | 3,638 |
Property, plant and equipment | 4,054 |
Unamortized energy contracts | 3,218 |
Other intangibles, trade name and retail relationships | 457 |
Investment in affiliates | 1,942 |
Asset retirement obligation | 0 |
Other assets | 1,266 |
Total assets | 14,575 |
Current liabilities | 2,804 |
Unamortized energy contract liabilities | 1,512 |
Long-term debt, including current maturities | 2,972 |
Noncontrolling interest | 90 |
Other liabilities | 1,933 |
Total liabilities | 9,311 |
Total net assets | $5,264 |
Mergers_Acquisitions_and_Dispo6
Mergers, Acquisitions and Dispositions - Summary of Pro-forma Impact of the Merger (Details) (USD $) | 12 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2011 |
Business Acquisition [Line Items] | ||
Total revenues | $26,700 | $30,712 |
Net income attributable to Exelon | 2,092 | 974 |
Basic Earnings Per Share (in usd per share) | $2,560,000 | $1,150,000 |
Diluted Earnings Per Share (in usd per share) | $2,550,000 | $1,140,000 |
Non-recurring costs | 236 | |
Exelon Generation Co L L C [Member] | ||
Business Acquisition [Line Items] | ||
Total revenues | 17,013 | 19,494 |
Net income attributable to Exelon | 1,205 | 324 |
Non-recurring costs | $203 |
Mergers_Acquisitions_and_Dispo7
Mergers, Acquisitions and Dispositions - Summary of Asset Divestitures (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Long Lived Assets Held-for-sale [Line Items] | |||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | $437 | $13 | ($7) |
Fore River [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Percent Owned | 100.00% | ||
Net Generation Capacity | 726,000,000 | ||
West Valley [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Percent Owned | 100.00% | ||
Net Generation Capacity | 185,000,000 | ||
Keystone [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Percent Owned | 41.98% | ||
Net Generation Capacity | 714,000,000 | ||
Conemaugh [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Percent Owned | 31.28% | ||
Net Generation Capacity | 532,000,000 | ||
Safe Harbor [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Percent Owned | 66.70% | ||
Net Generation Capacity | 278,000,000 | ||
Quail Run [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | 412 | ||
Percent Owned | 100.00% | ||
Net Generation Capacity | 488,000,000 | ||
Exelon Generation Co L L C [Member] | |||
Long Lived Assets Held-for-sale [Line Items] | |||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | $437 | $13 | ($7) |
Mergers_Acquisitions_and_Dispo8
Mergers, Acquisitions and Dispositions - Summary of Major Classes of Assets and Liabilities Held for Sale (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | |
Significant Acquisitions and Disposals [Line Items] | |||
Total assets held for sale | $147 | $14 | |
Accrued expenses | 1,539 | 1,633 | |
Other current liabilities | 1,123 | 858 | |
Electricity Generation Plant, Non-Nuclear [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Property, plant and equipment, net | 143 | [1] | |
Inventory | 4 | ||
Total assets held for sale | 147 | ||
Accrued expenses | 1 | ||
Other current liabilities | 4 | ||
Total liabilities held for sale | 5 | [2] | |
Asset impairment charges | $50 | ||
[1] | The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information. | ||
[2] | Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. |
Investment_in_Constellation_En2
Investment in Constellation Energy Nuclear Group, LLC - Narrative (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | |||||||||||||
In Millions, unless otherwise specified | Apr. 01, 2014 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Purchase of nuclear output by EDF | 49.99% | |||||||||||||||
Guarantee obligations maximum exposure | $9,402 | $9,402 | ||||||||||||||
Revenues | 7,255 | 6,912 | 6,024 | 7,237 | 6,163 | 6,502 | 6,141 | 6,082 | 27,429 | [1] | 24,888 | [1] | 23,489 | [1] | ||
Investment in CENG | 0 | 1,925 | 0 | 1,925 | ||||||||||||
Accumulated other comprehensive loss, net | -2,684 | -2,040 | [2] | -2,684 | -2,040 | [2] | -2,767 | [2] | ||||||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | |||||||||||||||
Operating revenues from affiliates | 23 | 70 | 48 | |||||||||||||
Parental guarantee provided | 75 | 75 | ||||||||||||||
Business Combination, Integration Related Costs | 19 | 28 | ||||||||||||||
Constellation Energy Nuclear Group [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Accumulated other comprehensive loss, net | 1,500 | |||||||||||||||
Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Due to affiliate | 245 | |||||||||||||||
Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Guarantee obligations maximum exposure | 165 | |||||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Ownership interest | 50.01% | 50.01% | ||||||||||||||
Cash distribution paid to member | 645 | 625 | 1,626 | |||||||||||||
Purchase of nuclear output by EDF | 49.99% | |||||||||||||||
Guarantee obligations maximum exposure | 6,384 | 6,384 | ||||||||||||||
Total equity investment earnings (losses) - CENG | 19 | 9 | ||||||||||||||
Revenues | 4,802 | 4,412 | 3,789 | 4,390 | 3,772 | 4,255 | 4,070 | 3,533 | 17,393 | 15,630 | 14,437 | |||||
Investment in CENG | 0 | 1,925 | 0 | 1,925 | ||||||||||||
Accumulated other comprehensive loss, net | -36 | 214 | [2] | -36 | 214 | [2] | 513 | [2] | ||||||||
Allocation of federal tax benefit under tax sharing agreement | 77 | 26 | 26 | |||||||||||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | 85.00% | ||||||||||||||
Subsequent purchases of power from CENG's nuclear plants not sold to third parties | 50.01% | |||||||||||||||
Operating revenues from affiliates | 779 | 1,423 | 1,702 | |||||||||||||
Parental guarantee provided | 5 | 5 | ||||||||||||||
Business Combination, Integration Related Costs | 19 | |||||||||||||||
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Remeasurement gain from derecognition of equity method investment | 261 | |||||||||||||||
Business combination, step acquisition, equity interest in acquiree, fair value | 136 | |||||||||||||||
Business acquisition, preexisting relationship, gain (loss) recognized | 132 | |||||||||||||||
Parental guarantee provided | 7 | 7 | 7 | |||||||||||||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Revenues | 17 | 218 | 56 | |||||||||||||
Investment in CENG | 1,900 | |||||||||||||||
Accumulated other comprehensive loss, net | 116 | |||||||||||||||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Due from affiliates | 400 | 400 | 400 | |||||||||||||
Interest rate on loan to CENG | 5.25% | |||||||||||||||
Allocation of federal tax benefit under tax sharing agreement | 152 | |||||||||||||||
Reduction to net income attributable to noncontrolling interest | 13 | |||||||||||||||
Net Income (Loss) Attributable to Parent | 407 | |||||||||||||||
Business Combination, Integration Related Costs | 26 | |||||||||||||||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Due to affiliate | 205 | |||||||||||||||
Exelon Generation Co L L C [Member] | EDFI [Member] | Constellation Energy Nuclear Group [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 137 | |||||||||||||||
Electricite De France LLC [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 15.00% | |||||||||||||||
Subsequent purchases of power from CENG's nuclear plants not sold to third parties | 49.99% | |||||||||||||||
Electricite De France LLC [Member] | Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Guarantee obligations maximum exposure | 145 | |||||||||||||||
Constellation Energy Group LLC [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Interest rate on distribution | 8.50% | |||||||||||||||
Constellation Energy Group LLC [Member] | EDFI [Member] | ||||||||||||||||
Schedule of Equity Method Investments [Line Items] | ||||||||||||||||
Cash distribution paid to member | $400 | |||||||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||||
[2] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Investment_in_Constellation_En3
Investment in Constellation Energy Nuclear Group, LLC - Schedule of Assets and Liabilities of CENG (Details) (Exelon Generation Co L L C [Member], Constellation Energy Nuclear Group [Member], USD $) | Apr. 01, 2014 |
In Millions, unless otherwise specified | |
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | |
Business Acquisition [Line Items] | |
Current assets | $499 |
Nuclear decommissioning trust fund | 1,955 |
Property, plant and equipment | 3,017 |
Nuclear fuel | 482 |
Other assets | 10 |
Total assets | 5,963 |
Current liabilities | 237 |
Asset retirement obligation | 1,760 |
Pension and other employee benefit obligations | 281 |
Unamortized energy contract liabilities | 171 |
Other liabilities | 114 |
Total liabilities | 2,563 |
Total net assets | $3,400 |
Accounts_Receivable_Schedule_o
Accounts Receivable - Schedule of Estimated Unbilled Revenues (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Unbilled customer revenues | $1,381 | $1,151 | ||
Allowance for uncollectible accounts | -311 | [1] | -272 | [1] |
Exelon Generation Co L L C [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Unbilled customer revenues | 823 | [2] | 584 | [2] |
Allowance for uncollectible accounts | -60 | [1] | -57 | [1] |
Commonwealth Edison Co [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Unbilled customer revenues | 204 | 201 | ||
Allowance for uncollectible accounts | -84 | [1] | -62 | [1] |
PECO Energy Co [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Unbilled customer revenues | 140 | 161 | ||
Allowance for uncollectible accounts | -100 | [1],[3] | -107 | [1],[3] |
Current financing receivable allowance for credit losses | 7 | 8 | ||
Baltimore Gas and Electric Company [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Unbilled customer revenues | 214 | 205 | ||
Allowance for uncollectible accounts | -67 | [1],[4] | -46 | [1],[4] |
Charged to Costs and Expenses | $19 | |||
[1] | Includes the allowance for uncollectible accounts on customer and other accounts receivable. | |||
[2] | Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy. | |||
[3] | Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below. | |||
[4] | At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income. |
Accounts_Receivable_Narrative_
Accounts Receivable - Narrative (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Installment plan receivables | $15 | $19 |
PECO Energy Co [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Installment plan receivables uncollectible accounts reserve | 15 | 18 |
Risk Level, Low [Member] | PECO Energy Co [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Installment plan receivables uncollectible accounts reserve | 1 | 1 |
Risk Level, Medium [Member] | PECO Energy Co [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Installment plan receivables | 3 | 4 |
Risk Level, High [Member] | PECO Energy Co [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Installment plan receivables | $11 | $13 |
Property_Plant_and_Equipment_S
Property, Plant and Equipment - Summary of Property, Plant and Equipment (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | $66,829 | $61,043 | ||
Less: accumulated depreciation | 14,742 | [1] | 13,713 | [1] |
Property, plant and equipment, net | 52,087 | 47,330 | ||
Nuclear fuel - work in progress | 1,003 | 947 | ||
Buildings under capital lease | 15 | 23 | ||
Original cost basis for buildings | 52 | 59 | ||
Accumulated depreciation for buildings | 37 | 36 | ||
Accumulated amortization of nuclear fuel | 2,673 | 2,371 | ||
Electric Transmission and Distribution Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 30,157 | 28,123 | ||
Electric Transmission and Distribution Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 90 years | |||
Electric Transmission and Distribution Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 5 years | |||
Electric Generation Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 22,911 | 20,420 | ||
Electric Generation Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 56 years | |||
Electric Generation Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 1 year | |||
Gas Distribution Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 3,505 | 3,296 | ||
Gas Distribution Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 90 years | |||
Gas Distribution Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 5 years | |||
Common Electric And Gas T And D Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 1,169 | 1,101 | ||
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 | |||
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 | |||
Nuclear Fuel [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 5,947 | [2] | 5,196 | [2] |
Nuclear Fuel [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 8 years | [2] | ||
Nuclear Fuel [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 1 year | [2] | ||
Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 2,167 | 1,890 | ||
Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 973 | [3] | 1,017 | [3] |
Other Capitalized Property Plant and Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 50 years | [3] | ||
Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 5 years | [3] | ||
Exelon Generation Co L L C [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 30,557 | 27,145 | ||
Less: accumulated depreciation | 7,612 | [4] | 7,034 | [4] |
Property, plant and equipment, net | 22,945 | 20,111 | ||
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 22,911 | 20,420 | ||
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 | 56 years | |||
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] | Nuclear Fuel [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 5,947 | [2] | 5,196 | [2] |
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 | [2] | ||
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 | [2] | ||
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 | 1,404 | 1,129 | ||
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 | 295 | [5] | 400 | [5] |
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 | 31 years | [5] | ||
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 | 6 years | [5] | ||
Commonwealth Edison Co [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 19,225 | 17,850 | ||
Less: accumulated depreciation | 3,432 | 3,184 | ||
Property, plant and equipment, net | 15,793 | 14,666 | ||
Buildings under capital lease | 8 | |||
Original cost basis for buildings | 8 | |||
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 18,884 | 17,334 | ||
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 80 years | |||
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 5 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 | 276 | 456 | ||
Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 65 | [6] | 60 | [6] |
Commonwealth Edison 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 | [6] | ||
Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 39 years | [6] | ||
PECO Energy Co [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 9,718 | 9,319 | ||
Less: accumulated depreciation | 2,917 | 2,935 | ||
Property, plant and equipment, net | 6,801 | 6,384 | ||
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 6,886 | 6,669 | ||
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 65 years | |||
PECO Energy Co [Member] | Electric Transmission and 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] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 2,039 | 1,932 | ||
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] | Gas Distribution 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] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 618 | 600 | ||
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] | 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] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 154 | 101 | ||
PECO Energy Co [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 50 years | [7] | ||
Total property, plant and equipment | 21 | [7] | 17 | [7] |
Baltimore Gas and Electric Company [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 9,072 | 8,566 | ||
Less: accumulated depreciation | 2,868 | 2,702 | ||
Property, plant and equipment, net | 6,204 | 5,864 | ||
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 6,339 | 6,100 | ||
Baltimore Gas and Electric Company [Member] | Electric Transmission and 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] | Electric Transmission and 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] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 1,761 | 1,660 | ||
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] | 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] | Common Electric And Gas T And D Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 623 | 578 | ||
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 | 40 years | |||
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] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total property, plant and equipment | 317 | 196 | ||
Baltimore Gas and Electric Company [Member] | Other Capitalized Property Plant and Equipment [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Property, plant and equipment, useful life | 20 years | [7] | ||
Total property, plant and equipment | $32 | [7] | $32 | [7] |
[1] | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | |||
[2] | Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively. | |||
[3] | Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation. | |||
[4] | Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively. | |||
[5] | Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities. | |||
[6] | Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. | |||
[7] | Represents land held for future use and non utility property. |
Property_Plant_and_Equipment_A
Property, Plant and Equipment - Annual Depreciation Provisions as Percentage of Average Service Life (Details) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Electric Transmission and Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 2.93% | 2.91% | 2.76% |
Electric Generation Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 3.50% | 3.35% | 3.15% |
Gas Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 2.13% | 2.06% | 2.03% |
Common Electric And Gas T And D Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 7.32% | 7.53% | 7.61% |
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 2.55% | 2.73% | 2.51% |
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 1.84% | 1.79% | 1.77% |
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 5.16% | 6.65% | 7.54% |
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 2.96% | 2.91% | 2.92% |
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 2.47% | 2.36% | 2.33% |
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 9.49% | 8.45% | 7.68% |
Property_Plant_and_Equipment_N
Property, Plant and Equipment - Narrative (Details) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Electric Generation Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 3.50% | 3.35% | 3.15% |
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 3.50% | 3.35% | 3.15% |
Commonwealth Edison Co [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Annual depreciation rate | 3.05% | 2.97% | 2.79% |
Impairment_of_Longlived_Assets1
Impairment of Long-lived Assets - Narrative (Details) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | ||||||||
Feb. 26, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | 31-May-14 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2000 | Oct. 31, 2000 | ||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Impairment charges | $24,000,000 | $14,000,000 | ||||||||||
Interest costs incurred | 1,144,000,000 | [1],[2],[3] | 1,423,000,000 | [1],[2],[3] | 1,003,000,000 | [1],[2],[3] | ||||||
Estimated residual value of leased assets | 685,000,000 | 1,465,000,000 | 685,000,000 | 1,600,000,000 | ||||||||
Capital lease net investment in direct financing leases prepayments received | 1,200,000,000 | |||||||||||
Proceeds from termination of direct financing lease investment | 335,000,000 | 335,000,000 | 0 | 0 | ||||||||
Capital leases net investment in direct financing leases writeoff | 336,000,000 | |||||||||||
Pre Tax Loss | 1,000,000 | |||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Carrying amount of long lived assets to be written down | 1,000,000,000 | 75,000,000 | 151,000,000 | 1,000,000,000 | ||||||||
Fair value of impaired assets | 556,000,000 | 32,000,000 | 65,000,000 | 556,000,000 | ||||||||
Impairment charges | 450,000,000 | 43,000,000 | 86,000,000 | |||||||||
Interest costs incurred | 419,000,000 | [1],[2],[3] | 411,000,000 | [1],[2],[3] | 368,000,000 | [1],[2],[3] | ||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Regulatory assets transfer changes | 272,000,000 | 8,000,000 | ||||||||||
Interest costs incurred | 118,000,000 | [1],[3] | 129,000,000 | [1],[3] | 149,000,000 | [1],[3] | ||||||
Constellation Energy Group LLC [Member] | ||||||||||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Carrying amount of long lived assets to be written down | 163,000,000 | 163,000,000 | ||||||||||
Fair value of impaired assets | 39,000,000 | 39,000,000 | ||||||||||
Impairment charges | 124,000,000 | |||||||||||
Operating And Maintenance Expense [Member] | Exelon Generation Co L L C [Member] | ||||||||||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Utilities operating expense, impairments | 111,000,000 | |||||||||||
Interest Expense [Member] | Exelon Generation Co L L C [Member] | ||||||||||||
Capital Leases Net Investment In Direct Financing Leases [Line Items] | ||||||||||||
Interest costs incurred | $8,000,000 | |||||||||||
[1] | 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 year ended December 31, 2012. | |||||||||||
[2] | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014. | |||||||||||
[3] | Includes interest expense to affiliates. |
Impairment_of_Longlived_Assets2
Impairment of Long-lived Assets - Components of Net Investment in Long-term Leases (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 31, 2000 |
In Millions, unless otherwise specified | |||
Impairment or Disposal of Tangible Assets Disclosure [Abstract] | |||
Estimated residual value of leased assets | $685 | $1,465 | $1,600 |
Less: unearned income | 324 | 767 | |
Net investment in long-term leases | $361 | $698 |
Jointly_Owned_Electric_Utility2
Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Substation capacity | 500,000 | |||
Salem [Member] | ||||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Substation capacity | 500,000 | |||
Conemaugh [Member] | ||||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Substation capacity | 500,000 | |||
Pennsylvania [Member] | ||||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Miles of transmission voltage lines | 127 | |||
Transmission line capacity | 500,000 | |||
Delaware And New Jersey [Member] | ||||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Miles of transmission voltage lines | 131 | |||
Substation capacity | 500,000 | |||
Exelon Generation Co L L C [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 44.24% | |||
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Quad Cities [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | Generation | |||
Ownership interest | 75.00% | |||
Plant | $995 | [1] | $941 | [2] |
Accumulated depreciation | 266 | [1] | 226 | [2] |
Construction work in progress | 15 | 27 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 995 | [1] | 941 | [2] |
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Peach Bottom [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | Generation | |||
Ownership interest | 50.00% | |||
Plant | 1,095 | [1] | 883 | [2] |
Accumulated depreciation | 343 | [1] | 326 | [2] |
Construction work in progress | 133 | 174 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 1,095 | [1] | 883 | [2] |
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Salem [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | PSEG Nuclear | [3] | ||
Ownership interest | 42.59% | [3] | ||
Plant | 531 | [2],[3] | 501 | [2],[3] |
Accumulated depreciation | 150 | [2],[3] | 134 | [2],[3] |
Construction work in progress | 29 | [3] | 24 | [3] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 531 | [2],[3] | 501 | [2],[3] |
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 | [2] | ||
Ownership interest | 0.00% | [2] | ||
Plant | 0 | [1],[2] | 725 | [1],[2] |
Accumulated depreciation | 0 | [1],[2] | 268 | [1],[2] |
Construction work in progress | 0 | [2] | 6 | [2] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 0 | [1],[2] | 725 | [1],[2] |
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Conemaugh [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | GenOn | [2] | ||
Ownership interest | 0.00% | [2] | ||
Plant | 0 | [1],[2] | 399 | [1],[2] |
Accumulated depreciation | 0 | [1],[2] | 220 | [1],[2] |
Construction work in progress | 0 | [2] | 121 | [2] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 0 | [1],[2] | 399 | [1],[2] |
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 | |||
Ownership interest | 5.89% | |||
Plant | 3 | [1],[2] | 3 | [1],[2] |
Accumulated depreciation | 3 | [1],[2] | 3 | [1],[2] |
Construction work in progress | 0 | 0 | ||
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 3 | [1],[2] | 3 | [1],[2] |
Exelon Generation Co L L C [Member] | Other Service [Member] | Other Locations [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | [1] | |||
Ownership interest | 44.24% | [1] | ||
Plant | 2 | [1],[2] | 2 | [1],[2] |
Accumulated depreciation | 1 | [1],[2] | 1 | [1],[2] |
Construction work in progress | 0 | [1] | 0 | [1] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 2 | [1],[2] | 2 | [1],[2] |
PECO Energy Co [Member] | Salem [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 42.55% | |||
PECO Energy Co [Member] | Conemaugh [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 20.70% | |||
PECO Energy Co [Member] | Pennsylvania [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 22.00% | |||
PECO Energy Co [Member] | Delaware And New Jersey [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 42.55% | |||
PECO Energy Co [Member] | Electric Transmission [Member] | Pennsylvania [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | First Energy | [4] | ||
Plant | 14 | [2],[4] | 14 | [2],[4] |
Accumulated depreciation | 7 | [2],[4] | 7 | [2],[4] |
Construction work in progress | 0 | [4] | 0 | [4] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | 14 | [2],[4] | 14 | [2],[4] |
PECO Energy Co [Member] | Electric Transmission [Member] | Delaware And New Jersey [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Operator | PSEG | [5] | ||
Ownership interest | 42.55% | [5] | ||
Plant | 64 | [2],[5] | 64 | [2],[5] |
Accumulated depreciation | 34 | [2],[5] | 34 | [2],[5] |
Construction work in progress | 0 | [5] | 0 | [5] |
Jointly Owned Utility Plant Footnote [Abstract] | ||||
Plant | $64 | [2],[5] | $64 | [2],[5] |
Baltimore Gas and Electric Company [Member] | Conemaugh [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 10.56% | |||
Baltimore Gas and Electric Company [Member] | Pennsylvania [Member] | ||||
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract] | ||||
Ownership interest | 7.00% | |||
[1] | Excludes asset retirement costs. | |||
[2] | As of December 31, 2014, Generation sold its ownership interest in Keystone and Conemaugh. At December 31, 2013, Generation held 41.98% and 31.28% ownership interest in Keystone and Conemaugh, respectively. See Note 4—Mergers, Acquisitions, and Dispositions for additional information. | |||
[3] | 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, 2014 and 2013. | |||
[4] | PECO owns a 42.55% share in 131 miles of 500kV 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. | |||
[5] | Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey. |
Intangible_Assets_Schedule_of_
Intangible Assets - Schedule of Goodwill (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | |
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | $2,625 | ||
Goodwill from business combination | 47 | ||
Goodwill, ending balance | 2,672 | ||
Commonwealth Edison Co [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 2,625 | ||
Goodwill from business combination | 0 | ||
Goodwill, ending balance | 2,625 | ||
Exelon Generation Co L L C [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 0 | ||
Goodwill, ending balance | 47 | 0 | |
Goodwill Gross [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 4,608 | ||
Goodwill from business combination | 47 | ||
Goodwill, ending balance | 4,655 | ||
Goodwill Gross [Member] | Commonwealth Edison Co [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 4,608 | [1] | |
Goodwill from business combination | 0 | ||
Goodwill, ending balance | 4,608 | [1] | |
Goodwill Gross [Member] | Exelon Generation Co L L C [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 0 | ||
Goodwill from business combination | 47 | ||
Goodwill, ending balance | 47 | ||
Goodwill Accumulated Impairment Losses [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 1,983 | ||
Goodwill from business combination | 0 | ||
Goodwill, ending balance | 1,983 | ||
Goodwill Accumulated Impairment Losses [Member] | Commonwealth Edison Co [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 1,983 | ||
Goodwill from business combination | 0 | ||
Goodwill, ending balance | 1,983 | ||
Goodwill Accumulated Impairment Losses [Member] | Exelon Generation Co L L C [Member] | |||
Goodwill [Roll Forward] | |||
Goodwill, beginning balance | 0 | ||
Goodwill from business combination | 47 | ||
Goodwill, ending balance | $47 | ||
[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. |
Intangible_Assets_Narrative_De
Intangible Assets - Narrative (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | $179 | [1] | $478 | [1] | $1,150 | [1] |
Finite lived intangible assets gross | 2,489 | |||||
Commonwealth Edison Co [Member] | ||||||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | 7 | 7 | 7 | |||
Current alternative or renewable energy credits | 4 | 3 | ||||
Exelon Generation Co L L C [Member] | ||||||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | 179 | [1] | 550 | [1] | 1,145 | [1] |
Current alternative or renewable energy credits | 191 | 158 | ||||
Noncurrent alternative or renewable energy credits | 44 | |||||
PECO Energy Co [Member] | ||||||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | 0 | [2] | 0 | [2] | 0 | [2] |
Current alternative or renewable energy credits | 13 | 19 | ||||
Noncurrent alternative or renewable energy credits | 5 | |||||
Unamortized Energy Contracts [Member] | ||||||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | 135 | [3],[4] | 430 | [3],[4] | 1,110 | [3],[4] |
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member] | ||||||
Goodwill [Line Items] | ||||||
Amortization of Intangible Assets | 135 | [3],[4] | 507 | [3],[4] | 1,110 | [2] |
Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member] | ||||||
Goodwill [Line Items] | ||||||
Finite lived intangible assets gross | 1,499 | |||||
Constellation Energy Group LLC [Member] | Trade Names [Member] | ||||||
Goodwill [Line Items] | ||||||
Useful life | 10 years | |||||
Finite lived intangible assets gross | $243 | |||||
[1] | At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income | |||||
[2] | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | |||||
[3] | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | |||||
[4] | 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. |
Intangible_Assets_Schedule_of_1
Intangible Assets - Schedule of Other Intangible Assets (Details) (USD $) | 12 Months Ended | 1 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Feb. 28, 2003 | Dec. 31, 2010 | Sep. 30, 2011 | |
MW | MW | ||||
Finite-Lived Intangible Assets [Line Items] | |||||
Gross | 2,489 | ||||
Accumulated Amortization | -1,751 | ||||
Net | 738 | ||||
2015 | 66 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 39 | ||||
2017 | 40 | ||||
2018 | 69 | ||||
2019 | 67 | ||||
Other miscellaneous unamortized energy contracts | 26 | ||||
Exelon Generation Co L L C [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 10 years | ||||
Commonwealth Edison Co [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Chicago payment made to city | 60 | ||||
Period for payment | 10 years | ||||
City of Chicago payment made to 3rd party | -2 | ||||
City of Chicago payment received | 32 | ||||
Reduction of amortization expense | -2 | ||||
Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 21 years 9 months 18 days | [1],[2] | |||
Gross | 100 | [1] | |||
Accumulated Amortization | -79 | [1] | |||
Net | 21 | [1] | |||
2015 | 3 | [1] | |||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 3 | [1] | |||
2017 | 4 | [1] | |||
2018 | 4 | [1] | |||
2019 | 4 | [1] | |||
Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 17 years 10 months 24 days | [2],[3] | |||
Gross | 62 | [3] | |||
Accumulated Amortization | -40 | [3] | |||
Net | 22 | [3] | |||
2015 | 4 | [3] | |||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 4 | [3] | |||
2017 | 3 | [3] | |||
2018 | 3 | [3] | |||
2019 | 3 | [3] | |||
Exelon Generation Co L L C [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
2015 | 4 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 3 | ||||
2017 | 0 | ||||
2018 | 2 | ||||
2019 | 2 | ||||
Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Wind turbine supply megawatt | 735 | ||||
Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 18 years | [2],[4],[5] | |||
Gross | 224 | [4],[5] | |||
Accumulated Amortization | -55 | [4],[5] | |||
Net | 169 | ||||
2015 | 14 | [4],[5] | |||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 14 | [4],[5] | |||
2017 | 14 | [4],[5] | |||
2018 | 14 | [4],[5] | |||
2019 | 14 | [4],[5] | |||
Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Wind turbine supply megawatt | 230 | ||||
Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 25 years | [2],[4],[6] | |||
Gross | 190 | [4],[6] | |||
Accumulated Amortization | -12 | [4],[6] | |||
Net | 178 | ||||
2015 | 8 | [4],[6] | |||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 8 | [4],[6] | |||
2017 | 8 | [4],[6] | |||
2018 | 8 | [4],[6] | |||
2019 | 8 | [4],[6] | |||
Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 1 year 5 months 24 days | ||||
Gross | 1,499 | ||||
Accumulated Amortization | -1,451 | ||||
Net | 48 | ||||
2015 | 19 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | -31 | ||||
2017 | -21 | ||||
2018 | 11 | ||||
2019 | 8 | ||||
Constellation Energy Group LLC [Member] | Trade Names [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 10 years | ||||
Gross | 243 | ||||
Accumulated Amortization | -79 | ||||
Net | 164 | ||||
2015 | 23 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 23 | ||||
2017 | 23 | ||||
2018 | 23 | ||||
2019 | 23 | ||||
Constellation Energy Group LLC [Member] | Customer Relationships [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 12 years 4 months 24 days | ||||
Gross | 214 | ||||
Accumulated Amortization | -58 | ||||
Net | 156 | ||||
2015 | 18 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 18 | ||||
2017 | 18 | ||||
2018 | 18 | ||||
2019 | 17 | ||||
CENG [Member] | Unamortized Energy Contracts [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 1 year 8 months 12 days | ||||
Gross | -97 | ||||
Accumulated Amortization | 29 | ||||
Net | -68 | ||||
2015 | -20 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | -11 | ||||
2017 | -15 | ||||
2018 | -18 | ||||
2019 | -15 | ||||
Integrys [Member] | Unamortized Energy Contracts [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 2 years 4 months 24 days | ||||
Gross | 6 | ||||
Accumulated Amortization | -5 | ||||
Net | 1 | ||||
2015 | -8 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 6 | ||||
2017 | 1 | ||||
2018 | 1 | ||||
2019 | 0 | ||||
Integrys [Member] | Customer Relationships [Member] | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Weighted-average amortization period | 10 years | ||||
Gross | 48 | ||||
Accumulated Amortization | -1 | ||||
Net | 47 | ||||
2015 | 5 | ||||
Finite-Lived Intangible Assets, Amortization Expense, Year Two | 5 | ||||
2017 | 5 | ||||
2018 | 5 | ||||
2019 | 5 | ||||
[1] | In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc. | ||||
[2] | See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||
[3] | See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions. | ||||
[4] | 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. | ||||
[5] | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | ||||
[6] | In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states. |
Intangible_Assets_Summary_of_A
Intangible Assets - Summary of Amortization Expense (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset amortization expense | $179 | [1] | $478 | [1] | $1,150 | [1] |
Exelon Generation Co L L C [Member] | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset amortization expense | 179 | [1] | 550 | [1] | 1,145 | [1] |
Commonwealth Edison Co [Member] | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset amortization expense | 7 | 7 | 7 | |||
Unamortized Energy Contracts [Member] | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset amortization expense | 135 | [2],[3] | 430 | [2],[3] | 1,110 | [2],[3] |
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member] | ||||||
Finite-Lived Intangible Assets [Line Items] | ||||||
Intangible asset amortization expense | $135 | [2],[3] | $507 | [2],[3] | $1,110 | [4] |
[1] | At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income | |||||
[2] | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | |||||
[3] | 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. | |||||
[4] | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
Fair_Value_of_Financial_Assets2
Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at the Carrying Amount (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | $460 | $341 | ||
Long-term debt (including amounts due within one year) | 441 | 384 | ||
Long-term debt to financing trusts | 648 | 648 | ||
Long-term debt to financing trusts | 648 | 648 | ||
Spent Nuclear Fuel Obligation, Noncurrent | 1,021 | 1,021 | ||
Reported Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 463 | 344 | ||
Long-term debt to financing trusts | 648 | 648 | ||
Debt and Capital Lease Obligations | 21,164 | 19,132 | ||
Spent Nuclear Fuel Obligation, Noncurrent | 1,021 | 1,021 | ||
Estimate of Fair Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 463 | 344 | ||
Long-term debt (including amounts due within one year) | 22,936 | 19,751 | ||
Long-term debt to financing trusts | 648 | 631 | ||
SNF obligation | 833 | 790 | ||
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 3 | |||
Long-term debt (including amounts due within one year) | 1,208 | |||
Long-term debt to financing trusts | 0 | |||
SNF obligation | 0 | |||
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 448 | |||
Long-term debt (including amounts due within one year) | 20,417 | |||
Long-term debt to financing trusts | 0 | |||
SNF obligation | 833 | |||
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 12 | |||
Long-term debt (including amounts due within one year) | 1,311 | |||
Long-term debt to financing trusts | 648 | |||
SNF obligation | 0 | |||
Exelon Generation Co L L C [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 36 | 22 | ||
Long-term debt (including amounts due within one year) | 146 | 166 | ||
Long-term debt to financing trusts | 943 | 1,523 | ||
Debt and Capital Lease Obligations | 7,652 | 7,168 | ||
Spent Nuclear Fuel Obligation, Noncurrent | 1,021 | 1,021 | ||
Exelon Generation Co L L C [Member] | Reported Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 36 | 22 | ||
Debt and Capital Lease Obligations | 8,266 | 7,729 | ||
Spent Nuclear Fuel Obligation, Noncurrent | 1,021 | 1,021 | ||
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 36 | 22 | ||
Long-term debt (including amounts due within one year) | 8,822 | 7,648 | ||
SNF obligation | 833 | 790 | ||
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 0 | |||
Long-term debt (including amounts due within one year) | 0 | |||
SNF obligation | 0 | |||
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 24 | |||
Long-term debt (including amounts due within one year) | 7,511 | |||
SNF obligation | 833 | |||
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 12 | |||
Long-term debt (including amounts due within one year) | 1,311 | |||
SNF obligation | 0 | |||
Commonwealth Edison Co [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 304 | 184 | ||
Long-term debt to financing trusts | 206 | 206 | ||
Debt and Capital Lease Obligations | 5,698 | 5,058 | ||
Commonwealth Edison Co [Member] | Reported Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 304 | 184 | ||
Long-term debt to financing trusts | 206 | 206 | ||
Debt and Capital Lease Obligations | 5,958 | 5,675 | ||
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 304 | 184 | ||
Long-term debt (including amounts due within one year) | 6,788 | 6,255 | ||
Long-term debt to financing trusts | 213 | 202 | ||
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 0 | |||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | 0 | |||
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 304 | |||
Long-term debt (including amounts due within one year) | 6,788 | |||
Long-term debt to financing trusts | 0 | |||
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 0 | |||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | 213 | |||
PECO Energy Co [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt to financing trusts | 184 | [1] | 184 | [1] |
Debt and Capital Lease Obligations | 2,246 | 1,947 | ||
Long-term debt to financing trusts | 184 | 184 | ||
PECO Energy Co [Member] | Reported Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt to financing trusts | 184 | 184 | ||
Debt and Capital Lease Obligations | 2,246 | 2,197 | ||
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt (including amounts due within one year) | 2,537 | 2,358 | ||
Long-term debt to financing trusts | 199 | 180 | ||
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | 0 | |||
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt (including amounts due within one year) | 2,537 | |||
Long-term debt to financing trusts | 0 | |||
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | 199 | |||
Baltimore Gas and Electric Company [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 120 | 135 | ||
Long-term debt to financing trusts | 258 | 258 | ||
Debt and Capital Lease Obligations | 2,011 | |||
Baltimore Gas and Electric Company [Member] | Reported Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term Debt | 123 | 138 | ||
Long-term debt to financing trusts | 258 | |||
Debt and Capital Lease Obligations | 1,942 | |||
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 123 | 138 | ||
Long-term debt (including amounts due within one year) | 2,178 | 2,148 | ||
Long-term debt to financing trusts | 236 | 249 | ||
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 3 | |||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | 0 | |||
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 120 | |||
Long-term debt (including amounts due within one year) | 2,178 | |||
Long-term debt to financing trusts | 0 | |||
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Short-term liabilities | 0 | |||
Long-term debt (including amounts due within one year) | 0 | |||
Long-term debt to financing trusts | $236 | |||
[1] | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. |
Fair_Value_of_Financial_Assets3
Fair Value of Financial Assets and Liabilities - Fair Value Measurement of Assets and Liabilities, Recurring and Nonrecurring (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | $1,119 | [1] | $1,230 | [1] |
Rabbi trust investments subtotal | [2] | |||
Other investments | 5 | 15 | ||
Total assets | 14,081 | 11,162 | ||
Deferred compensation obligation | -107 | -114 | ||
Total liabilities | -744 | -573 | ||
Total net assets | 13,337 | 10,589 | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 35 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | 403 | 300 | ||
Mark-to-market derivative liabilities (current liabilities) | 234 | 159 | ||
Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 31 | |||
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -41 | |||
Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 13 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | 289 | 285 | ||
Mark-to-market derivative liabilities (current liabilities) | 235 | 158 | ||
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -103 | |||
Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 27 | |||
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -23 | |||
Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 245 | 459 | ||
Equity | 4,630 | 3,913 | ||
Foreign | 612 | 249 | ||
Equity funds subtotal | 5,242 | 4,162 | ||
Corporate debt securities | 2,262 | 1,784 | ||
U.S. Treasury and agencies | 996 | 882 | ||
Foreign governments | 95 | 87 | ||
State and municipal debt | 438 | 294 | ||
Other | 511 | 75 | ||
Fixed income subtotal | 4,302 | 3,122 | ||
Middle market lending | 366 | 314 | ||
Private equity | 83 | 5 | ||
Real estate | 3 | |||
Other | 301 | 14 | ||
Nuclear decommissioning trust fund investments subtotal | 10,542 | [3] | 8,076 | [3] |
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | -5 | |||
Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 15 | 26 | ||
Equity | 7 | 16 | ||
Corporate debt securities | 89 | 227 | ||
U.S. Treasury and agencies | 8 | 49 | ||
State and municipal debt | 10 | 20 | ||
Other | 3 | |||
Fixed income subtotal | 110 | 296 | ||
Middle market lending | 184 | 112 | ||
Other | 1 | |||
Pledged assets for Zion Station decommissioning subtotal | 316 | [4] | 451 | [4] |
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments | 3 | 7 | ||
Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1 | [2] | 2 | [2] |
Mutual funds | 46 | [2],[5] | 54 | [2],[5] |
Rabbi trust investments subtotal | 47 | [2] | 56 | [2] |
Deferred compensation obligation | -45 | -53 | ||
Supplemental executive retirement plan fair value | 1 | 1 | ||
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 11 | 32 | ||
Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 6,813 | 3,960 | ||
Proprietary trading | 512 | 1,761 | ||
Effect of netting and allocation of collateral received/(paid) | 5,296 | [6] | 4,424 | [6] |
Commodity derivative subtotal | 2,029 | 1,297 | ||
Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -48 | -32 | ||
Interest rate and foreign currency derivative | -69 | |||
Interest rate and foreign currency derivatives subtotal | -23 | -37 | ||
Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -6,694 | -3,020 | ||
Proprietary trading | -532 | -1,703 | ||
Effect of netting and allocation of collateral received/(paid) | -6,702 | [6] | -4,280 | [6] |
Commodity derivative subtotal | -524 | -443 | ||
Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -54 | -32 | ||
Interest rate and foreign currency derivative | 0 | -48 | ||
Interest rate and foreign currency derivatives subtotal | -113 | -16 | ||
Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1,119 | [1] | 1,230 | [1] |
Other investments | 2 | 0 | ||
Total assets | 5,305 | 4,533 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | -9 | 1 | ||
Total net assets | 5,296 | 4,534 | ||
Collateral received from counterparties, net of collateral paid to counterparties | 434 | 6 | ||
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 18 | |||
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -14 | |||
Fair Value, Inputs, Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 208 | 459 | ||
Equity | 2,423 | 1,642 | ||
Foreign | 612 | 249 | ||
Equity funds subtotal | 3,035 | 1,891 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 996 | 882 | ||
Foreign governments | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | 0 | ||
Fixed income subtotal | 996 | 882 | ||
Middle market lending | 0 | 0 | ||
Private equity | 0 | 0 | ||
Real estate | 0 | |||
Other | 0 | 0 | ||
Nuclear decommissioning trust fund investments subtotal | 4,239 | [3] | 3,232 | [3] |
Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 6 | 16 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 5 | 45 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | |||
Fixed income subtotal | 5 | 45 | ||
Middle market lending | 0 | 0 | ||
Other | 0 | |||
Pledged assets for Zion Station decommissioning subtotal | 11 | [4] | 61 | [4] |
Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 1 | [2] | 2 | [2] |
Mutual funds | 46 | [2],[5] | 54 | [2],[5] |
Rabbi trust investments subtotal | 47 | [2] | 56 | [2] |
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 1,667 | 493 | ||
Proprietary trading | 201 | 324 | ||
Effect of netting and allocation of collateral received/(paid) | 1,982 | [6] | 863 | [6] |
Commodity derivative subtotal | -114 | -46 | ||
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -17 | -30 | ||
Interest rate and foreign currency derivative | -30 | |||
Interest rate and foreign currency derivatives subtotal | -1 | 0 | ||
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -2,241 | -540 | ||
Proprietary trading | -195 | -328 | ||
Effect of netting and allocation of collateral received/(paid) | -2,416 | [6] | -869 | [6] |
Commodity derivative subtotal | -20 | 1 | ||
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -25 | -31 | ||
Interest rate and foreign currency derivative | 0 | -31 | ||
Interest rate and foreign currency derivatives subtotal | 11 | 0 | ||
Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [1] |
Other investments | 0 | 0 | ||
Total assets | 6,747 | 5,575 | ||
Deferred compensation obligation | -107 | -114 | ||
Total liabilities | -427 | -269 | ||
Total net assets | 6,320 | 5,306 | ||
Collateral received from counterparties, net of collateral paid to counterparties | 800 | -124 | ||
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 31 | |||
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -41 | |||
Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 13 | |||
Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -103 | |||
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 9 | |||
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -9 | |||
Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 37 | 0 | ||
Equity | 2,207 | 2,271 | ||
Foreign | 0 | 0 | ||
Equity funds subtotal | 2,207 | 2,271 | ||
Corporate debt securities | 2,023 | 1,753 | ||
U.S. Treasury and agencies | 0 | 0 | ||
Foreign governments | 95 | 87 | ||
State and municipal debt | 438 | 294 | ||
Other | 511 | 75 | ||
Fixed income subtotal | 3,067 | 2,209 | ||
Middle market lending | 0 | 0 | ||
Private equity | 0 | 0 | ||
Real estate | 0 | |||
Other | 301 | 14 | ||
Nuclear decommissioning trust fund investments subtotal | 5,612 | [3] | 4,494 | [3] |
Fair Value, Inputs, Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 15 | 26 | ||
Equity | 1 | 0 | ||
Corporate debt securities | 89 | 227 | ||
U.S. Treasury and agencies | 3 | 4 | ||
State and municipal debt | 10 | 20 | ||
Other | 3 | |||
Fixed income subtotal | 105 | 251 | ||
Middle market lending | 0 | 0 | ||
Other | 1 | |||
Pledged assets for Zion Station decommissioning subtotal | 121 | [4] | 278 | [4] |
Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 0 | [2],[5] | 0 | [2],[5] |
Rabbi trust investments subtotal | 0 | [2] | 0 | [2] |
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 3,465 | 2,582 | ||
Proprietary trading | 284 | 1,315 | ||
Effect of netting and allocation of collateral received/(paid) | 2,757 | [6] | 3,131 | [6] |
Commodity derivative subtotal | 992 | 766 | ||
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -31 | -2 | ||
Interest rate and foreign currency derivative | -39 | |||
Interest rate and foreign currency derivatives subtotal | -22 | -37 | ||
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -3,458 | -1,890 | ||
Proprietary trading | -295 | -1,256 | ||
Effect of netting and allocation of collateral received/(paid) | -3,557 | [6] | -3,007 | [6] |
Commodity derivative subtotal | -196 | -139 | ||
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -29 | -1 | ||
Interest rate and foreign currency derivative | 0 | -17 | ||
Interest rate and foreign currency derivatives subtotal | -124 | -16 | ||
Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [1] |
Other investments | 3 | 15 | ||
Total assets | 2,029 | 1,054 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | -308 | -305 | ||
Total net assets | 1,721 | 749 | ||
Collateral received from counterparties, net of collateral paid to counterparties | 172 | -26 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 176 | |||
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 0 | 0 | ||
Foreign | 0 | 0 | ||
Equity funds subtotal | 0 | 0 | ||
Corporate debt securities | 239 | 31 | ||
U.S. Treasury and agencies | 0 | 0 | ||
Foreign governments | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | 0 | ||
Fixed income subtotal | 239 | 31 | ||
Middle market lending | 366 | 314 | ||
Private equity | 83 | 5 | ||
Real estate | 3 | |||
Other | 0 | 0 | ||
Nuclear decommissioning trust fund investments subtotal | 691 | [3] | 350 | [3] |
Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 0 | 0 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | |||
Fixed income subtotal | 0 | 0 | ||
Middle market lending | 184 | 112 | ||
Other | 0 | |||
Pledged assets for Zion Station decommissioning subtotal | 184 | [4] | 112 | [4] |
Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 0 | [2],[5] | 0 | [2],[5] |
Rabbi trust investments subtotal | 0 | [2] | 0 | [2] |
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 1,681 | 885 | ||
Proprietary trading | 27 | 122 | ||
Effect of netting and allocation of collateral received/(paid) | 557 | [6] | 430 | [6] |
Commodity derivative subtotal | 1,151 | 577 | ||
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | 0 | 0 | ||
Interest rate and foreign currency derivative | 0 | |||
Interest rate and foreign currency derivatives subtotal | 0 | 0 | ||
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -995 | -590 | ||
Proprietary trading | -42 | -119 | ||
Effect of netting and allocation of collateral received/(paid) | -729 | [6] | -404 | [6] |
Commodity derivative subtotal | -308 | -305 | ||
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | 0 | 0 | ||
Interest rate and foreign currency derivative | 0 | 0 | ||
Interest rate and foreign currency derivatives subtotal | 0 | 0 | ||
Exelon Generation Co L L C [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 405 | [1] | 1,006 | [1] |
Other investments | 3 | 15 | ||
Total assets | 13,329 | 10,888 | ||
Derivative liabilities | -293 | [7] | -210 | [7] |
Deferred compensation obligation | -31 | -29 | ||
Total liabilities | -350 | -291 | ||
Total net assets | 12,979 | 10,597 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 105 | 120 | ||
Mark-to-market derivative liabilities (current liabilities) | 214 | 142 | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 8 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | 1,540 | 804 | ||
Mark-to-market derivative liabilities (current liabilities) | 4,947 | 2,023 | ||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -12 | |||
Exelon Generation Co L L C [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 12 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | 102 | [8] | 109 | [9] |
Mark-to-market derivative liabilities (current liabilities) | 215 | [8] | 141 | [9] |
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -2 | |||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 27 | |||
Mark-to-market derivative liabilities (current liabilities) | 2 | |||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -23 | |||
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 245 | 459 | ||
Equity | 4,630 | 3,913 | ||
Foreign | 612 | 249 | ||
Equity funds subtotal | 5,242 | 4,162 | ||
Corporate debt securities | 2,262 | 1,784 | ||
U.S. Treasury and agencies | 996 | 882 | ||
Foreign governments | 95 | 87 | ||
State and municipal debt | 438 | 294 | ||
Other | 511 | 75 | ||
Fixed income subtotal | 4,302 | 3,122 | ||
Middle market lending | 366 | 314 | ||
Private equity | 83 | 5 | ||
Real estate | 3 | |||
Other | 301 | 14 | ||
Nuclear decommissioning trust fund investments subtotal | 10,542 | [3] | 8,076 | [3] |
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 15 | 26 | ||
Equity | 7 | 16 | ||
Corporate debt securities | 89 | 227 | ||
U.S. Treasury and agencies | 8 | 49 | ||
State and municipal debt | 10 | 20 | ||
Other | 3 | |||
Fixed income subtotal | 110 | 296 | ||
Middle market lending | 184 | 112 | ||
Other | 1 | |||
Pledged assets for Zion Station decommissioning subtotal | 316 | [4] | 451 | [4] |
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 16 | [2],[5] | 13 | [2],[5] |
Rabbi trust investments subtotal | 16 | [2] | 13 | [2] |
Cash surrender value of life insurance investments excluded from Rabbi Trust investments | 10 | |||
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 6,813 | 3,960 | ||
Proprietary trading | 512 | 1,761 | ||
Effect of netting and allocation of collateral received/(paid) | 5,296 | [6] | 4,424 | [6] |
Commodity derivative subtotal | 2,029 | 1,297 | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -29 | -32 | ||
Interest rate and foreign currency derivative | -62 | |||
Interest rate and foreign currency derivatives subtotal | -18 | -30 | ||
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -6,487 | -2,827 | ||
Proprietary trading | -532 | -1,703 | ||
Effect of netting and allocation of collateral received/(paid) | -6,702 | [6] | -4,280 | [6] |
Commodity derivative subtotal | -317 | -250 | ||
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -35 | -32 | ||
Interest rate and foreign currency derivative | 0 | -44 | ||
Interest rate and foreign currency derivatives subtotal | -2 | -12 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 405 | [1] | 1,006 | [1] |
Other investments | 0 | 0 | ||
Total assets | 4,558 | 4,266 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | -9 | 1 | ||
Total net assets | 4,549 | 4,267 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 18 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -14 | |||
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 and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 208 | 459 | ||
Equity | 2,423 | 1,642 | ||
Foreign | 612 | 249 | ||
Equity funds subtotal | 3,035 | 1,891 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 996 | 882 | ||
Foreign governments | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | 0 | ||
Fixed income subtotal | 996 | 882 | ||
Middle market lending | 0 | 0 | ||
Private equity | 0 | 0 | ||
Real estate | 0 | |||
Other | 0 | 0 | ||
Nuclear decommissioning trust fund investments subtotal | 4,239 | [3] | 3,232 | [3] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 6 | 16 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 5 | 45 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | |||
Fixed income subtotal | 5 | 45 | ||
Middle market lending | 0 | 0 | ||
Other | 0 | |||
Pledged assets for Zion Station decommissioning subtotal | 11 | [4] | 61 | [4] |
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 and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 16 | [2],[5] | 13 | [2],[5] |
Rabbi trust investments subtotal | 16 | [2] | 13 | [2] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 1,667 | 493 | ||
Proprietary trading | 201 | 324 | ||
Effect of netting and allocation of collateral received/(paid) | 1,982 | [6] | 863 | [6] |
Commodity derivative subtotal | -114 | -46 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -17 | -30 | ||
Interest rate and foreign currency derivative | -30 | |||
Interest rate and foreign currency derivatives subtotal | -1 | 0 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -2,241 | -540 | ||
Proprietary trading | -195 | -328 | ||
Effect of netting and allocation of collateral received/(paid) | -2,416 | [6] | -869 | [6] |
Commodity derivative subtotal | -20 | 1 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -25 | -31 | ||
Interest rate and foreign currency derivative | 0 | -31 | ||
Interest rate and foreign currency derivatives subtotal | 11 | 0 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [1] |
Other investments | 0 | 0 | ||
Total assets | 6,742 | 5,568 | ||
Deferred compensation obligation | -31 | -29 | ||
Total liabilities | -240 | -180 | ||
Total net assets | 6,502 | 5,388 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 8 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -12 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 12 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -2 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 9 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | -9 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 37 | 0 | ||
Equity | 2,207 | 2,271 | ||
Foreign | 0 | 0 | ||
Equity funds subtotal | 2,207 | 2,271 | ||
Corporate debt securities | 2,023 | 1,753 | ||
U.S. Treasury and agencies | 0 | 0 | ||
Foreign governments | 95 | 87 | ||
State and municipal debt | 438 | 294 | ||
Other | 511 | 75 | ||
Fixed income subtotal | 3,067 | 2,209 | ||
Middle market lending | 0 | 0 | ||
Private equity | 0 | 0 | ||
Real estate | 0 | |||
Other | 301 | 14 | ||
Nuclear decommissioning trust fund investments subtotal | 5,612 | [3] | 4,494 | [3] |
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 and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 15 | 26 | ||
Equity | 1 | 0 | ||
Corporate debt securities | 89 | 227 | ||
U.S. Treasury and agencies | 3 | 4 | ||
State and municipal debt | 10 | 20 | ||
Other | 3 | |||
Fixed income subtotal | 105 | 251 | ||
Middle market lending | 0 | 0 | ||
Other | 1 | |||
Pledged assets for Zion Station decommissioning subtotal | 121 | [4] | 278 | [4] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 0 | [2],[5] | 0 | [2],[5] |
Rabbi trust investments subtotal | 0 | [2] | 0 | [2] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 3,465 | 2,582 | ||
Proprietary trading | 284 | 1,315 | ||
Effect of netting and allocation of collateral received/(paid) | 2,757 | [6] | 3,131 | [6] |
Commodity derivative subtotal | 992 | 766 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -12 | -2 | ||
Interest rate and foreign currency derivative | -32 | |||
Interest rate and foreign currency derivatives subtotal | -17 | -30 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -3,458 | -1,890 | ||
Proprietary trading | -295 | -1,256 | ||
Effect of netting and allocation of collateral received/(paid) | -3,557 | [6] | -3,007 | [6] |
Commodity derivative subtotal | -196 | -139 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | -10 | -1 | ||
Interest rate and foreign currency derivative | 0 | -13 | ||
Interest rate and foreign currency derivatives subtotal | -13 | -12 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [1] | 0 | [1] |
Other investments | 3 | 15 | ||
Total assets | 2,029 | 1,054 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | -101 | -112 | ||
Total net assets | 1,928 | 942 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 0 | 0 | ||
Foreign | 0 | 0 | ||
Equity funds subtotal | 0 | 0 | ||
Corporate debt securities | 239 | 31 | ||
U.S. Treasury and agencies | 0 | 0 | ||
Foreign governments | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | 0 | ||
Fixed income subtotal | 239 | 31 | ||
Middle market lending | 366 | 314 | ||
Private equity | 83 | 5 | ||
Real estate | 3 | |||
Other | 0 | 0 | ||
Nuclear decommissioning trust fund investments subtotal | 691 | [3] | 350 | [3] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Equity | 0 | 0 | ||
Corporate debt securities | 0 | 0 | ||
U.S. Treasury and agencies | 0 | 0 | ||
State and municipal debt | 0 | 0 | ||
Other | 0 | |||
Fixed income subtotal | 0 | 0 | ||
Middle market lending | 184 | 112 | ||
Other | 0 | |||
Pledged assets for Zion Station decommissioning subtotal | 184 | [4] | 112 | [4] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | [2] | 0 | [2] |
Mutual funds | 0 | [2],[5] | 0 | [2],[5] |
Rabbi trust investments subtotal | 0 | [2] | 0 | [2] |
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | 1,681 | 885 | ||
Proprietary trading | 27 | 122 | ||
Effect of netting and allocation of collateral received/(paid) | 557 | [6] | 430 | [6] |
Commodity derivative subtotal | 1,151 | 577 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | 0 | 0 | ||
Interest rate and foreign currency derivative | 0 | |||
Interest rate and foreign currency derivatives subtotal | 0 | 0 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Economic hedges | -788 | -397 | ||
Proprietary trading | -42 | -119 | ||
Effect of netting and allocation of collateral received/(paid) | -729 | [6] | -404 | [6] |
Commodity derivative subtotal | -101 | -112 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Effect of netting and allocation of collateral received/(paid) | 0 | 0 | ||
Interest rate and foreign currency derivative | 0 | 0 | ||
Interest rate and foreign currency derivatives subtotal | 0 | 0 | ||
Commonwealth Edison Co [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 25 | 0 | ||
Commodity derivative subtotal | -207 | [10] | -193 | [10] |
Total assets | 25 | 5 | ||
Deferred compensation obligation | -8 | -8 | ||
Total liabilities | -215 | -201 | ||
Total net assets | -190 | -196 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 187 | 176 | ||
Mark-to-market derivative liabilities (current liabilities) | 20 | 17 | ||
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mark-to-market derivative liabilities (noncurrent liabilities) | 187 | [11] | 176 | [11] |
Mark-to-market derivative liabilities (current liabilities) | 20 | [11] | 17 | [11] |
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 5 | [12] |
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 25 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 25 | 5 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | 0 | 0 | ||
Total net assets | 25 | 5 | ||
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 5 | [12] |
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | -8 | -8 | ||
Total liabilities | -8 | -8 | ||
Total net assets | -8 | -8 | ||
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 0 | [12] |
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | -207 | [10] | -193 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | -207 | -193 | ||
Total net assets | -207 | -193 | ||
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 0 | [12] |
PECO Energy Co [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 12 | 175 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 21 | 184 | ||
Deferred compensation obligation | -15 | -17 | ||
Total liabilities | -15 | -17 | ||
Total net assets | 6 | 167 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 14 | |||
PECO Energy Co [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 9 | [12] | 9 | [12] |
PECO Energy Co [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 12 | 175 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 21 | 184 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | 0 | 0 | ||
Total net assets | 21 | 184 | ||
PECO Energy Co [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 9 | [12] | 9 | [12] |
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | -15 | -17 | ||
Total liabilities | -15 | -17 | ||
Total net assets | -15 | -17 | ||
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 0 | [12] |
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | 0 | 0 | ||
Total net assets | 0 | 0 | ||
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 0 | [12] |
Baltimore Gas and Electric Company [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 103 | 31 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 108 | 37 | ||
Deferred compensation obligation | -5 | -6 | ||
Total liabilities | -5 | -6 | ||
Total net assets | 103 | 31 | ||
Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 5 | [12] | 6 | [12] |
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 1 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 103 | 31 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 108 | 37 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | 0 | 0 | ||
Total net assets | 108 | 37 | ||
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 5 | [12] | 6 | [12] |
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | -5 | -6 | ||
Total liabilities | -5 | -6 | ||
Total net assets | -5 | -6 | ||
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | 0 | [12] | 0 | [12] |
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash equivalents | 0 | 0 | ||
Commodity derivative subtotal | 0 | [10] | 0 | [10] |
Total assets | 0 | 0 | ||
Deferred compensation obligation | 0 | 0 | ||
Total liabilities | 0 | 0 | ||
Total net assets | 0 | 0 | ||
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Mutual funds | $0 | [12] | $0 | [12] |
[1] | Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value. | |||
[2] | The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013. | |||
[3] | Excludes net liabilities of $5 million at both December 31, 2014 and 2013. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||
[4] | Excludes net assets of $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. | |||
[5] | Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation. | |||
[6] | Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014. Collateral posted (received) to/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. | |||
[7] | (c)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. | |||
[8] | Current and noncurrent assets are shown net of collateral of $(416) million and $(171) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(599) million and $(220) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014. | |||
[9] | Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. 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. | |||
[10] | The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||
[11] | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. | |||
[12] | At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013 |
Fair_Value_of_Financial_Assets4
Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Ending balance | ||||
Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 749 | 656 | ||
Included in net income | 532 | -42 | ||
Included in other comprehensive income | 2 | |||
Included in noncurrent payables to affiliates | 0 | |||
Included in payable for Zion Station decommissioning | -2 | 0 | ||
Included in regulatory assets/liabilities | 0 | [1] | -118 | [1] |
Change in collateral | 198 | 7 | ||
Purchases | 598 | 297 | ||
Sales | -80 | -86 | ||
Settlements | -64 | -18 | ||
Transfers into Level 3 - (Asset) / Liability | 7 | -87 | ||
Transfers out of Level 3 - (Asset) / Liability | -207 | -36 | ||
Ending balance | 1,721 | 749 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 644 | 168 | ||
Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 350 | |||
Included in net income | 6 | |||
Included in payable for Zion Station decommissioning | 0 | |||
Change in collateral | 0 | |||
Purchases | 400 | 203 | ||
Sales | -15 | -28 | ||
Settlements | -64 | -18 | ||
Transfers into Level 3 - (Asset) / Liability | 0 | 0 | ||
Transfers out of Level 3 - (Asset) / Liability | 0 | 0 | ||
Ending balance | 691 | 350 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 4 | 1 | ||
Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 112 | |||
Purchases | 62 | |||
Sales | -50 | -39 | ||
Settlements | 0 | 0 | ||
Transfers into Level 3 - (Asset) / Liability | 0 | 0 | ||
Transfers out of Level 3 - (Asset) / Liability | 0 | 0 | ||
Ending balance | 184 | 112 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 0 | 0 | ||
Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 465 | |||
Purchases | 76 | [2] | 28 | |
Sales | -7 | -11 | ||
Settlements | 0 | 0 | ||
Transfers into Level 3 - (Asset) / Liability | 7 | -86 | [1] | |
Transfers out of Level 3 - (Asset) / Liability | -201 | -35 | ||
Ending balance | 1,050 | 465 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 640 | 156 | ||
Fair Value, Inputs, Level 3 [Member] | Other Investments [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 15 | |||
Included in noncurrent payables to affiliates | -8 | |||
Included in regulatory assets/liabilities | -218 | |||
Purchases | 2 | 4 | ||
Sales | -8 | -8 | ||
Settlements | 0 | 0 | ||
Transfers into Level 3 - (Asset) / Liability | 0 | -1 | ||
Transfers out of Level 3 - (Asset) / Liability | -6 | -1 | ||
Ending balance | 3 | 15 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 0 | 0 | ||
Exelon Generation Co L L C [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Settlements | -215 | |||
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts | 114 | -207 | ||
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments | 11 | |||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Settlements | -1 | 7 | ||
Exelon Generation Co L L C [Member] | Derivative [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Cash | 34 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 942 | 949 | ||
Included in net income | 532 | -49 | ||
Included in other comprehensive income | -217 | |||
Included in noncurrent payables to affiliates | 8 | |||
Included in payable for Zion Station decommissioning | -2 | 0 | ||
Included in regulatory assets/liabilities | 0 | [1] | ||
Change in collateral | 198 | 7 | ||
Purchases | 598 | 297 | ||
Sales | -80 | -86 | ||
Settlements | -64 | -18 | ||
Transfers into Level 3 - (Asset) / Liability | 7 | -87 | ||
Transfers out of Level 3 - (Asset) / Liability | -207 | -36 | ||
Ending balance | 1,928 | 942 | ||
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 644 | 157 | ||
Decrease in Fair Value Adjustment | 13 | 133 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 183 | |||
Included in net income | 2 | |||
Included in other comprehensive income | 0 | |||
Included in noncurrent payables to affiliates | 14 | |||
Included in payable for Zion Station decommissioning | 0 | |||
Change in collateral | 0 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 89 | |||
Included in net income | 0 | 0 | ||
Included in other comprehensive income | 0 | |||
Included in noncurrent payables to affiliates | 0 | |||
Included in payable for Zion Station decommissioning | -2 | 0 | ||
Included in regulatory assets/liabilities | 0 | [1] | 0 | [1] |
Change in collateral | 0 | 0 | ||
Purchases | 120 | |||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 660 | |||
Included in net income | 526 | -51 | [3],[4] | |
Included in other comprehensive income | -219 | [3] | ||
Included in noncurrent payables to affiliates | 0 | |||
Included in payable for Zion Station decommissioning | 0 | 0 | ||
Included in regulatory assets/liabilities | 0 | [1] | 0 | [1] |
Change in collateral | 198 | 7 | ||
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | 17 | |||
Included in net income | 0 | 0 | ||
Included in other comprehensive income | 2 | |||
Included in noncurrent payables to affiliates | 0 | |||
Included in payable for Zion Station decommissioning | 0 | 0 | ||
Included in regulatory assets/liabilities | 0 | [1] | 0 | [1] |
Change in collateral | 0 | 0 | ||
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Beginning balance | -193 | [3],[5] | -293 | [3],[5] |
Included in net income | 0 | [3] | 0 | [3],[5] |
Included in other comprehensive income | 0 | [3],[5] | ||
Included in noncurrent payables to affiliates | 0 | [3],[5] | ||
Included in payable for Zion Station decommissioning | 0 | [3] | 0 | [3],[5] |
Included in regulatory assets/liabilities | -14 | [1],[3] | 100 | [1],[3],[5] |
Change in collateral | 0 | [3] | 0 | [3],[5] |
Purchases | 0 | [3] | 0 | [3],[5] |
Sales | 0 | [3] | 0 | [3],[5] |
Settlements | 0 | [3] | 0 | [3],[5] |
Transfers into Level 3 - (Asset) / Liability | 0 | [3] | 0 | [3],[5] |
Transfers out of Level 3 - (Asset) / Liability | 0 | [3] | 0 | [3],[5] |
Ending balance | -207 | [3] | -193 | [3],[5] |
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities | 0 | [3] | 0 | [3],[5] |
Consolidation, Eliminations [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Purchases | 0 | |||
Sales | 0 | |||
Settlements | 0 | |||
Transfers into Level 3 - (Asset) / Liability | 0 | |||
Transfers out of Level 3 - (Asset) / Liability | 0 | |||
Consolidation, Eliminations [Member] | Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Included in net income | 7 | |||
Included in other comprehensive income | 219 | |||
Included in noncurrent payables to affiliates | -14 | |||
Included in payable for Zion Station decommissioning | 0 | |||
Included in regulatory assets/liabilities | 14 | |||
Change in collateral | $0 | |||
[1] | Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations. | |||
[2] | Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition. | |||
[3] | Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively. | |||
[4] | Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively. | |||
[5] | Includes $11 million of decreases in fair value and realized gains 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. |
Fair_Value_of_Financial_Assets5
Fair Value of Financial Assets and Liabilities - Narrative (Details) (USD $) | Dec. 31, 2014 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Forward Power Basis | $2.75 |
Forward Gas Basis | $0.34 |
Fair_Value_of_Financial_Assets6
Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on Recurring Basis Gain Loss Included in Earnings (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Operating Revenue [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | $614 | ($152) | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 663 | 40 | ||
Purchased Fuel and Electric [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | -88 | 108 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | -23 | 127 | ||
Other, net [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | 6 | [1] | 2 | [1] |
Change in the unrealized gains (losses) relating to assets and liabilities held | 4 | [1] | 1 | [1] |
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | 614 | -158 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | 663 | 30 | ||
Exelon Generation Co L L C [Member] | Purchased Fuel and Electric [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | -88 | 107 | ||
Change in the unrealized gains (losses) relating to assets and liabilities held | -23 | 126 | ||
Exelon Generation Co L L C [Member] | Other, net [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Total gains (losses) included in income | 6 | [1] | 2 | [1] |
Change in the unrealized gains (losses) relating to assets and liabilities held | $4 | [1] | $1 | [1] |
[1] | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation. |
Fair_Value_of_Financial_Assets7
Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Cash collateral excluded | 172,000,000 | 26,000,000 | ||
Exelon Generation Co L L C [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities, fair value | 293,000,000 | [1] | 210,000,000 | [1] |
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities, fair value | -15,000,000 | [2],[3] | 3,000,000 | [2],[4] |
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative assets, fair value | 893,000,000 | [2],[3] | 488,000,000 | [2],[4] |
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 15 | [2],[5] | 10 | [2] |
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 15 | [2],[5] | 8 | [2] |
Forward gas price assets | 1.52 | [2],[5] | 2.98 | [6] |
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 117 | [2],[5] | 176 | [2],[6] |
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member] | All Regions excluding New England [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 76 | |||
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 120 | [2],[5] | 176 | [2],[6] |
Forward gas price assets | 14.02 | [2],[5] | 16.63 | [6] |
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | All Regions excluding New England [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward power price assets | 97 | 100 | ||
Forward gas price assets | 8.14 | 5.7 | ||
Exelon Generation Co L L C [Member] | Option Model Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Volatility percentage | 8.00% | [2] | 15.00% | |
Exelon Generation Co L L C [Member] | Option Model Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Volatility percentage | 257.00% | [2] | 142.00% | |
Commonwealth Edison Co [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Derivative liabilities, fair value | -207,000,000 | [3] | -193,000,000 | [4] |
Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward heat rate | 8.00% | [7] | 8.00% | [7] |
Marketability Reserve | 3.50% | 3.50% | ||
Renewable factor | 86.00% | 84.00% | ||
Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Forward heat rate | 9.00% | [7] | 9.00% | [7] |
Marketability Reserve | 8.00% | 8.00% | ||
Renewable factor | 126.00% | 128.00% | ||
[1] | (c)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. | |||
[2] | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. | |||
[3] | The fair values do not include cash collateral held on level three positions of $172 million as of December 31, 2014. | |||
[4] | The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 | |||
[5] | 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 $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading. | |||
[6] | 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. | |||
[7] | 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. |
Derivative_Financial_Instrumen2
Derivative Financial Instruments - Narrative (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||
In Millions, unless otherwise specified | Sep. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
MWh | MWh | MWh | ||||
Derivative [Line Items] | ||||||
Gain Loss On Interest Rate Swap Treasury Rate Lock Net Of Tax | $20 | $5 | ||||
Estimated percentage of natural gas purchases hedged | 30.00% | |||||
Derivative, notional amount | 1,491 | 2,651 | ||||
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound | 8 | |||||
Ineffective portion recognized in income | 18 | 2 | ||||
Notional amount of interest rate swaps acquired from merger | 1,900 | |||||
Mark-to-market derivative liabilities | 403 | 300 | ||||
Mark-to-market derivative liabilities | 234 | 159 | ||||
Fair value of interest rate swaps from merger acquiree | 150 | |||||
Cash collateral held | 69 | |||||
Letters of credit held | 16 | |||||
Net Asset Liability Position After Contractual Right Of Offset | -90 | |||||
Credit Derivative, Collateral Held Directly or by Third Parties Monetary Amount | 2 | |||||
PHI Merger [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 100 | |||||
Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 28 | |||||
Designated as Hedging Instrument [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 3,070 | |||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 26 | |||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | ||||||
Derivative [Line Items] | ||||||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 195 | 464 | 747 | |||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 1,450 | 1,275 | ||||
Increase in notional amount of derivative instruments | 100 | |||||
Increase in notional amount of derivative instruments | 75 | |||||
Derivative asset | 29 | 26 | ||||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 400 | |||||
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 505 | |||||
Interest Rate Swap [Member] | Derivative [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 1,450 | |||||
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 400 | |||||
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 8 | |||||
Baltimore Gas and Electric Company [Member] | ||||||
Derivative [Line Items] | ||||||
Net receivable from electric utility | 40 | |||||
Credit exposure under off system sales | 8 | |||||
Incremental collateral for loss of investment grade credit rating | 79 | |||||
Exelon Generation Co L L C [Member] | ||||||
Derivative [Line Items] | ||||||
Proprietary trading activities volume | 10,571,000 | 8,762,000 | 12,958,000 | |||
Hypothetical increase in interest rates associated with variable-rate debt | 50.00% | |||||
Unrealized gain (loss) on interest rate cash flow hedges, pretax, accumulated other comprehensive income (loss) | 21 | |||||
Mark-to-market derivative liabilities | 105 | 120 | ||||
Mark-to-market derivative liabilities | 214 | 142 | ||||
Derivative, collateral, right to reclaim cash | 8 | 10 | ||||
Expected reclassification from accumulated other comprehensive income to results of operations | 2 | |||||
Letters of credit posted | 672 | 364 | ||||
Cash collateral held | 77 | 206 | ||||
Letters of credit held | 24 | 34 | ||||
Cash collateral posted | 72 | |||||
Incremental collateral for loss of investment grade credit rating | 2,400 | 2,000 | ||||
Net Asset Liability Position After Contractual Right Of Offset | 16 | |||||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 770 | |||||
Derivative asset | 6,813 | 3,960 | ||||
Mark-to-market derivative liabilities | 1,540 | 804 | ||||
Mark-to-market derivative liabilities | 4,947 | 2,023 | ||||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Antelope Valle [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
DOE interest rate swap | 485 | |||||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | ||||||
Derivative [Line Items] | ||||||
Notional amounts on forward starting interest rate swaps | 26 | |||||
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | ||||||
Derivative [Line Items] | ||||||
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income | 195 | 683 | 1,368 | |||
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | ||||||
Derivative [Line Items] | ||||||
Net unrealized pre-tax gain (loss) on effective cash flow hedges | 5 | |||||
Exelon Generation Co L L C [Member] | Derivative [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, collateral, right to reclaim cash | 1,497 | |||||
Exelon Generation Co L L C [Member] | Derivative [Member] | Other Solar Projects [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 3 | |||||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 2 | |||||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 550 | |||||
Interest rate swaps previously held by acquiree | 550 | |||||
Derivative asset | 7 | 23 | ||||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 550 | |||||
Exelon Generation Co L L C [Member] | Interest Rate Contract [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 126 | |||||
Exelon Generation Co L L C [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Increase in notional amount of derivative instruments | 213 | |||||
Notional amount of interest rate swaps acquired from merger | 26 | |||||
Exelon Generation Co L L C [Member] | Foreign Exchange Contract [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, notional amount | 349 | |||||
Commonwealth Edison Co [Member] | ||||||
Derivative [Line Items] | ||||||
Term of contract | 20 years | |||||
Mark-to-market derivative liabilities | 187 | 176 | ||||
Mark-to-market derivative liabilities | 20 | 17 | ||||
Net receivable from electric utility | 43 | |||||
Cash collateral held | 19 | |||||
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative asset | 0 | [1] | 0 | |||
Mark-to-market derivative liabilities | 187 | [1] | 176 | [1] | ||
Mark-to-market derivative liabilities | 20 | [1] | 17 | [1] | ||
PECO Energy Co [Member] | ||||||
Derivative [Line Items] | ||||||
Mark-to-market derivative liabilities | 14 | |||||
Net receivable from electric utility | 29 | |||||
Credit exposure under natural gas supply and management agreements | 8 | |||||
Incremental collateral for loss of investment grade credit rating | $36 | |||||
Minimum [Member] | ||||||
Derivative [Line Items] | ||||||
Expected generation hedged in next twelve months | 93.00% | |||||
Expected generation hedged in year two | 61.00% | |||||
Expected generation hedged in year three | 31.00% | |||||
Minimum [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Derivative [Line Items] | ||||||
Estimated percentage of natural gas purchases hedged | 10.00% | |||||
Maximum [Member] | ||||||
Derivative [Line Items] | ||||||
Expected generation hedged in next twelve months | 96.00% | |||||
Expected generation hedged in year two | 64.00% | |||||
Expected generation hedged in year three | 34.00% | |||||
Maximum [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Derivative [Line Items] | ||||||
Estimated percentage of natural gas purchases hedged | 20.00% | |||||
[1] | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Derivative_Financial_Instrumen3
Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Interest Rate Swap [Member] | Derivative [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | $15 | ($1) | ||
Mark-to-market derivative assets (noncurrent assets) | 8 | 38 | ||
Total mark-to-market derivative assets | 23 | 37 | ||
Mark-to-market derivative liabilities (current liabilities) | 1 | -1 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -114 | -15 | ||
Total mark-to-market derivative liabilities | -113 | -16 | ||
Interest Rate Derivative Fair Value Of Derivative Net | -90 | 21 | ||
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 12 | -1 | ||
Mark-to-market derivative assets (noncurrent assets) | 6 | 31 | ||
Total mark-to-market derivative assets | 18 | 30 | ||
Mark-to-market derivative liabilities (current liabilities) | 1 | -1 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -3 | -11 | ||
Total mark-to-market derivative liabilities | -2 | -12 | ||
Interest Rate Derivative Fair Value Of Derivative Net | 16 | 18 | ||
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Derivative [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 7 | 3 | ||
Mark-to-market derivative assets (noncurrent assets) | 5 | 3 | ||
Total mark-to-market derivative assets | 12 | 6 | ||
Mark-to-market derivative liabilities (current liabilities) | -2 | -1 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 0 | -1 | ||
Total mark-to-market derivative liabilities | -2 | -2 | ||
Interest Rate Derivative Fair Value Of Derivative Net | 10 | 4 | ||
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 20 | [1] | 15 | [1] |
Mark-to-market derivative assets (noncurrent assets) | 7 | [1] | 15 | [1] |
Total mark-to-market derivative assets | 27 | [1] | 30 | [1] |
Mark-to-market derivative liabilities (current liabilities) | -14 | [1] | -18 | [1] |
Mark-to-market derivative liabilities (noncurrent liabilities) | -9 | [1] | -13 | [1] |
Total mark-to-market derivative liabilities | -23 | [1] | -31 | [1] |
Interest Rate Derivative Fair Value Of Derivative Net | 4 | [1] | -1 | [1] |
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | -22 | [2] | -19 | [2] |
Mark-to-market derivative assets (noncurrent assets) | -7 | [2] | -13 | [2] |
Total mark-to-market derivative assets | -29 | [2] | -32 | [2] |
Mark-to-market derivative liabilities (current liabilities) | 25 | [2] | 19 | [2] |
Mark-to-market derivative liabilities (noncurrent liabilities) | 10 | [2] | 13 | [2] |
Total mark-to-market derivative liabilities | 35 | [2] | 32 | [2] |
Interest Rate Derivative Fair Value Of Derivative Net | 6 | [2] | 0 | [2] |
Other Segments [Member] | Interest Rate Swap [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 3 | |||
Mark-to-market derivative assets (noncurrent assets) | 2 | |||
Total mark-to-market derivative assets | 5 | |||
Mark-to-market derivative liabilities (current liabilities) | 0 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -111 | |||
Total mark-to-market derivative liabilities | -111 | |||
Interest Rate Derivative Fair Value Of Derivative Net | -106 | |||
Other Segments [Member] | Interest Rate Swap [Member] | Derivative [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 0 | |||
Mark-to-market derivative assets (noncurrent assets) | 1 | |||
Total mark-to-market derivative assets | 1 | |||
Mark-to-market derivative liabilities (current liabilities) | 0 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -101 | |||
Total mark-to-market derivative liabilities | -101 | |||
Interest Rate Derivative Fair Value Of Derivative Net | -100 | |||
Other Segments [Member] | Interest Rate Swap [Member] | Collateral And Netting [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 0 | [2] | ||
Mark-to-market derivative assets (noncurrent assets) | -19 | [2] | ||
Total mark-to-market derivative assets | -19 | [2] | ||
Mark-to-market derivative liabilities (current liabilities) | 0 | [2] | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | 19 | [2] | ||
Total mark-to-market derivative liabilities | 19 | [2] | ||
Interest Rate Derivative Fair Value Of Derivative Net | 0 | [2] | ||
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 7 | 0 | ||
Mark-to-market derivative assets (noncurrent assets) | 1 | 26 | ||
Total mark-to-market derivative assets | 8 | 26 | ||
Mark-to-market derivative liabilities (current liabilities) | -8 | -1 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -4 | -10 | ||
Total mark-to-market derivative liabilities | -12 | -11 | ||
Interest Rate Derivative Fair Value Of Derivative Net | -4 | 15 | ||
Designated as Hedging Instrument [Member] | Other Segments [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative liabilities (current liabilities) | 0 | |||
Designated as Hedging Instrument [Member] | Other Segments [Member] | Interest Rate Swap [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 3 | 0 | ||
Mark-to-market derivative assets (noncurrent assets) | 20 | 7 | ||
Total mark-to-market derivative assets | 23 | 7 | ||
Mark-to-market derivative liabilities (current liabilities) | 0 | |||
Mark-to-market derivative liabilities (noncurrent liabilities) | -29 | -4 | ||
Total mark-to-market derivative liabilities | -29 | -4 | ||
Interest Rate Derivative Fair Value Of Derivative Net | ($6) | $3 | ||
[1] | 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. | |||
[2] | Represents the netting of fair value balances with the same counterparty and any associated cash collateral. |
Derivative_Financial_Instrumen4
Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Exelon Generation Co L L C [Member] | ||||||
Derivative [Line Items] | ||||||
Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net | $4 | $2 | ||||
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | ||||||
Derivative [Line Items] | ||||||
Gain (Loss) on Swaps/Borrowings | 15 | -3 | -1 | |||
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Gain (Loss) on Swaps/Borrowings | 3 | -24 | -9 | |||
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | ||||||
Derivative [Line Items] | ||||||
Gain (Loss) on Swaps/Borrowings | 2 | [1] | -6 | [1] | 0 | [1] |
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Gain (Loss) on Swaps/Borrowings | -16 | [1] | -15 | [1] | -6 | [1] |
Gain (Loss) on Fair Value Hedges Recognized in Earnings | $17 | $16 | ||||
[1] | For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively. |
Derivative_Financial_Instrumen5
Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | $1,279 | $727 | ||
Mark-to-market derivative assets (noncurrent assets) | 773 | 607 | ||
Mark-to-market derivative liabilities (current liabilities) | -234 | -159 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -403 | -300 | ||
Noncurrent Liability Interest Rate Swap AVSR | 0 | |||
Total cash collateral received net of cash collateral posted | 144 | |||
Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 1,276 | 727 | ||
Mark-to-market derivative assets (noncurrent assets) | 771 | 600 | ||
Mark-to-market derivative liabilities (current liabilities) | -214 | -142 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -105 | -120 | ||
Commonwealth Edison Co [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative liabilities (current liabilities) | -20 | -17 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -187 | -176 | ||
Proprietary Trading [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 456 | 1,476 | ||
Mark-to-market derivative assets (noncurrent assets) | 56 | 285 | ||
Total mark-to-market derivative assets | 512 | 1,761 | ||
Mark-to-market derivative liabilities (current liabilities) | -468 | -1,410 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -64 | -293 | ||
Total mark-to-market derivative liabilities | -532 | -1,703 | ||
Total mark-to-market derivative net assets (liabilities) | -20 | 58 | ||
Collateral And Netting [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | -4,184 | [1] | -3,364 | [1] |
Mark-to-market derivative assets (noncurrent assets) | -1,112 | [1] | -1,060 | [1] |
Total mark-to-market derivative assets | -5,296 | [1] | -4,424 | [1] |
Mark-to-market derivative liabilities (current liabilities) | 5,200 | [1] | 3,292 | [1] |
Mark-to-market derivative liabilities (noncurrent liabilities) | 1,502 | [1] | 988 | [1] |
Total mark-to-market derivative liabilities | 6,702 | [1] | 4,280 | [1] |
Total mark-to-market derivative net assets (liabilities) | 1,406 | [1] | -144 | [1] |
Derivative [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 1,264 | 728 | ||
Mark-to-market derivative assets (noncurrent assets) | 765 | 569 | ||
Total mark-to-market derivative assets | 2,029 | 1,297 | ||
Mark-to-market derivative liabilities (current liabilities) | -235 | -158 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -289 | -285 | ||
Total mark-to-market derivative liabilities | -524 | -443 | ||
Total mark-to-market derivative net assets (liabilities) | 1,505 | 854 | ||
Derivative [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 1,264 | [2] | 728 | [3] |
Mark-to-market derivative assets (noncurrent assets) | 765 | [2] | 569 | [3] |
Total mark-to-market derivative assets | 2,029 | [2] | 1,297 | [3] |
Mark-to-market derivative liabilities (current liabilities) | -215 | [2] | -141 | [3] |
Mark-to-market derivative liabilities (noncurrent liabilities) | -102 | [2] | -109 | [3] |
Total mark-to-market derivative liabilities | -317 | [2] | -250 | [3] |
Total mark-to-market derivative net assets (liabilities) | 1,712 | [2] | 1,047 | [3] |
Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 4,992 | 2,616 | ||
Mark-to-market derivative assets (noncurrent assets) | 1,821 | 1,344 | ||
Total mark-to-market derivative assets | 6,813 | 3,960 | ||
Mark-to-market derivative liabilities (current liabilities) | -4,947 | -2,023 | ||
Mark-to-market derivative liabilities (noncurrent liabilities) | -1,540 | -804 | ||
Total mark-to-market derivative liabilities | -6,487 | -2,827 | ||
Total mark-to-market derivative net assets (liabilities) | 326 | 1,133 | ||
Current assets collateral offset | -416 | -84 | ||
Noncurrent assets collateral offset | -171 | -72 | ||
Current liabilities collateral offset | -599 | -12 | ||
Collateral Amount Offset Against Fair Value Of Derivative Current Noncurrent Liability | -220 | |||
Total cash collateral received net of cash collateral posted | 1,406 | |||
Designated as Hedging Instrument [Member] | Commonwealth Edison Co [Member] | ||||
Derivative [Line Items] | ||||
Mark-to-market derivative assets (current assets) | 0 | 0 | ||
Mark-to-market derivative assets (noncurrent assets) | 0 | [4] | 0 | [4] |
Total mark-to-market derivative assets | 0 | [4] | 0 | |
Mark-to-market derivative liabilities (current liabilities) | -20 | [4] | -17 | [4] |
Mark-to-market derivative liabilities (noncurrent liabilities) | -187 | [4] | -176 | [4] |
Total mark-to-market derivative liabilities | -207 | [4] | -193 | [4] |
Total mark-to-market derivative net assets (liabilities) | ($207) | [4] | ($193) | [4] |
[1] | 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. | |||
[2] | Current and noncurrent assets are shown net of collateral of $(416) million and $(171) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(599) million and $(220) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014. | |||
[3] | Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. 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. | |||
[4] | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Derivative_Financial_Instrumen6
Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Ineffective portion recognized in income | $18 | $2 | |
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | 133 | ||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | 78 | 270 | |
Net gains (losses) related to interest rate swaps and treasury rate locks | 20 | 5 | |
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks | 15 | 15 | |
Exelon Generation Co L L C [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Reclassifications from accumulated OCI to net income | 16,614 | 14,207 | 12,735 |
Total Cash Flow Hedges [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Accumulated OCI derivative gain - Beginning Balance | 120 | 368 | |
Effective portion of changes in fair value | -31 | 29 | |
Accumulated OCI derivative gain - Ending Balance | -28 | 120 | |
Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Accumulated OCI derivative gain - Beginning Balance | 119 | 532 | |
Effective portion of changes in fair value | 0 | 0 | |
Accumulated OCI derivative gain - Ending Balance | 2 | 119 | |
Operating Revenue One [Member] | Energy Related Hedges [Member] | Exelon Generation Co L L C [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract | 133 | ||
Operating Revenue One [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Total Cash Flow Hedges [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Reclassifications from accumulated OCI to net income | -117 | -277 | |
Operating Revenue One [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Reclassifications from accumulated OCI to net income | -117 | -413 | |
Purchased PowerOne [Member] | Total Cash Flow Hedges [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Ineffective portion recognized in income | 0 | ||
Purchased PowerOne [Member] | Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | |||
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward] | |||
Ineffective portion recognized in income | $0 |
Derivative_Financial_Instrumen7
Derivative Financial Instruments - Summary of Economic Hedges (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative [Line Items] | |||
Change in fair value of commodity positions | ($92) | ($5) | $6 |
Reclassification to realized at settlement | -2 | -1 | -3 |
Net mark-to market gains (losses) | -693 | 507 | 533 |
Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -607 | 460 | -241 |
Reclassification to realized at settlement | 53 | 771 | |
Net mark-to market gains (losses) | 513 | 530 | |
Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | 0 | 7 | 7 |
Intersegment Eliminations [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 0 | -6 | -94 |
Reclassification to realized at settlement | 0 | 13 | 101 |
Net mark-to market gains (losses) | 0 | 7 | 7 |
Intersegment Eliminations [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 0 | 0 | 0 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Interest Rate Swap [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | -94 | -6 | 3 |
Interest Rate Swap [Member] | Intersegment Eliminations [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | 0 | 0 | 0 |
Other Segments [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 0 | 0 | 0 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Net mark-to market gains (losses) | 0 | 0 | 0 |
Other Segments [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -100 | 0 | 0 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Net mark-to market gains (losses) | -100 | 0 | 0 |
Other Segments [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | -100 | 0 | 0 |
Exelon Generation Co L L C [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -607 | 466 | -147 |
Reclassification to realized at settlement | 8 | 40 | 670 |
Net mark-to market gains (losses) | -599 | 506 | 523 |
Exelon Generation Co L L C [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 0 | 0 | 0 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Net mark-to market gains (losses) | 0 | 0 | 0 |
Exelon Generation Co L L C [Member] | Purchased Power [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 8 | -5 | 6 |
Reclassification to realized at settlement | -2 | -1 | -3 |
Net mark-to market gains (losses) | -593 | 500 | 526 |
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -413 | 286 | -362 |
Reclassification to realized at settlement | 231 | -64 | 432 |
Net mark-to market gains (losses) | -182 | 222 | 70 |
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -194 | 180 | 215 |
Reclassification to realized at settlement | -223 | 104 | 238 |
Net mark-to market gains (losses) | -417 | 284 | 453 |
Exelon Generation Co L L C [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 10 | -1 | 0 |
Reclassification to realized at settlement | -2 | -1 | -3 |
Net mark-to market gains (losses) | -174 | 220 | 67 |
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | 0 | 0 | 0 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Net mark-to market gains (losses) | -417 | 284 | 453 |
Exelon Generation Co L L C [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Change in fair value of commodity positions | -2 | -4 | 6 |
Reclassification to realized at settlement | 0 | 0 | 0 |
Net mark-to market gains (losses) | -2 | -4 | 6 |
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Purchased Power [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | 6 | -6 | 3 |
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | 8 | -2 | -3 |
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Purchased Power And Fuel [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | 0 | 0 | 0 |
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Interest Expense [Member] | |||
Derivative [Line Items] | |||
Net mark-to market gains (losses) | ($2) | ($4) | $6 |
Derivative_Financial_Instrumen8
Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Derivative [Line Items] | |||
Change in fair value | $1 | $1 | $1 |
Reclassification to realized at settlement | 3 | -3 | 0 |
Net mark-to-market gains (losses) | -26 | -39 | 96 |
Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Change in fair value | -1 | -22 | -13 |
Reclassification to realized at settlement | -29 | -15 | 108 |
Net mark-to-market gains (losses) | -30 | -37 | 95 |
Interest Rate Swap [Member] | Operating Revenue [Member] | |||
Derivative [Line Items] | |||
Net mark-to-market gains (losses) | $4 | ($2) | $1 |
Derivative_Financial_Instrumen9
Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) (Exelon Generation Co L L C [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Total Exposure Before Credit Collateral [Member] | |
Derivative [Line Items] | |
Investment grade | $1,629 |
Non-investment grade | 49 |
Internally rated—investment grade | 479 |
Internally rated—non-investment grade | 60 |
Total | 2,217 |
Credit Collateral [Member] | |
Derivative [Line Items] | |
Investment grade | 62 |
Non-investment grade | 19 |
Internally rated—investment grade | 0 |
Internally rated—non-investment grade | 4 |
Total | 85 |
Net Exposure [Member] | |
Derivative [Line Items] | |
Investment grade | 1,567 |
Non-investment grade | 30 |
Internally rated—investment grade | 479 |
Internally rated—non-investment grade | 56 |
Total | 2,132 |
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | |
Derivative [Line Items] | |
Investment grade | 1 |
Non-investment grade | 0 |
Internally rated—investment grade | 0 |
Internally rated—non-investment grade | 0 |
Total | 1 |
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member] | |
Derivative [Line Items] | |
Investment grade | 452 |
Non-investment grade | 0 |
Internally rated—investment grade | 0 |
Internally rated—non-investment grade | 0 |
Total | $452 |
Recovered_Sheet2
Derivative Financial Instruments - Net Credit Exposure by Type of Counterparty (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Derivative [Line Items] | ||
Cash collateral held | $69 | |
Letters of credit held | 16 | |
Exelon Generation Co L L C [Member] | ||
Derivative [Line Items] | ||
Cash collateral held | 77 | 206 |
Letters of credit held | 24 | 34 |
Exelon Generation Co L L C [Member] | Net Exposure [Member] | ||
Derivative [Line Items] | ||
Financial institutions | 295 | |
Investor-owned utilities, marketers, power producers | 958 | |
Energy cooperatives and municipalities | 862 | |
Other | 17 | |
Total | $2,132 |
Recovered_Sheet3
Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) (Exelon Generation Co L L C [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Exelon Generation Co L L C [Member] | ||||
Derivative [Line Items] | ||||
Derivative Asset, Fair Value, Gross Liability | ($1,433) | [1] | ($1,056) | [1] |
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements | 1,140 | [2] | 846 | [2] |
Derivative liabilities, fair value | ($293) | [3] | ($210) | [3] |
[1] | (a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. | |||
[2] | (b)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] | (c)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_Com
Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | 30-May-14 | Mar. 28, 2014 | ||||
Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | $8,300,000,000 | [1],[2] | $8,300,000,000 | [1],[2] | ||||
Outstanding commercial paper | 424,000,000 | 319,000,000 | ||||||
Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 8,500,000,000 | [3] | ||||||
Exelon Corporate [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Average Interest Rate on Commercial Paper Borrowings | 0.53% | 0.35% | ||||||
Exelon Corporate [Member] | Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 500,000,000 | [1],[2] | ||||||
Outstanding commercial paper | 0 | 0 | ||||||
Average Interest Rate on Commercial Paper Borrowings | 0.00% | 0.27% | ||||||
Exelon Corporate [Member] | Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 500,000,000 | [3] | 500,000,000 | [1],[2] | ||||
Exelon Generation Co L L C [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Bilateral letters of credit | 200,000,000 | |||||||
Exelon Generation Co L L C [Member] | Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 5,600,000,000 | [1],[2] | 5,600,000,000 | [1],[2] | ||||
Outstanding commercial paper | 0 | 0 | ||||||
Average Interest Rate on Commercial Paper Borrowings | 0.32% | 0.32% | ||||||
Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 5,800,000,000 | [3] | 5,300,000,000 | [2] | ||||
Commonwealth Edison Co [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Average Interest Rate on Commercial Paper Borrowings | 0.50% | 0.37% | ||||||
Commonwealth Edison Co [Member] | Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 1,000,000,000 | [1],[2] | ||||||
Outstanding commercial paper | 304,000,000 | 184,000,000 | ||||||
Average Interest Rate on Commercial Paper Borrowings | 0.33% | 0.40% | ||||||
Commonwealth Edison Co [Member] | Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 1,000,000,000 | [3] | 1,000,000,000 | [1],[2] | ||||
PECO Energy Co [Member] | Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 600,000,000 | [1],[2] | ||||||
Outstanding commercial paper | 0 | 0 | ||||||
PECO Energy Co [Member] | Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 600,000,000 | [3] | 600,000,000 | [1],[2] | ||||
Baltimore Gas and Electric Company [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Average Interest Rate on Commercial Paper Borrowings | 0.61% | 0.31% | ||||||
Baltimore Gas and Electric Company [Member] | Commercial Paper [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | 600,000,000 | [1],[2] | 600,000,000 | [1],[2] | ||||
Outstanding commercial paper | 120,000,000 | 135,000,000 | ||||||
Average Interest Rate on Commercial Paper Borrowings | 0.29% | 0.31% | ||||||
Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member] | ||||||||
Short-term Debt [Line Items] | ||||||||
Maximum Program Size | $600,000,000 | [3] | ||||||
[1] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||||
[2] | aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||
[3] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below |
Debt_and_Credit_Agreements_Sum
Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) (USD $) | Dec. 31, 2014 | 30-May-14 | Mar. 28, 2014 | |||
Short-term Debt [Line Items] | ||||||
Facility draws | $0 | |||||
Outstanding letters of credit | 1,190,000,000 | [1] | ||||
Actual available capacity | 7,310,000,000 | |||||
To Support Additional Commercial Paper | 6,771,000,000 | [2] | ||||
Exelon Corporate [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Facility draws | 0 | |||||
Outstanding letters of credit | 6,000,000 | [1] | ||||
Actual available capacity | 494,000,000 | |||||
To Support Additional Commercial Paper | 494,000,000 | [2] | ||||
Exelon Generation Co L L C [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Facility draws | 0 | |||||
Outstanding letters of credit | 1,181,000,000 | [1] | ||||
Actual available capacity | 4,619,000,000 | |||||
To Support Additional Commercial Paper | 4,504,000,000 | [2] | ||||
Credit facility agreements with minority and community banks | 50,000,000 | |||||
Letters of credit | 9,000,000 | |||||
Bilateral letters of credit | 200,000,000 | |||||
Commonwealth Edison Co [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Facility draws | 0 | |||||
Outstanding letters of credit | 2,000,000 | [1] | ||||
Actual available capacity | 998,000,000 | |||||
To Support Additional Commercial Paper | 694,000,000 | [2] | ||||
Credit facility agreements with minority and community banks | 34,000,000 | |||||
Letters of credit | 16,000,000 | |||||
PECO Energy Co [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Facility draws | 0 | |||||
Outstanding letters of credit | 1,000,000 | [1] | ||||
Actual available capacity | 599,000,000 | |||||
To Support Additional Commercial Paper | 599,000,000 | [2] | ||||
Credit facility agreements with minority and community banks | 34,000,000 | |||||
Letters of credit | 21,000,000 | |||||
Baltimore Gas and Electric Company [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Facility draws | 0 | |||||
Outstanding letters of credit | 0 | [1] | ||||
Actual available capacity | 600,000,000 | |||||
To Support Additional Commercial Paper | 480,000,000 | [2] | ||||
Credit facility agreements with minority and community banks | 5,000,000 | |||||
Letters of credit | 1,000,000 | |||||
Revolving Credit Facility [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | 8,500,000,000 | [3] | ||||
Revolving Credit Facility [Member] | Exelon Corporate [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | 500,000,000 | [3] | 500,000,000 | [4],[5] | ||
Revolving Credit Facility [Member] | Exelon Generation Co L L C [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | 5,800,000,000 | [3] | 5,300,000,000 | [5] | ||
Revolving Credit Facility [Member] | Commonwealth Edison Co [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | 1,000,000,000 | [3] | 1,000,000,000 | [4],[5] | ||
Revolving Credit Facility [Member] | PECO Energy Co [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | 600,000,000 | [3] | 600,000,000 | [4],[5] | ||
Revolving Credit Facility [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Maximum Program Size | $600,000,000 | [3] | ||||
[1] | Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind. | |||||
[2] | Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program. | |||||
[3] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below | |||||
[4] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||||
[5] | aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. |
Debt_and_Credit_Agreements_Sum1
Debt and Credit Agreements - Summary of Short-term Borrowing Activities (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commonwealth Edison Co [Member] | |||
Short-term Debt [Line Items] | |||
Average borrowings | $415 | $203 | $110 |
Maximum borrowings outstanding | 597 | 446 | 366 |
Average interest rates, computed on a daily basis | 0.33% | 0.40% | 0.50% |
Average interest rates at year end | 0.50% | 0.37% | |
Exelon Corporate [Member] | |||
Short-term Debt [Line Items] | |||
Average borrowings | 571 | 254 | 199 |
Maximum borrowings outstanding | 1,164 | 682 | 505 |
Average interest rates, computed on a daily basis | 0.32% | 0.37% | 0.48% |
Average interest rates at year end | 0.53% | 0.35% | |
Exelon Generation Co L L C [Member] | |||
Short-term Debt [Line Items] | |||
Average borrowings | 93 | 42 | 4 |
Maximum borrowings outstanding | 552 | 291 | 165 |
Average interest rates, computed on a daily basis | 0.32% | 0.32% | 0.45% |
Baltimore Gas and Electric Company [Member] | |||
Short-term Debt [Line Items] | |||
Average borrowings | 64 | 35 | 6 |
Maximum borrowings outstanding | $180 | $135 | $76 |
Average interest rates, computed on a daily basis | 0.29% | 0.31% | 0.43% |
Average interest rates at year end | 0.61% | 0.31% |
Debt_and_Credit_Agreements_Nar
Debt and Credit Agreements - Narrative (Details) (USD $) | 1 Months Ended | 3 Months Ended | 0 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||||||||||||
Jun. 30, 2014 | Jun. 30, 2014 | Sep. 30, 2013 | Dec. 31, 2014 | Jan. 13, 2015 | Jul. 31, 2011 | Sep. 30, 2012 | Jun. 11, 2014 | 31-May-14 | Dec. 31, 2013 | 30-May-14 | Mar. 28, 2014 | Sep. 18, 2014 | Feb. 06, 2014 | Oct. 24, 2014 | ||||
MW | MW | MW | ||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | $1,190,000,000 | [1] | ||||||||||||||||
Bridge loan | 3,200,000,000 | 7,200,000,000 | ||||||||||||||||
Long-term debt, gross | 20,756,000,000 | 18,760,000,000 | ||||||||||||||||
Equity units issued | 23,000,000 | |||||||||||||||||
Underwriting fee | 60,000,000 | 35,000,000 | ||||||||||||||||
Equity units, annual distribution rate | 6.50% | |||||||||||||||||
Forward contract, payment rate | 4.00% | |||||||||||||||||
Long-term debt | 131,000,000 | 131,000,000 | 21,404,000,000 | |||||||||||||||
Collateral amount of debt | 2,700,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
Debt Continental Project [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Generation capacity of portfolio | 667 | |||||||||||||||||
Designated as Hedging Instrument [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 3,070,000,000 | |||||||||||||||||
Long Term Debt Issuances [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 2.50% | 2.50% | ||||||||||||||||
Senior Notes [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Long-term debt, gross | 7,071,000,000 | 7,571,000,000 | ||||||||||||||||
Junior Subordinated Debt [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Long-term debt, gross | 1,150,000,000 | 1,150,000,000 | 1,150,000,000 | 0 | ||||||||||||||
Convertible Debt Securities [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Conversion price | $50 | $50 | ||||||||||||||||
Proceeds from issuance of subordinated long-term debt | 1,110,000,000 | |||||||||||||||||
Maximum [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Basis points adders for prime-based borrowings | 0.07% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.00165 | |||||||||||||||||
Equity units, share price | $43.75 | |||||||||||||||||
Common shares, issuable at maturity | 1.1429 | |||||||||||||||||
Minimum [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Equity units, share price | $35 | |||||||||||||||||
Common shares, issuable at maturity | 1.4286 | |||||||||||||||||
Revolving Credit Facility [Member] | Parent [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, cumulative committed amount | 315,000,000 | |||||||||||||||||
Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 8,500,000,000 | [2] | ||||||||||||||||
Bridge Loan [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest expense, short-term borrowings | 31,000,000 | |||||||||||||||||
Commonwealth Edison Co [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Additional amounts available upon request under current credit facilities | 500,000,000 | |||||||||||||||||
Outstanding letters of credit | 2,000,000 | [1] | ||||||||||||||||
Basis points adders for prime-based borrowings | 0.08% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.01075 | |||||||||||||||||
Long-term debt, gross | 5,977,000,000 | 5,694,000,000 | ||||||||||||||||
Interest rate on long-term debt | 6.35% | [3] | ||||||||||||||||
Long-term debt | 6,183,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
Commonwealth Edison Co [Member] | Letter of Credit [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 500,000,000 | [4] | ||||||||||||||||
Commonwealth Edison Co [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 1,000,000,000 | [2] | 1,000,000,000 | [4],[5] | ||||||||||||||
Exelon Corporate [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 6,000,000 | [1] | ||||||||||||||||
Basis points adders for prime-based borrowings | 0.28% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.01275 | |||||||||||||||||
Long-term debt, gross | 3,808,000,000 | 2,658,000,000 | ||||||||||||||||
Long-term debt | 3,808,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
Exelon Corporate [Member] | Senior Notes [Member] | Subsequent Event [Member] | Fixed Rate Note, 4.55% Due 2015 [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 4.55% | |||||||||||||||||
Redemption of debt | 550,000,000 | |||||||||||||||||
Exelon Corporate [Member] | Junior Subordinated Debt [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Long-term debt, gross | 1,150,000,000 | 0 | ||||||||||||||||
Exelon Corporate [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 500,000,000 | [2] | 500,000,000 | [4],[5] | ||||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 1,181,000,000 | [1] | ||||||||||||||||
Basis points adders for prime-based borrowings | 0.28% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.01275 | |||||||||||||||||
Long-term debt, gross | 8,134,000,000 | 7,552,000,000 | ||||||||||||||||
Long-term debt | 8,134,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Debt Continental Project [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 6.00% | |||||||||||||||||
Principal amount of debt | 613,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Continetal Wind [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 131,000,000 | |||||||||||||||||
Outstanding letters of credit | 47,000,000 | |||||||||||||||||
Aggregate bank commitments under unsecured revolving credit facilities | 10,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 770,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Debt Continental Project [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, interest rate swap | 350,000,000 | |||||||||||||||||
Gain from exchange offer | 26,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | ExGen Texas Power [Member] | Interest Rate Swap [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, interest rate swap | 505,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member] | Interest Rate Swap [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 2.03% | |||||||||||||||||
Non-recourse debt, interest rate swap | 240,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Sacramento PV Energy [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, interest rate swap | 30,000,000 | |||||||||||||||||
Generation capacity of portfolio | 30 | |||||||||||||||||
Outstanding borrowings/facility draws | 35,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Constellation Solar Horizons Financing [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, interest rate swap | 29,000,000 | |||||||||||||||||
Non-recourse debt, commitment | 38,000,000 | |||||||||||||||||
Generation capacity of portfolio | 16 | |||||||||||||||||
Outstanding borrowings/facility draws | 34,000,000 | |||||||||||||||||
Non-recourse debt, hedge percentage | 75.00% | |||||||||||||||||
Exelon Generation Co L L C [Member] | Denver International Airport [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding borrowings/facility draws | 7,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Holyoke [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding borrowings/facility draws | 10,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Senior Notes [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Long-term debt, gross | 5,771,000,000 | 6,271,000,000 | ||||||||||||||||
Exelon Generation Co L L C [Member] | Senior Notes [Member] | ExGen Texas Power [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Principal amount of debt | 675,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Senior Notes [Member] | ExGen Texas Power [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 4.75% | |||||||||||||||||
Exelon Generation Co L L C [Member] | Senior Notes [Member] | Subsequent Event [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 2.95% | |||||||||||||||||
Principal amount of debt | 750,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Continetal Wind [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 592,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGen Texas Power [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 673,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExgenRenewablesI425June62021[Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 282,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 156,000,000 | |||||||||||||||||
Non-recourse debt | 557,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Sacramento PV Energy [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 41,000,000 | |||||||||||||||||
Non-recourse debt, hedge percentage | 75.00% | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Denver International Airport [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 7,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Holyoke [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt | 10,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Upstream Gas Property [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, commitment | 110,000,000 | |||||||||||||||||
Non-recourse debt, commitment increase available | 500,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 77,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Long Term Debt Issuances [Member] | ExGen Texas Power [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 2.34% | |||||||||||||||||
Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Long Term Debt Issuances [Member] | ExgenRenewablesI425June62021[Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Interest rate on long-term debt | 4.25% | |||||||||||||||||
Long-term debt | 300,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | DOE Financing Project [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Non-recourse debt, interest rate swap | 485,000,000 | |||||||||||||||||
Non-recourse debt, commitment | 646,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Sumitomo Bank [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 100,000,000 | |||||||||||||||||
Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 5,800,000,000 | [2] | 5,300,000,000 | [4] | ||||||||||||||
PECO Energy Co [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 1,000,000 | [1] | ||||||||||||||||
Basis points adders for prime-based borrowings | 0.00% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.009 | |||||||||||||||||
Long-term debt, gross | 2,250,000,000 | 2,200,000,000 | ||||||||||||||||
Long-term debt | 2,434,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
PECO Energy Co [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 600,000,000 | [2] | 600,000,000 | [4],[5] | ||||||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Outstanding letters of credit | 0 | [1] | ||||||||||||||||
Basis points adders for prime-based borrowings | 0.00% | |||||||||||||||||
Basis points adders for LIBOR-based borrowings | 0.01 | |||||||||||||||||
Long-term debt, gross | 1,945,000,000 | 2,015,000,000 | ||||||||||||||||
Long-term debt | 2,203,000,000 | |||||||||||||||||
Outstanding borrowings/facility draws | 0 | |||||||||||||||||
Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Line of credit facility, maximum borrowing capacity | 600,000,000 | [2] | ||||||||||||||||
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | 400,000,000 | |||||||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member] | ||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||
Notional amount of preissuance interest rate cash flow hedge derivatives | $26,000,000 | |||||||||||||||||
[1] | Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind. | |||||||||||||||||
[2] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below | |||||||||||||||||
[3] | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. | |||||||||||||||||
[4] | aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. | |||||||||||||||||
[5] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. |
Debt_and_Credit_Agreements_Sum2
Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Nov. 24, 2014 | Jan. 09, 2015 | |
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | $1,190 | [1] | ||
Credit facility threshold | 2.50 to 1 | |||
Credit facility threshold | 2.5 | |||
Exelon Generation Co L L C [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 1,181 | [1] | ||
Credit facility threshold | 3.00 to 1 | |||
Credit facility threshold | 3 | |||
Commonwealth Edison Co [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 2 | [1] | ||
Credit facility threshold | 2.00 to 1 | |||
Credit facility threshold | 2 | |||
PECO Energy Co [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 1 | [1] | ||
Credit facility threshold | 2.00 to 1 | |||
Credit facility threshold | 2 | |||
Baltimore Gas and Electric Company [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 0 | [1] | ||
Credit facility threshold | 2.00 to 1 | |||
Credit facility threshold | 2 | |||
citibank Bank [Member] | Exelon Generation Co L L C [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 25 | |||
CIBC Bank [Member] | Exelon Generation Co L L C [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | $75 | |||
[1] | Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind. |
Debt_and_Credit_Agreements_Sum3
Debt and Credit Agreements - Summary of Interest Coverage Ratios (Details) | Dec. 31, 2014 |
Debt Instrument [Line Items] | |
Interest coverage ratio | 919.00% |
Exelon Generation Co L L C [Member] | |
Debt Instrument [Line Items] | |
Interest coverage ratio | 1235.00% |
Commonwealth Edison Co [Member] | |
Debt Instrument [Line Items] | |
Interest coverage ratio | 703.00% |
PECO Energy Co [Member] | |
Debt Instrument [Line Items] | |
Interest coverage ratio | 872.00% |
Baltimore Gas and Electric Company [Member] | |
Debt Instrument [Line Items] | |
Interest coverage ratio | 928.00% |
Debt_and_Credit_Agreements_Sum4
Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | |||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | $20,756,000,000 | $18,760,000,000 | |||
Unamortized debt discount and premium, net | -37,000,000 | -19,000,000 | |||
Long-term debt (including amounts due within one year) | 441,000,000 | 384,000,000 | |||
Fair value hedge carrying value adjustment, net | 4,000,000 | 7,000,000 | |||
Long-term debt due within one year | -1,802,000,000 | -1,509,000,000 | |||
Long-term debt | 19,362,000,000 | 17,623,000,000 | |||
Long-term debt to financing trusts | 648,000,000 | 648,000,000 | |||
Total long-term debt to financing trusts | 648,000,000 | [1] | 648,000,000 | [1] | |
ComEd Financing Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 6.35% | [1] | |||
Long-term debt to financing trusts | 206,000,000 | [1] | 206,000,000 | [1] | |
PECO Trust Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 7.38% | [1] | |||
Long-term debt to financing trusts | 81,000,000 | [1] | 81,000,000 | [1] | |
PECO Trust Four Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 5.75% | [1] | |||
Long-term debt to financing trusts | 103,000,000 | [1] | 103,000,000 | [1] | |
BGE Trust Member [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 6.20% | [1] | |||
Long-term debt to financing trusts | 258,000,000 | [1] | 258,000,000 | [1] | |
Junior Subordinated Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum interest rate on long-term debt | 6.50% | ||||
Long-term Debt, Gross | 1,150,000,000 | 1,150,000,000 | 0 | ||
Secured Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 1.20% | [2],[3] | |||
Maximum interest rate on long-term debt | 6.45% | [2],[3] | |||
Long-term Debt, Gross | 8,079,000,000 | [2],[3] | 7,746,000,000 | [2],[3] | |
Unsecured Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.80% | ||||
Maximum interest rate on long-term debt | 6.35% | ||||
Long-term Debt, Gross | 1,750,000,000 | 1,750,000,000 | |||
Rate Stabilization Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 5.72% | ||||
Maximum interest rate on long-term debt | 5.82% | ||||
Long-term Debt, Gross | 195,000,000 | 265,000,000 | |||
Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.00% | ||||
Maximum interest rate on long-term debt | 7.60% | ||||
Long-term Debt, Gross | 7,071,000,000 | 7,571,000,000 | |||
Notes Payable to Banks [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 3.25% | ||||
Maximum interest rate on long-term debt | 3.35% | ||||
Long-term Debt, Gross | 70,000,000 | 0 | |||
Pollution Control Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum interest rate on long-term debt | 4.10% | ||||
Long-term Debt, Gross | 0 | 20,000,000 | |||
Non Recourse Fixed Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.33% | ||||
Maximum interest rate on long-term debt | 6.00% | ||||
Long-term Debt, Gross | 1,166,000,000 | 1,077,000,000 | |||
Non Recourse Variable Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.41% | ||||
Maximum interest rate on long-term debt | 5.00% | ||||
Long-term Debt, Gross | 1,101,000,000 | 150,000,000 | |||
Notes Payable, Other Payables [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 6.95% | [4] | |||
Maximum interest rate on long-term debt | 7.83% | [4] | |||
Long-term Debt, Gross | 174,000,000 | [4] | 181,000,000 | [4] | |
Capital Lease Obligations [Member] | |||||
Debt Instrument [Line Items] | |||||
Capital lease obligations, noncurrent | 32,000,000 | 41,000,000 | |||
Due in 2015 | 3,000,000 | ||||
Due in 2016 | 4,000,000 | ||||
Due in 2018 | 4,000,000 | ||||
Due in 2019 | 5,000,000 | ||||
Due in 2020 | 12,000,000 | ||||
Exelon Generation Co L L C [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 8,134,000,000 | 7,552,000,000 | |||
Unamortized debt discount and premium, net | -14,000,000 | 11,000,000 | |||
Long-term debt (including amounts due within one year) | 146,000,000 | 166,000,000 | |||
Long-term debt due within one year | -614,000,000 | -561,000,000 | |||
Long-term debt | 6,709,000,000 | 5,645,000,000 | |||
Long-term debt to financing trusts | 943,000,000 | 1,523,000,000 | |||
Debt and Capital Lease Obligations | 7,652,000,000 | 7,168,000,000 | |||
Capital lease obligations, noncurrent | 24,000,000 | 33,000,000 | |||
Due in 2015 | 3,000,000 | ||||
Due in 2016 | 4,000,000 | ||||
Due in 2017 | 4,000,000 | ||||
Due in 2018 | 4,000,000 | ||||
Due in 2020 | 4,000,000 | ||||
Exelon Generation Co L L C [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.00% | ||||
Maximum interest rate on long-term debt | 7.60% | ||||
Long-term Debt, Gross | 5,771,000,000 | 6,271,000,000 | |||
Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 3.25% | ||||
Long-term Debt, Gross | 70,000,000 | 0 | |||
Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 4.10% | ||||
Long-term Debt, Gross | 0 | 20,000,000 | |||
Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.33% | ||||
Maximum interest rate on long-term debt | 6.00% | ||||
Long-term Debt, Gross | 1,166,000,000 | 1,077,000,000 | |||
Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.41% | ||||
Maximum interest rate on long-term debt | 5.00% | ||||
Long-term Debt, Gross | 1,101,000,000 | 150,000,000 | |||
Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member] | |||||
Debt Instrument [Line Items] | |||||
Maximum interest rate on long-term debt | 7.83% | [5] | |||
Long-term Debt, Gross | 26,000,000 | [5] | 33,000,000 | [5] | |
Exelon Generation Co L L C [Member] | Capital Lease Obligations [Member] | |||||
Debt Instrument [Line Items] | |||||
Due in 2019 | 5,000,000 | ||||
Exelon Generation Co L L C [Member] | Social Security Administration [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.93% | ||||
Long-term Debt, Gross | 0 | 1,000,000 | |||
Commonwealth Edison Co [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 5,977,000,000 | 5,694,000,000 | |||
Unamortized debt discount and premium, net | -19,000,000 | -19,000,000 | |||
Long-term debt due within one year | -260,000,000 | -617,000,000 | |||
Long-term debt | 5,698,000,000 | 5,058,000,000 | |||
Interest rate on long-term debt | 6.35% | [6] | |||
Long-term debt to financing trusts | 206,000,000 | 206,000,000 | |||
Debt and Capital Lease Obligations | 5,698,000,000 | 5,058,000,000 | |||
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 206,000,000 | [1] | |||
Commonwealth Edison Co [Member] | Notes Payable to Banks [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 6.95% | [7] | |||
Maximum interest rate on long-term debt | 7.49% | [7] | |||
Long-term Debt, Gross | 148,000,000 | [7] | 148,000,000 | [7] | |
Commonwealth Edison Co [Member] | Capital Lease Obligations [Member] | |||||
Debt Instrument [Line Items] | |||||
Capital lease obligations, noncurrent | 8,000,000 | 8,000,000 | |||
Due in 2020 | 1,000,000 | ||||
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 1.95% | [8],[9] | |||
Maximum interest rate on long-term debt | 6.45% | [8],[9] | |||
Long-term Debt, Gross | 5,829,000,000 | [8],[9] | 5,546,000,000 | [8],[9] | |
PECO Energy Co [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 2,250,000,000 | 2,200,000,000 | |||
Unamortized debt discount and premium, net | -4,000,000 | -3,000,000 | |||
Long-term debt | 2,246,000,000 | 1,947,000,000 | |||
Long-term debt to financing trusts | 184,000,000 | [10] | 184,000,000 | [10] | |
Long-term debt due within one year | 0 | -250,000,000 | |||
Debt and Capital Lease Obligations | 2,246,000,000 | 1,947,000,000 | |||
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 7.38% | [10] | |||
Long-term debt to financing trusts | 81,000,000 | [10] | 81,000,000 | [10] | |
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 5.75% | [10] | |||
Long-term debt to financing trusts | 103,000,000 | [10] | 103,000,000 | [10] | |
PECO Energy Co [Member] | First Mortgage Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 1.20% | [11],[12] | |||
Maximum interest rate on long-term debt | 5.95% | [11],[12] | |||
Long-term Debt, Gross | 2,250,000,000 | [11],[12] | 2,200,000,000 | [11],[12] | |
Baltimore Gas and Electric Company [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 1,945,000,000 | 2,015,000,000 | |||
Unamortized debt discount and premium, net | -3,000,000 | -4,000,000 | |||
Long-term debt | 1,867,000,000 | 1,941,000,000 | |||
Long-term debt to financing trusts | 258,000,000 | 258,000,000 | |||
Long-term debt due within one year | -75,000,000 | -70,000,000 | |||
Debt and Capital Lease Obligations | 2,011,000,000 | ||||
Long-term debt | 1,867,000,000 | 1,941,000,000 | |||
Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member] | |||||
Debt Instrument [Line Items] | |||||
Interest rate on long-term debt | 6.20% | [13] | |||
Long-term debt to financing trusts | 258,000,000 | [13] | 258,000,000 | [13] | |
Baltimore Gas and Electric Company [Member] | Unsecured Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 2.80% | ||||
Maximum interest rate on long-term debt | 6.35% | ||||
Long-term Debt, Gross | 1,750,000,000 | 1,750,000,000 | |||
Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member] | |||||
Debt Instrument [Line Items] | |||||
Minimum interest rate on long-term debt | 5.72% | ||||
Maximum interest rate on long-term debt | 5.82% | ||||
Long-term Debt, Gross | $195,000,000 | $265,000,000 | |||
[1] | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. | ||||
[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 and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures. | ||||
[4] | Includes capital lease obligations of $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | ||||
[5] | Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively. | ||||
[6] | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. | ||||
[7] | Includes ComEd’s capital lease obligations of $8 million at both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053. | ||||
[8] | Includes first mortgage bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes. | ||||
[9] | Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture. | ||||
[10] | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. | ||||
[11] | Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control bonds and notes. | ||||
[12] | Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. | ||||
[13] | Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets. |
Debt_and_Credit_Agreements_Sch
Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) (USD $) | Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | ||
Debt Instrument [Line Items] | |||||
2015 | $1,739,000,000 | ||||
2016 | 1,269,000,000 | ||||
2017 | 2,400,000,000 | ||||
2018 | 1,415,000,000 | ||||
2019 | 982,000,000 | ||||
Thereafter | 13,599,000,000 | [1] | |||
Total | 21,404,000,000 | 131,000,000 | |||
Long-term debt to financing trusts | 648,000,000 | 648,000,000 | |||
BGE Trust Member [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 258,000,000 | [2] | 258,000,000 | [2] | |
ComEd Financing Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 206,000,000 | [2] | 206,000,000 | [2] | |
ComEd, PECO and BGE Financing Trusts [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 648,000,000 | [2] | |||
PECO Financing Trusts [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 184,000,000 | [2] | |||
Exelon Generation Co L L C [Member] | |||||
Debt Instrument [Line Items] | |||||
2015 | 604,000,000 | ||||
2016 | 4,000,000 | ||||
2017 | 705,000,000 | ||||
2018 | 75,000,000 | ||||
2019 | 682,000,000 | ||||
Thereafter | 6,064,000,000 | ||||
Total | 8,134,000,000 | ||||
Long-term debt to financing trusts | 943,000,000 | 1,523,000,000 | |||
Commonwealth Edison Co [Member] | |||||
Debt Instrument [Line Items] | |||||
2015 | 260,000,000 | ||||
2016 | 665,000,000 | ||||
2017 | 425,000,000 | ||||
2018 | 840,000,000 | ||||
2019 | 300,000,000 | ||||
Thereafter | 3,693,000,000 | [3] | |||
Total | 6,183,000,000 | ||||
Long-term debt to financing trusts | 206,000,000 | 206,000,000 | |||
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | 206,000,000 | [2] | |||
PECO Energy Co [Member] | |||||
Debt Instrument [Line Items] | |||||
2015 | 0 | ||||
2016 | 300,000,000 | ||||
2017 | 0 | ||||
2018 | 500,000,000 | ||||
2019 | 0 | ||||
Thereafter | 1,634,000,000 | [4] | |||
Total | 2,434,000,000 | ||||
Long-term debt to financing trusts | 184,000,000 | [5] | 184,000,000 | [5] | |
Baltimore Gas and Electric Company [Member] | |||||
Debt Instrument [Line Items] | |||||
2015 | 75,000,000 | ||||
2016 | 300,000,000 | ||||
2017 | 120,000,000 | ||||
2018 | 0 | ||||
2019 | 0 | ||||
Thereafter | 1,708,000,000 | [6] | |||
Total | 2,203,000,000 | ||||
Long-term debt to financing trusts | 258,000,000 | 258,000,000 | |||
Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term debt to financing trusts | $258,000,000 | [7] | $258,000,000 | [7] | |
[1] | Includes $648 million due to ComEd, PECO and BGE financing trusts. | ||||
[2] | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. | ||||
[3] | Includes $206 million due to ComEd financing trust. | ||||
[4] | Includes $184 million due to PECO financing trusts. | ||||
[5] | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. | ||||
[6] | ncludes $258 million due to BGE financing trust. | ||||
[7] | Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets. |
Income_Taxes_Components_of_Inc
Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Taxes [Line Items] | |||
Income taxes | $666 | $1,044 | $627 |
Exelon Generation Co L L C [Member] | |||
Income Taxes [Line Items] | |||
Income taxes | 207 | 615 | 500 |
Commonwealth Edison Co [Member] | |||
Income Taxes [Line Items] | |||
Income taxes | 268 | 152 | 239 |
PECO Energy Co [Member] | |||
Income Taxes [Line Items] | |||
Income taxes | 114 | 162 | 127 |
Baltimore Gas and Electric Company [Member] | |||
Income Taxes [Line Items] | |||
Current | 0 | 0 | 0 |
Income taxes | 140 | 134 | 7 |
Internal Revenue Service (IRS) [Member] | |||
Income Taxes [Line Items] | |||
Current | 121 | 744 | 37 |
Deferred | 576 | 140 | 701 |
Investment Tax Credit | 20 | 15 | 11 |
Internal Revenue Service (IRS) [Member] | Exelon Generation Co L L C [Member] | |||
Income Taxes [Line Items] | |||
Current | 360 | 250 | 104 |
Deferred | -35 | 360 | 326 |
Investment Tax Credit | 16 | 11 | 6 |
Internal Revenue Service (IRS) [Member] | Commonwealth Edison Co [Member] | |||
Income Taxes [Line Items] | |||
Current | -171 | 160 | -40 |
Deferred | 395 | -27 | 237 |
Investment Tax Credit | 2 | 2 | 2 |
Internal Revenue Service (IRS) [Member] | PECO Energy Co [Member] | |||
Income Taxes [Line Items] | |||
Current | 28 | 126 | 88 |
Deferred | 87 | 23 | 25 |
Investment Tax Credit | 0 | 1 | 2 |
Internal Revenue Service (IRS) [Member] | Baltimore Gas and Electric Company [Member] | |||
Income Taxes [Line Items] | |||
Current | 24 | 9 | -97 |
Deferred | 90 | 100 | 101 |
Investment Tax Credit | 1 | 1 | 1 |
State and Local Jurisdiction [Member] | |||
Income Taxes [Line Items] | |||
Current | 42 | 181 | -25 |
Deferred | -53 | -6 | -75 |
State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member] | |||
Income Taxes [Line Items] | |||
Current | 35 | 50 | -12 |
Deferred | -137 | -34 | 88 |
State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member] | |||
Income Taxes [Line Items] | |||
Current | 7 | 50 | 6 |
Deferred | 39 | -29 | 38 |
State and Local Jurisdiction [Member] | PECO Energy Co [Member] | |||
Income Taxes [Line Items] | |||
Current | -2 | 16 | 4 |
Deferred | 1 | -2 | 12 |
State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member] | |||
Income Taxes [Line Items] | |||
Deferred | $27 | $26 | $4 |
Income_Taxes_Reconciliation_to
Income Taxes - Reconciliation to Effective Tax Rate (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Income Taxes [Line Items] | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | 35.00% | [1] |
State income taxes, net of Federal income tax benefit | 1.30% | 4.80% | -3.50% | [1] |
Qualified nuclear decommissioning trust fund income | -2.40% | -3.70% | -5.40% | [1] |
Tax exempt income | 0.20% | 0.20% | 0.20% | [1] |
Domestic production activities deduction | 2.00% | 0.00% | 0.00% | [1] |
Health care reform legislation | -0.10% | -0.10% | -0.10% | [1] |
Amortization of investment tax credit, net deferred taxes | 1.10% | 1.90% | 1.10% | [1] |
Plant basis differences | -1.90% | -1.60% | -2.20% | [1] |
Merger expenses | 2.60% | [1],[2] | ||
Merger expenses (c) | 2.40% | [1] | ||
Statute of limitations expiration | -2.60% | -0.10% | -0.10% | [1] |
Production tax credits and other credits | -2.40% | -2.10% | -2.40% | [1] |
Non-controlling interest | -1.80% | |||
Other | 0.00% | 0.10% | 1.10% | [1] |
Effective income tax rate | 26.80% | 37.60% | 34.90% | [1] |
Exelon Generation Co L L C [Member] | ||||
Income Taxes [Line Items] | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | 35.00% | [1] |
State income taxes, net of Federal income tax benefit | -1.90% | 1.80% | 4.90% | [1] |
Qualified nuclear decommissioning trust fund income | -4.80% | -6.10% | -9.10% | [1] |
Tax exempt income | 0.50% | 0.30% | 0.40% | [1] |
Domestic production activities deduction | 4.10% | 0.00% | 0.00% | [1] |
Health care reform legislation | 0.00% | 0.00% | 0.00% | [1] |
Amortization of investment tax credit, net deferred taxes | 2.00% | 3.00% | 1.30% | [1] |
Plant basis differences | 0.00% | 0.00% | -3.70% | [1] |
Merger expenses | 4.40% | [1],[2] | ||
Merger expenses (c) | 0.00% | [1] | ||
Statute of limitations expiration | -5.30% | -0.20% | -0.30% | [1] |
Production tax credits and other credits | -4.80% | -3.40% | 0.00% | [1] |
Non-controlling interest | -3.70% | |||
Other | 0.60% | -0.70% | 0.40% | [1] |
Effective income tax rate | 16.90% | 36.70% | 47.30% | [1] |
Commonwealth Edison Co [Member] | ||||
Income Taxes [Line Items] | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | 35.00% | |
State income taxes, net of Federal income tax benefit | 4.50% | 3.40% | 4.60% | |
Qualified nuclear decommissioning trust fund income | 0.00% | 0.00% | 0.00% | |
Tax exempt income | 0.00% | 0.00% | 0.00% | |
Domestic production activities deduction | 0.00% | 0.00% | 0.00% | |
Health care reform legislation | -0.20% | -0.70% | -0.40% | |
Amortization of investment tax credit, net deferred taxes | 0.30% | 0.60% | 0.40% | |
Plant basis differences | -0.10% | -0.80% | 0.00% | |
Merger expenses | 0.00% | [2] | ||
Merger expenses (c) | 0.00% | |||
Statute of limitations expiration | 0.00% | 0.00% | 0.00% | |
Production tax credits and other credits | 0.00% | -0.10% | -0.30% | |
Non-controlling interest | 0.00% | |||
Other | -0.30% | -0.30% | 0.60% | |
Effective income tax rate | 39.60% | 37.90% | 38.70% | |
PECO Energy Co [Member] | ||||
Income Taxes [Line Items] | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | 35.00% | |
State income taxes, net of Federal income tax benefit | -0.10% | 1.60% | 2.00% | |
Qualified nuclear decommissioning trust fund income | 0.00% | 0.00% | 0.00% | |
Tax exempt income | 0.00% | 0.00% | 0.00% | |
Domestic production activities deduction | 0.00% | 0.00% | 0.00% | |
Health care reform legislation | 0.00% | 0.00% | 0.00% | |
Amortization of investment tax credit, net deferred taxes | 0.10% | 0.10% | 0.30% | |
Plant basis differences | -10.40% | -7.10% | 0.00% | |
Merger expenses | 0.00% | [2] | ||
Merger expenses (c) | 0.00% | |||
Statute of limitations expiration | 0.00% | 0.00% | ||
Production tax credits and other credits | 0.00% | 0.00% | -11.50% | |
Non-controlling interest | 0.00% | |||
Other | -0.10% | 0.30% | 0.20% | |
Effective income tax rate | 24.50% | 29.10% | 25.00% | |
Baltimore Gas and Electric Company [Member] | ||||
Income Taxes [Line Items] | ||||
U.S. Federal statutory rate | 35.00% | 35.00% | 35.00% | [3] |
State income taxes, net of Federal income tax benefit | 5.00% | 4.90% | 24.30% | [3] |
Qualified nuclear decommissioning trust fund income | 0.00% | 0.00% | 0.00% | [3] |
Tax exempt income | 0.00% | 0.00% | 0.00% | [3] |
Domestic production activities deduction | 0.00% | 0.00% | 0.00% | [3] |
Health care reform legislation | -0.20% | -0.20% | -11.60% | [3] |
Amortization of investment tax credit, net deferred taxes | 0.30% | 0.00% | 8.60% | [3] |
Plant basis differences | 0.20% | -0.20% | 0.00% | [3] |
Merger expenses | 0.00% | [2],[3] | ||
Merger expenses (c) | 24.20% | [3] | ||
Statute of limitations expiration | 0.00% | 0.00% | 0.00% | [3] |
Production tax credits and other credits | 0.00% | 0.00% | -9.00% | [3] |
Non-controlling interest | 0.00% | |||
Other | 0.20% | 0.90% | 13.90% | [3] |
Effective income tax rate | 39.90% | 39.00% | 63.60% | [3] |
[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] | 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. | |||
[3] | BGE activity represents the activity for the twelve months ended December 31, 2012. |
Income_Taxes_Tax_Effects_of_Te
Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Operating Loss Carryforwards [Line Items] | ||
Plant basis differences | ($12,143) | ($11,612) |
Accrual based contracts | -178 | -214 |
Derivatives and other financial instruments | -46 | -509 |
Deferred pension and postretirement obligation | 1,914 | 1,489 |
Nuclear decommissioning activities | -726 | -647 |
Deferred debt refinancing costs | 112 | 173 |
Regulatory assets and liabilities | -1,824 | -1,611 |
Tax loss carryforward | 111 | 252 |
Tax credit carryforward | 97 | 534 |
Investment in CENG | -563 | -541 |
Other, net | 1,029 | 804 |
Deferred income tax liabilities (net) | 12,217 | 11,882 |
Unamortized investment tax credits | -555 | -490 |
Total deferred income tax liabilities (net) and unamortized investment tax credits | -12,772 | -12,372 |
Exelon Generation Co L L C [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Plant basis differences | -3,834 | -3,879 |
Accrual based contracts | -178 | -214 |
Derivatives and other financial instruments | -79 | -505 |
Deferred pension and postretirement obligation | -390 | -362 |
Nuclear decommissioning activities | -726 | -646 |
Deferred debt refinancing costs | 57 | 79 |
Regulatory assets and liabilities | 0 | 0 |
Tax loss carryforward | 48 | 76 |
Tax credit carryforward | 143 | 534 |
Investment in CENG | -563 | -541 |
Other, net | 346 | 67 |
Deferred income tax liabilities (net) | 5,176 | 5,391 |
Unamortized investment tax credits | -528 | -454 |
Total deferred income tax liabilities (net) and unamortized investment tax credits | -5,704 | -5,845 |
Commonwealth Edison Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Plant basis differences | -3,945 | -3,523 |
Accrual based contracts | 0 | 0 |
Derivatives and other financial instruments | -4 | -4 |
Deferred pension and postretirement obligation | -543 | -522 |
Nuclear decommissioning activities | 0 | 0 |
Deferred debt refinancing costs | -18 | -21 |
Regulatory assets and liabilities | -286 | -241 |
Tax loss carryforward | 0 | 47 |
Tax credit carryforward | 0 | 0 |
Investment in CENG | 0 | 0 |
Other, net | 255 | 154 |
Deferred income tax liabilities (net) | 4,541 | 4,110 |
Unamortized investment tax credits | -20 | -22 |
Total deferred income tax liabilities (net) and unamortized investment tax credits | -4,561 | -4,132 |
PECO Energy Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Plant basis differences | -2,749 | -2,573 |
Accrual based contracts | 0 | 0 |
Derivatives and other financial instruments | 0 | 0 |
Deferred pension and postretirement obligation | 2 | 0 |
Nuclear decommissioning activities | 0 | 0 |
Deferred debt refinancing costs | -2 | -3 |
Regulatory assets and liabilities | 27 | 42 |
Tax loss carryforward | 11 | 11 |
Tax credit carryforward | 0 | 0 |
Investment in CENG | 0 | 0 |
Other, net | 111 | 122 |
Deferred income tax liabilities (net) | 2,600 | 2,401 |
Unamortized investment tax credits | -2 | -3 |
Total deferred income tax liabilities (net) and unamortized investment tax credits | -2,602 | -2,404 |
Baltimore Gas and Electric Company [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Plant basis differences | -1,661 | -1,538 |
Accrual based contracts | 0 | 0 |
Derivatives and other financial instruments | 0 | 0 |
Deferred pension and postretirement obligation | -53 | -74 |
Nuclear decommissioning activities | 0 | 0 |
Deferred debt refinancing costs | -4 | -5 |
Regulatory assets and liabilities | -258 | -253 |
Tax loss carryforward | 39 | 52 |
Tax credit carryforward | 0 | 0 |
Investment in CENG | 0 | 0 |
Other, net | 30 | 26 |
Deferred income tax liabilities (net) | 1,907 | 1,792 |
Unamortized investment tax credits | -5 | -6 |
Total deferred income tax liabilities (net) and unamortized investment tax credits | ($1,912) | ($1,798) |
Income_Taxes_Schedule_of_Carry
Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) (USD $) | Dec. 31, 2014 | |
In Millions, unless otherwise specified | ||
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Credit Carryforward, Amount | $184 | [1] |
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Exelon Generation Co L L C [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Credit Carryforward, Amount | 184 | [1] |
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Commonwealth Edison Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Credit Carryforward, Amount | 0 | [1] |
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | PECO Energy Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Credit Carryforward, Amount | 0 | [1] |
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Baltimore Gas and Electric Company [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Tax Credit Carryforward, Amount | 0 | [1] |
State and Local Jurisdiction [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Federal general business credits carryforward | 3,141 | [2] |
State net operating losses and other credit carryforwards | 169 | |
Valuation allowance on state tax attributes | 50 | |
State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Federal general business credits carryforward | 1,693 | [3] |
State net operating losses and other credit carryforwards | 96 | |
Valuation allowance on state tax attributes | 48 | |
State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Federal general business credits carryforward | 0 | |
State net operating losses and other credit carryforwards | 0 | |
Valuation allowance on state tax attributes | 0 | |
State and Local Jurisdiction [Member] | PECO Energy Co [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Federal general business credits carryforward | 170 | |
State net operating losses and other credit carryforwards | 11 | |
Valuation allowance on state tax attributes | 0 | |
State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member] | ||
Operating Loss Carryforwards [Line Items] | ||
Federal general business credits carryforward | 730 | |
State net operating losses and other credit carryforwards | 39 | |
Valuation allowance on state tax attributes | $1 | |
[1] | Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015 | |
[2] | Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015. | |
[3] | PECO’s state net operating losses will expire beginning in 2031. |
Income_Taxes_Reconciliation_of
Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||
Unrecognized tax benefits - beginning balance | $2,175 | $1,024 | $807 | |
Merger balance transfer | 195 | |||
Increases based on tax positions related to current year | 15 | 19 | 34 | |
Changes to tax positions that only affect timing | -255 | 649 | -88 | |
Increases based on tax positions prior to current year | 18 | 493 | 91 | |
Decreases based on tax positions prior to current year | -1 | -6 | -6 | |
Decrease from settlements with taxing authorities | -35 | -2 | ||
Decreases from expiration of statute of limitations | -88 | -4 | -7 | |
Unrecognized tax benefits - ending balance | 1,829 | 1,829 | 2,175 | 1,024 |
Exelon Generation Co L L C [Member] | ||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||
Unrecognized tax benefits - beginning balance | 1,415 | 876 | 683 | |
Merger balance transfer | 183 | |||
Increases based on tax positions related to current year | 15 | 19 | 3 | |
Changes to tax positions that only affect timing | 33 | 36 | -69 | |
Increases based on tax positions prior to current year | 18 | 493 | 91 | |
Decreases based on tax positions prior to current year | -661 | -2 | -5 | -6 |
Decrease from settlements with taxing authorities | -34 | -2 | ||
Decreases from expiration of statute of limitations | -88 | -4 | -7 | |
Unrecognized tax benefits - ending balance | 1,357 | 1,357 | 1,415 | 876 |
Commonwealth Edison Co [Member] | ||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||
Unrecognized tax benefits - beginning balance | 324 | 67 | 70 | |
Merger balance transfer | 0 | |||
Increases based on tax positions related to current year | 0 | 0 | 0 | |
Changes to tax positions that only affect timing | -175 | 257 | -3 | |
Increases based on tax positions prior to current year | 0 | 0 | 0 | |
Decreases based on tax positions prior to current year | 0 | 0 | 0 | |
Decrease from settlements with taxing authorities | 0 | 0 | ||
Decreases from expiration of statute of limitations | 0 | 0 | 0 | |
Unrecognized tax benefits - ending balance | 149 | 149 | 324 | 67 |
PECO Energy Co [Member] | ||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||
Unrecognized tax benefits - beginning balance | 44 | 44 | 48 | |
Merger balance transfer | 0 | |||
Increases based on tax positions related to current year | 0 | 0 | 0 | |
Changes to tax positions that only affect timing | 0 | 0 | -4 | |
Increases based on tax positions prior to current year | 0 | 0 | 0 | |
Decreases based on tax positions prior to current year | 0 | 0 | 0 | |
Decrease from settlements with taxing authorities | 0 | 0 | ||
Decreases from expiration of statute of limitations | 0 | 0 | 0 | |
Unrecognized tax benefits - ending balance | 44 | 44 | 44 | 44 |
Baltimore Gas and Electric Company [Member] | ||||
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||||
Unrecognized tax benefits - beginning balance | 0 | 0 | 11 | |
Merger balance transfer | 0 | |||
Increases based on tax positions related to current year | 0 | 0 | 0 | |
Changes to tax positions that only affect timing | 0 | 0 | -11 | |
Increases based on tax positions prior to current year | 0 | 0 | 0 | |
Decreases based on tax positions prior to current year | 0 | 0 | 0 | |
Decrease from settlements with taxing authorities | 0 | 0 | ||
Decreases from expiration of statute of limitations | 0 | 0 | 0 | |
Unrecognized tax benefits - ending balance | $0 | $0 | $0 | $0 |
Income_Taxes_Narrative_Details
Income Taxes - Narrative (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | 3 Months Ended | ||||||
In Millions, unless otherwise specified | Sep. 30, 2012 | Dec. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Mar. 31, 2013 | Dec. 31, 1999 |
Income Taxes [Line Items] | ||||||||||
Tax positions for which there is uncertainty about the timing of tax benefits | $1,129 | $1,129 | $1,387 | |||||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | 701 | 701 | 788 | |||||||
Unrecognized Tax Benefits | 1 | 6 | 6 | |||||||
Increase in unrecognized tax benefits resulting from settlements with taxing authorities | 188 | |||||||||
Deferred gain on sale of property | 1,200 | |||||||||
IRS asserted penalties for understatement of tax | 90 | |||||||||
Expected non-cash charge to earnings | 265 | |||||||||
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position | 810 | 810 | ||||||||
Potential interest expense from a successful IRS challenge of the like-kind exchange position | 310 | 310 | ||||||||
Proceeds from long-term capital lease obligations | 335 | |||||||||
Taxes accrued | 305 | 285 | 305 | 315 | ||||||
Cash tax benefit (detriment) as a result of repair costs deduction | 300 | |||||||||
Effective Income Tax Rate Reconciliation, Deduction, Other, Amount | 35 | |||||||||
Gas Distribution Repair Tax Benefit Expense | 26 | |||||||||
Deferred State Tax Asset From State Tax Apportionment | 72 | |||||||||
Income tax benefit recorded as a result of re-apportionment of state income taxes | 3 | 116 | ||||||||
Deferred state tax liability resulting from purchase accounting | 44 | |||||||||
Exelon Generation Co L L C [Member] | ||||||||||
Income Taxes [Line Items] | ||||||||||
Unrecognized tax benefits that if recognized would affect the effective tax rate | 672 | 672 | 768 | |||||||
Unrecognized Tax Benefits | 661 | 2 | 5 | 6 | ||||||
Taxes accrued | 248 | 248 | 212 | |||||||
Cash tax benefit (detriment) as a result of repair costs deduction | 28 | |||||||||
Income tax benefit recorded as a result of re-apportionment of state income taxes | 7 | 14 | ||||||||
Deferred state tax liability resulting from purchase accounting | 14 | |||||||||
Allocation of federal tax benefit under tax sharing agreement | 77 | 26 | ||||||||
Allocation of tax benefit from parent | 48 | |||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||
Income Taxes [Line Items] | ||||||||||
Unrecognized Tax Benefits | 0 | 0 | 0 | |||||||
Taxes accrued | 42 | 42 | 16 | |||||||
Cash tax benefit (detriment) as a result of repair costs deduction | 27 | |||||||||
Commonwealth Edison Co [Member] | ||||||||||
Income Taxes [Line Items] | ||||||||||
Unrecognized Tax Benefits | 0 | 0 | 0 | |||||||
Deferred gain on sale of property | 155 | |||||||||
Expected non-cash charge to earnings | 170 | |||||||||
Noncash contributions from parent | 172 | |||||||||
Taxes accrued | 59 | 59 | 62 | |||||||
Cash tax benefit (detriment) as a result of repair costs deduction | 250 | |||||||||
Intercompany Non Cash Allocation Of Tax Benefit | 273 | 0 | 11 | |||||||
PECO Energy Co [Member] | ||||||||||
Income Taxes [Line Items] | ||||||||||
Unrecognized Tax Benefits | 0 | 0 | 0 | |||||||
Taxes accrued | 3 | 3 | 24 | |||||||
Cash tax benefit (detriment) as a result of repair costs deduction | 95 | |||||||||
Gas Distribution Repair Tax Benefit Expense | 29 | |||||||||
Allocation of federal tax benefit under tax sharing agreement | 27 | |||||||||
Allocation of tax benefit from parent | 27 | 9 | ||||||||
Maximum [Member] | ||||||||||
Income Taxes [Line Items] | ||||||||||
Cash tax benefit (detriment) as a result of repair costs deduction | $120 |
Income_Taxes_Summary_of_Intere
Income Taxes - Summary of Interest Receivable (Payable) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Income Taxes [Line Items] | ||
Net interest receivable (payable) recognized related to uncertain tax positions | ($310) | ($349) |
Exelon Generation Co L L C [Member] | ||
Income Taxes [Line Items] | ||
Net interest receivable (payable) recognized related to uncertain tax positions | 40 | -37 |
Commonwealth Edison Co [Member] | ||
Income Taxes [Line Items] | ||
Net interest receivable (payable) recognized related to uncertain tax positions | -203 | -174 |
PECO Energy Co [Member] | ||
Income Taxes [Line Items] | ||
Net interest receivable (payable) recognized related to uncertain tax positions | 3 | 3 |
Baltimore Gas and Electric Company [Member] | ||
Income Taxes [Line Items] | ||
Net interest receivable (payable) recognized related to uncertain tax positions | ($1) | $0 |
Income_Taxes_Summary_of_Intere1
Income Taxes - Summary of Interest Expense (Income) (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Income Taxes [Line Items] | |||
Net interest (income) expense recognized related to uncertain tax positions | ($36) | $391 | ($1) |
Exelon Generation Co L L C [Member] | |||
Income Taxes [Line Items] | |||
Net interest (income) expense recognized related to uncertain tax positions | -50 | 17 | 11 |
Commonwealth Edison Co [Member] | |||
Income Taxes [Line Items] | |||
Net interest (income) expense recognized related to uncertain tax positions | 6 | 281 | -20 |
PECO Energy Co [Member] | |||
Income Taxes [Line Items] | |||
Net interest (income) expense recognized related to uncertain tax positions | 0 | -1 | -1 |
Baltimore Gas and Electric Company [Member] | |||
Income Taxes [Line Items] | |||
Net interest (income) expense recognized related to uncertain tax positions | $1 | $0 | $9 |
Asset_Retirement_Obligations_N
Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) (Exelon Generation Co L L C [Member], USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset Retirement Obligation, Current | $1 | $0 | ||
Nuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | 4,855 | [1] | 4,741 | |
Accretion expense | 334 | 259 | ||
Net increase (decrease) resulting from updates to estimated future cash flows | 19 | -140 | ||
Costs incurred to decommission retired plants | -7 | -5 | ||
ARO ending balance | 6,961 | [1] | 4,855 | [1] |
Asset Retirement Obligation, Current | 8 | 9 | ||
CENG [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Consolidation of CENG | $1,760 | [2] | ||
[1] | Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. | |||
[2] | Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. |
Asset_Retirement_Obligations_N1
Asset Retirement Obligations - Narrative (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Oct. 02, 2013 | Dec. 31, 2012 | |
reactor | ||||
Asset Retirement Obligations [Line Items] | ||||
Nuclear decommissioning annual recovery current | $24,000,000 | |||
Percent of additional decommissioning shortfall with recourse | 50.00% | |||
Nuclear decommissioning trust funds | 10,537,000,000 | 8,071,000,000 | ||
Minimum [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Years after cessation of plant operations | 20 years | |||
Exelon Generation Co L L C [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Increase (decrease) in asset retirement obligation | 2,100,000,000 | 114,000,000 | ||
Shortfall of decommissioning funds with recourse | 50,000,000 | |||
Percent of additional decommissioning shortfall with recourse | 5.00% | |||
Nuclear decommissioning trust funds | 10,537,000,000 | 8,071,000,000 | ||
Percent of NDT funds invested in equity | 52.00% | 48.00% | ||
Percent of NDT funds invested in fixed income securities | 48.00% | 52.00% | ||
Zion Station spent nuclear fuel obligation | 86,000,000 | |||
ZionSolutions rent payable | 1 | |||
EnergySolutions letter of credit | 200,000,000 | |||
Assumed annual after-tax return on NDT funds | 2.00% | |||
Assumed annual after-tax return on NDT funds for former PECO units | 3.00% | |||
Annual average accretion of the ARO | 5.00% | |||
Number of years used in present value measurement | 30 years | |||
Estimated annual after tax return on nuclear decommissioning funds lower bound | 6.00% | |||
Estimated annual after tax return on nuclear decommissioning funds upper bound | 6.30% | |||
Historical five-year annual average after-tax return on NDT funds | 9.00% | |||
NRC funding assurance parent guarantees | 115,000,000 | |||
Number of operating reactors | 104 | |||
Exelon Generation Co L L C [Member] | Minimum [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Years after cessation of plant operations | 10 years | |||
Exelon Generation Co L L C [Member] | Maximum [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Years after cessation of plant operations | 70 years | |||
Nuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Net increase (decrease) resulting from updates to estimated future cash flows | 19,000,000 | -140,000,000 | ||
Property, Plant and Equipment [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Net increase (decrease) resulting from updates to estimated future cash flows | $16,000,000 |
Asset_Retirement_Obligations_U
Asset Retirement Obligations - Unrealized Gain on NDT Funds (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Asset Retirement Obligations [Line Items] | ||||||
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units | $180 | [1] | $406 | [1] | $386 | [1] |
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units | 134 | [2],[3] | 146 | [2],[3] | 105 | [2],[3] |
Exelon Generation Co L L C [Member] | ||||||
Asset Retirement Obligations [Line Items] | ||||||
Unrealized Gain Loss Investment Income Pledged Assets | $29 | $7 | $73 | |||
[1] | Net unrealized gains 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. | |||||
[2] | Excludes $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, 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. | |||||
[3] | Net unrealized gains 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. |
Asset_Retirement_Obligations_P
Asset Retirement Obligations - Pledged Assets and Payables to ZionSolutions (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Asset Retirement Obligations [Line Items] | ||||
Carrying value of Zion Station pledged assets | $319 | $458 | ||
Exelon Generation Co L L C [Member] | ||||
Asset Retirement Obligations [Line Items] | ||||
Carrying value of Zion Station pledged assets | 319 | 458 | ||
Payable to Zion Solutions | 292 | [1] | 414 | [1] |
Current portion of payable to Zion Solutions | 137 | [2] | 109 | [2] |
Withdrawals by Zion Solutions to pay decommissioning costs | $666 | $498 | ||
[1] | 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. | |||
[2] | Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. |
Asset_Retirement_Obligations_N2
Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | $351 | [1] | $343 | |
Net increase (decrease) resulting from updates to estimated future cash flows | -1 | [2] | 1 | [2] |
Development projects | 11 | [3] | 2 | [3] |
Accretion expense | 15 | [4] | 18 | [4] |
Payments | -6 | -13 | ||
Reclassified to liabilities held for sale | -4 | [5] | ||
Asset Divestitures | -20 | [6] | ||
ARO ending balance | 346 | [1] | 351 | [1] |
Exelon Generation Co L L C [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Reduction to operating and maintenance expense due to updates to estimated future cash flows | -2 | 13 | ||
Asset Retirement Obligation, Current | 1 | 0 | ||
Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | 201 | [1] | 207 | |
Net increase (decrease) resulting from updates to estimated future cash flows | -2 | [2] | -11 | [2] |
Development projects | 11 | [3] | 2 | [3] |
Accretion expense | 11 | [4] | 13 | [4] |
Payments | -3 | -10 | ||
Reclassified to liabilities held for sale | -4 | [5] | ||
Asset Divestitures | -20 | [6] | ||
ARO ending balance | 194 | [1] | 201 | [1] |
Commonwealth Edison Co [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Reduction to operating and maintenance expense due to updates to estimated future cash flows | 1 | |||
Asset Retirement Obligation, Current | 1 | 2 | ||
Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | 101 | [1] | 99 | |
Net increase (decrease) resulting from updates to estimated future cash flows | 2 | [2] | 0 | [2] |
Development projects | 0 | [3] | 0 | [3] |
Accretion expense | 3 | [4] | 4 | [4] |
Payments | -2 | -2 | ||
Reclassified to liabilities held for sale | 0 | [5] | ||
Asset Divestitures | 0 | [6] | ||
ARO ending balance | 104 | [1] | 101 | [1] |
PECO Energy Co [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset Retirement Obligation, Current | 1 | 1 | ||
PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | 30 | [1] | 29 | |
Net increase (decrease) resulting from updates to estimated future cash flows | 0 | [2] | 0 | [2] |
Development projects | 0 | [3] | 0 | [3] |
Accretion expense | 1 | [4] | 1 | [4] |
Payments | -1 | 0 | ||
Reclassified to liabilities held for sale | 0 | [5] | ||
Asset Divestitures | 0 | [6] | ||
ARO ending balance | 30 | [1] | 30 | [1] |
Baltimore Gas and Electric Company [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset Retirement Obligation, Current | 1 | 0 | ||
Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | ||||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
ARO beginning balance | 19 | [1] | 8 | |
Net increase (decrease) resulting from updates to estimated future cash flows | -1 | [2] | 12 | [2] |
Development projects | 0 | [3] | 0 | [3] |
Accretion expense | 0 | [4] | 0 | [4] |
Payments | 0 | -1 | ||
Reclassified to liabilities held for sale | 0 | [5] | ||
Asset Divestitures | 0 | [6] | ||
ARO ending balance | $18 | [1] | $19 | [1] |
[1] | During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets. | |||
[2] | During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013. | |||
[3] | Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites. | |||
[4] | 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. | |||
[5] | Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information. | |||
[6] | Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. See Note 4 — Mergers, Acquisitions, and Dispositions for further information. |
Retirement_Benefits_Narrative_
Retirement Benefits - Narrative (Details) (USD $) | 3 Months Ended | 12 Months Ended | 1 Months Ended | 3 Months Ended | 0 Months Ended | |||||||
Mar. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2014 | Oct. 31, 2014 | Apr. 30, 2014 | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Defined benefit plan, amounts recognized In regulatory liabilities, before tax | $5,000,000 | |||||||||||
Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act | 0 | 0 | 17,000,000 | |||||||||
Expected qualified pension plan contributions | 447,000,000 | 447,000,000 | ||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 37,000,000 | 37,000,000 | ||||||||||
Projected Benefit Obligation In Excess Of Plan Assets [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Funded status of the pension and other postretirement benefit obligations | 81.00% | 88.00% | ||||||||||
Accumulated Benefit Obligation In Excess Of Plan Assets [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Funded status of the pension and other postretirement benefit obligations | 87.00% | 93.00% | ||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected qualified pension plan contributions | 230,000,000 | 230,000,000 | ||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 17,000,000 | 17,000,000 | ||||||||||
Exelon Generation Co L L C [Member] | CENG [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected non-qualified pension plan contributions | 4,000,000 | 4,000,000 | ||||||||||
Business Services Company [Member] | Remeasurement [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Regulatory asset increase (decrease) due to updated valuation adjustment | 125,000,000 | |||||||||||
Commonwealth Edison Co [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected qualified pension plan contributions | 138,000,000 | 138,000,000 | ||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 1,000,000 | 1,000,000 | ||||||||||
Expected other postretirement benefit plan contributions | 2,000,000 | 2,000,000 | ||||||||||
PECO Energy Co [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected qualified pension plan contributions | 40,000,000 | 40,000,000 | ||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 1,000,000 | 1,000,000 | ||||||||||
Expected other postretirement benefit plan contributions | 0 | 0 | ||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected qualified pension plan contributions | 1,000,000 | 1,000,000 | ||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 1,000,000 | 1,000,000 | ||||||||||
Expected other postretirement benefit plan contributions | 17,000,000 | 17,000,000 | ||||||||||
Exelon Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Regulatory asset increase (decrease) due to updated valuation adjustment | 34,000,000 | |||||||||||
Constellation Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
AOCI valuation adjustment | 12,000,000 | 1,000,000 | ||||||||||
Regulatory asset increase (decrease) due to updated valuation adjustment | 15,000,000 | |||||||||||
Pension Plan, Defined Benefit [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected return on plan assets | 7.00% | [1] | 7.50% | [1] | 7.50% | [1] | 7.00% | |||||
Discount rate | 4.80% | [2] | 3.92% | [3] | 4.74% | [4] | 3.95% | |||||
Increase (decrease) in pension obligation | 361,000,000 | |||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 1,064,000,000 | 1,064,000,000 | ||||||||||
Healthcare cost trend on covered charges | 7.00% | |||||||||||
Pension Plan, Defined Benefit [Member] | Remeasurement [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected return on plan assets | 6.59% | |||||||||||
Pension Plan, Defined Benefit [Member] | Exelon Generation Co L L C [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 6,000,000 | 6,000,000 | ||||||||||
Pension Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Benefit obligation increase (decrease) reflecting actual census data | 35,000,000 | 13,000,000 | ||||||||||
Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected return on plan assets | 7.75% | |||||||||||
Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | Minimum [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Discount rate | 3.60% | |||||||||||
Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | Maximum [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Discount rate | 4.30% | |||||||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Benefit obligation increase (decrease) due to design changes | 790,000,000 | |||||||||||
Regulatory asset increase (decrease) due to design changes | 240,000,000 | |||||||||||
Other comprehensive income (loss) due to design changes | 259,000,000 | |||||||||||
Expected return on plan assets | 6.59% | [1] | 6.45% | [1] | 6.68% | [1] | 6.59% | |||||
Discount rate | 4.90% | [2] | 4.00% | [3] | 4.80% | [4] | 4.30% | |||||
Increase (decrease) in pension obligation | 117,000,000 | |||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | 217,000,000 | 217,000,000 | ||||||||||
Healthcare cost trend on covered charges | 6.46% | |||||||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Benefit obligation increase (decrease) reflecting actual census data | 12,000,000 | 3,000,000 | ||||||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected return on plan assets | 4.55% | |||||||||||
Exelon Sponsored Benefit Plan [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Expected qualified pension plan contributions | 36,000,000 | 36,000,000 | ||||||||||
Non-Qualified Pension Plan [Member] | ||||||||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||||||||
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months | $15,000,000 | $15,000,000 | ||||||||||
[1] | Not applicable to pension and other postretirement benefit plans that do not have plan asset | |||||||||||
[2] | )The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectivel | |||||||||||
[3] | 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 measurements | |||||||||||
[4] | The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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 remeasurement |
Retirement_Benefits_Summary_of
Retirement Benefits - Summary of Changes in Benefit Obligations (Details) (USD $) | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||||
Net benefit obligation at beginning of year | $15,459 | $16,800 | |||
Service cost | 293 | 317 | 280 | ||
Interest cost | 749 | 650 | 698 | ||
Plan participants’ contributions | 0 | 0 | |||
Actuarial loss (gain) | 2,095 | -1,363 | |||
Plan amendments | 0 | 1 | |||
Acquisitions/divestitures(a) | 594 | 0 | |||
Curtailments | -8 | 0 | |||
Settlements | -30 | [1] | -69 | [1] | |
Gross benefits paid | -896 | -877 | |||
Net benefit obligation at end of year | 18,256 | 15,459 | 16,800 | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward] | |||||
Net benefit obligation at beginning of year | 4,451 | 4,820 | |||
Service cost | 117 | 162 | 156 | ||
Interest cost | 186 | 194 | 205 | ||
Plan participants’ contributions | 42 | 34 | |||
Actuarial loss (gain) | 502 | -551 | |||
Plan amendments | -1,012 | 15 | |||
Acquisitions/divestitures(a) | 142 | 0 | |||
Curtailments | 0 | 0 | |||
Settlements | 0 | [1] | 0 | [1] | |
Gross benefits paid | -231 | -223 | |||
Net benefit obligation at end of year | $4,197 | $4,451 | $4,820 | ||
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246N0NFMEI0QkQ2ODg4NDYzNDFGOTY4RTdCNDgxQjJFMTIM} |
Retirement_Benefits_Summary_of1
Retirement Benefits - Summary of Changes in Plan Assets (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | $13,571 | $13,357 | ||
Actual return on plan assets | 1,443 | 821 | ||
Employer contributions | 332 | 339 | ||
Plan participants’ contributions | 0 | 0 | ||
Benefits paid | -896 | -877 | ||
Acquisitions/divestitures(a) | 454 | 0 | ||
Settlements | -30 | [1] | -69 | [1] |
Fair value of net plan assets at end of year | 14,874 | 13,571 | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 2,238 | 2,135 | ||
Actual return on plan assets | 90 | 209 | ||
Employer contributions | 291 | 83 | ||
Plan participants’ contributions | 42 | 34 | ||
Benefits paid | -231 | -223 | ||
Acquisitions/divestitures(a) | 0 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Fair value of net plan assets at end of year | $2,430 | $2,238 | ||
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246N0NFMEI0QkQ2ODg4NDYzNDFGOTY4RTdCNDgxQjJFMTIM} |
Retirement_Benefits_Balance_Sh
Retirement Benefits - Balance Sheet locations of Benefit Obligations and Plan Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Pension Plan, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other current liabilities | $16 | $12 |
Pension obligations | 3,366 | 1,876 |
Non-pension postretirement benefit obligations | 0 | 0 |
Unfunded status (net benefit obligation less net plan assets) | 3,382 | 1,888 |
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Other current liabilities | 25 | 23 |
Pension obligations | 0 | 0 |
Non-pension postretirement benefit obligations | 1,742 | 2,190 |
Unfunded status (net benefit obligation less net plan assets) | $1,767 | $2,213 |
Retirement_Benefits_Projected_
Retirement Benefits - Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Projected Benefit Obligation In Excess Of Plan Assets [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected benefit obligation | $18,256 | $15,452 |
Fair value of net plan assets | 14,874 | 13,564 |
Accumulated Benefit Obligation In Excess Of Plan Assets [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Projected benefit obligation | 18,256 | 15,452 |
Fair value of net plan assets | 14,874 | 13,564 |
Accumulated benefit obligation | $17,191 | $14,552 |
Retirement_Benefits_Components
Retirement Benefits - Components of Net Periodic Benefit Cost (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Commonwealth Edison Co [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Contractual termination benefit cost | $1 | |||||
Baltimore Gas and Electric Company [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Contractual termination benefit cost | 4 | |||||
Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost | 293 | 317 | 280 | |||
Interest cost | 749 | 650 | 698 | |||
Expected return on assets | -994 | -1,015 | -988 | |||
Transition obligation | 0 | 0 | 0 | |||
Prior service cost (credit) | 14 | 14 | 15 | |||
Actuarial loss | 420 | 562 | 450 | |||
Curtailment benefits | 0 | 0 | 0 | |||
Settlement charges | 2 | 9 | 31 | |||
Contractual termination benefit cost | 0 | [1] | 0 | [1] | 14 | [1] |
Net periodic benefit cost | 484 | 537 | 500 | |||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost | 117 | 162 | 156 | |||
Interest cost | 186 | 194 | 205 | |||
Expected return on assets | -154 | -132 | -115 | |||
Transition obligation | 0 | 0 | 11 | |||
Prior service cost (credit) | -122 | -19 | -17 | |||
Actuarial loss | 50 | 83 | 81 | |||
Curtailment benefits | 0 | 0 | -7 | |||
Settlement charges | 0 | 0 | 0 | |||
Contractual termination benefit cost | 0 | [1] | 0 | [1] | 6 | [1] |
Net periodic benefit cost | $77 | $288 | $320 | |||
[1] | )ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in |
Retirement_Benefits_Components1
Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Current year actuarial (gain) loss | $1,639 | ($1,169) | $1,693 | |||
Amortization of actuarial loss | -420 | -562 | -450 | |||
Current year prior service (credit) cost | 0 | 0 | 1 | |||
Amortization of prior service (cost) credit | -14 | -14 | -15 | |||
Current year transition (asset) obligation | 0 | 0 | 0 | |||
Amortization of transition asset (obligation) | 0 | 0 | 0 | |||
Curtailments | 0 | 0 | -10 | |||
Settlements | -2 | -8 | -31 | |||
Total recognized in AOCI and regulatory assets (liabilities) | 1,203 | [1] | -1,753 | [1] | 1,188 | [1] |
Defined benefit plan, amounts recognized in OCI, before tax | 788 | 1,071 | 283 | |||
Defined benefit plan, amounts recognized in regulatory assets, before tax | 415 | 682 | 904 | |||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Current year actuarial (gain) loss | 561 | -628 | 304 | |||
Amortization of actuarial loss | -50 | -83 | -81 | |||
Current year prior service (credit) cost | -1,012 | 15 | -109 | |||
Amortization of prior service (cost) credit | 122 | 19 | 17 | |||
Current year transition (asset) obligation | 0 | 0 | 1 | |||
Amortization of transition asset (obligation) | 0 | 0 | -11 | |||
Curtailments | 0 | 0 | -1 | |||
Settlements | 0 | 0 | 0 | |||
Total recognized in AOCI and regulatory assets (liabilities) | -379 | [1] | -677 | [1] | 120 | [1] |
Defined benefit plan, amounts recognized in OCI, before tax | 162 | 352 | 39 | |||
Defined benefit plan, amounts recognized in regulatory assets, before tax | $217 | $325 | $81 | |||
[1] | )Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. 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. |
Retirement_Benefits_Gross_Accu
Retirement Benefits - Gross Accumulated Other Comprehensive Loss and Regulatory Assets (Liabilities) not Recognized as Components of Periodic Benefit Cost (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Prior service cost (credit) | $49 | $62 | ||
Actuarial loss | 7,407 | 6,192 | ||
Total | 7,456 | [1] | 6,254 | [1] |
Benefits included in accumulated other comprehensive income | 4,310 | 3,523 | ||
Benefits included in regulatory assets | 3,146 | 2,731 | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Prior service cost (credit) | -963 | -73 | ||
Actuarial loss | 985 | 474 | ||
Total | 22 | [1] | 401 | [1] |
Benefits included in accumulated other comprehensive income | 161 | |||
Benefits included in regulatory assets | $22 | $240 | ||
[1] | )Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. 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 |
Retirement_Benefits_Components2
Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets expected to be Amortized as Components of Periodic Benefit Cost (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2012 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year | ($101) | ||
Benefits included in accumulated other comprehensive income | -51 | ||
Benefits included in regulatory assets | -50 | ||
Pension Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | 13 | ||
Defined Benefit Plan, Future Amortization of Gain (Loss) | 562 | ||
Benefits included in accumulated other comprehensive income | 575 | [1] | |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax | 329 | ||
Pension Plan, Defined Benefit [Member] | Regulatory Assets [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax | 246 | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 10 | ||
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit) | -175 | ||
Defined Benefit Plan, Future Amortization of Gain (Loss) | 74 | ||
Benefits included in accumulated other comprehensive income | ($101) | [1] | |
[1] | )Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, respectivel |
Retirement_Benefits_Assumption
Retirement Benefits - Assumptions Used in Calculations (Details) | 0 Months Ended | 12 Months Ended | 1 Months Ended | 0 Months Ended | |||||
Oct. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2014 | Apr. 30, 2014 | ||||
Pension Plan, Defined Benefit [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate | 3.94% | 4.80% | 3.92% | ||||||
Discount rate | 3.95% | 4.80% | [1] | 3.92% | [2] | 4.74% | [3] | ||
Expected return on plan assets | 7.00% | 7.00% | [4] | 7.50% | [4] | 7.50% | [4] | ||
Rate of compensation increase | 3.75% | ||||||||
Pension Plan, Defined Benefit [Member] | Remeasurement [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Expected return on plan assets | 6.59% | ||||||||
Discount rate used for remeasurement due to design changes | 4.21% | 3.71% | |||||||
Pension Plan, Defined Benefit [Member] | First Five Years [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Rate of compensation increase | 3.25% | 3.25% | |||||||
Rate of compensation increase | 3.25% | 3.25% | |||||||
Pension Plan, Defined Benefit [Member] | Thereafter [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Rate of compensation increase | 3.75% | 3.75% | |||||||
Rate of compensation increase | 3.75% | 3.75% | |||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate | 3.92% | 4.90% | 4.00% | ||||||
Discount rate | 4.90% | [1] | 4.00% | [2] | 4.80% | [3] | 4.30% | ||
Expected return on plan assets | 6.59% | [4] | 6.45% | [4] | 6.68% | [4] | 6.59% | ||
Rate of compensation increase | 3.75% | ||||||||
Health care cost trend rate | 6.00% | 6.50% | 6.50% | ||||||
Ultimate health care cost trend rate | 5.00% | 5.00% | 5.00% | ||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate used for remeasurement due to design changes | 4.66% | 3.72% | |||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Minimum [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate used for remeasurement due to design changes | 4.09% | ||||||||
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Maximum [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate used for remeasurement due to design changes | 4.55% | ||||||||
CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Minimum [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate used for remeasurement due to design changes | 3.60% | ||||||||
CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Maximum [Member] | |||||||||
Defined Benefit Plan Assumptions Used In Calculations [Line Items] | |||||||||
Discount rate used for remeasurement due to design changes | 4.30% | ||||||||
[1] | )The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectivel | ||||||||
[2] | 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 measurements | ||||||||
[3] | The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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 remeasurement | ||||||||
[4] | Not applicable to pension and other postretirement benefit plans that do not have plan asset |
Retirement_Benefits_Effects_of
Retirement Benefits - Effects of One Percentage Point Change in Assumed Health Care Cost Trend Rates (Details) (USD $) | 12 Months Ended |
In Millions, unless otherwise specified | Dec. 31, 2014 |
Compensation and Retirement Disclosure [Abstract] | |
Effect of a one percentage point increase in assumed healthcare cost trend on 2010 total service and interest cost components | $35 |
Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010 | 162 |
Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components | -24 |
Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010 | ($113) |
Retirement_Benefits_Contributi
Retirement Benefits - Contributions made to Pension and Other Postretirement Benefit Plans (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | $617 | $422 | $462 | |||
Expected qualified pension plan contributions | 447 | |||||
Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 332 | [1] | 339 | 149 | ||
Service cost | 293 | 317 | 280 | |||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 10 | |||||
Pension and non-pension postretirement benefit contributions | 291 | 83 | [2] | 323 | [2] | |
Service cost | 117 | 162 | 156 | |||
Defined Contribution Pension [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Service cost | 250 | |||||
Exelon Generation Co L L C [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 297 | 149 | 178 | |||
Expected qualified pension plan contributions | 230 | |||||
Exelon Generation Co L L C [Member] | CENG [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Expected non-qualified pension plan contributions | 4 | |||||
Exelon Generation Co L L C [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 173 | [1] | 119 | 48 | ||
Exelon Generation Co L L C [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 5 | |||||
Pension and non-pension postretirement benefit contributions | 124 | 30 | [2] | 135 | [2] | |
Exelon Corporate [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 9 | [1] | 72 | 13 | ||
Commonwealth Edison Co [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 248 | 122 | 138 | |||
Expected qualified pension plan contributions | 138 | |||||
Commonwealth Edison Co [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 122 | [1] | 118 | 25 | ||
Commonwealth Edison Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 4 | |||||
Pension and non-pension postretirement benefit contributions | 125 | 4 | [2] | 119 | [2] | |
PECO Energy Co [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 16 | 31 | 45 | |||
Expected qualified pension plan contributions | 40 | |||||
PECO Energy Co [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 11 | [1] | 11 | 13 | ||
PECO Energy Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 1 | |||||
Pension and non-pension postretirement benefit contributions | 5 | 20 | [2] | 33 | [2] | |
Baltimore Gas and Electric Company [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 16 | 24 | 16 | |||
Expected qualified pension plan contributions | 1 | |||||
Baltimore Gas and Electric Company [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 0 | [1],[3] | 0 | [3] | 0 | [3] |
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received | 2 | |||||
Pension and non-pension postretirement benefit contributions | 17 | [3] | 24 | [2],[3] | 12 | [2],[3] |
Business Services Company [Member] | Pension Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 26 | [1] | 91 | 63 | ||
Business Services Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | 20 | 5 | [2] | 24 | [2] | |
Constellation Legacy Benefit Plans [Member] | ||||||
Defined Benefit Plan Disclosure [Line Items] | ||||||
Pension and non-pension postretirement benefit contributions | $43 | [1] | ||||
[1] | )Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CEN | |||||
[2] | )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. Effective January 1, 2013, Exelon is no longer receiving this subsid | |||||
[3] | )BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statement |
Retirement_Benefits_Estimated_
Retirement Benefits - Estimated Future Benefit Payments (Details) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2015 | $37 |
Pension Plan, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2015 | 1,064 |
2016 | 962 |
2017 | 979 |
2018 | 1,004 |
2019 | 1,032 |
2020 through 2024 | 5,825 |
Total estimated future benefit payments through 2024 | 10,866 |
Other Postretirement Benefit Plan, Defined Benefit [Member] | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
2015 | 217 |
2016 | 223 |
2017 | 230 |
2018 | 236 |
2019 | 247 |
2020 through 2024 | 1,373 |
Total estimated future benefit payments through 2024 | $2,526 |
Retirement_Benefits_Allocated_
Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | $561 | $825 | $820 | |||
Exelon Generation Co L L C [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 250 | 347 | 341 | |||
Commonwealth Edison Co [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 162 | 309 | 282 | |||
PECO Energy Co [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 36 | 43 | 50 | |||
Business Services Company [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 46 | [1] | 71 | [1] | 99 | [1] |
Baltimore Gas and Electric Company [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 67 | [2],[3] | 55 | [2],[3] | 60 | [2],[3] |
Constellation Legacy Benefit Plans [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 12 | |||||
Pension and Other Postretirement Benefits [Member] | Commonwealth Edison Co [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | 1 | |||||
Pension and Other Postretirement Benefits [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Amount included in capital and operating & maintenance expense | $3 | [2],[3] | ||||
[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 charg | |||||
[2] | 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. | |||||
[3] | The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 201 |
Retirement_Benefits_Pension_an
Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Percentage of Plan Assets | 100.00% | 100.00% | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Percentage of Plan Assets | 42.00% | 45.00% | ||
Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Percentage of Plan Assets | 33.00% | 35.00% | ||
Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 41.00% | |||
Equity Securities [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 32.00% | |||
Fixed Income Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 34.00% | |||
Percentage of Plan Assets | 34.00% | 37.00% | ||
Fixed Income Securities [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 37.00% | |||
Percentage of Plan Assets | 37.00% | 37.00% | ||
Alternative Investments [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 25.00% | [1] | ||
Percentage of Plan Assets | 24.00% | [1] | 18.00% | [1] |
Alternative Investments [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||
Target asset allocation percentage | 31.00% | [1] | ||
Percentage of Plan Assets | 30.00% | [1] | 28.00% | [1] |
[1] | Alternative investments include private equity, hedge funds and real estate. |
Retirement_Benefits_Fair_Value
Retirement Benefits - Fair Value Measurements of Pension and Postretirement Benefit Plan Assets (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
In Millions, unless otherwise specified | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Derivative, notional amount | $1,491 | $2,651 | |||
Net assets pending transactions excluded | 42 | 43 | |||
Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2,430 | 2,238 | 2,135 | ||
Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 14,874 | 13,571 | 13,357 | ||
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 226 | 115 | 108 | ||
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 3,251 | 2,470 | 2,415 | ||
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 | ||
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2 | 2 | 0 | ||
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 0 | 0 | ||
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 272 | 41 | 0 | ||
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | 2 | 1 | ||
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 904 | 806 | 754 | ||
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 110 | 4 | 12 | ||
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,329 | 1,039 | 1,235 | ||
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 116 | 109 | 95 | ||
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 744 | 582 | 426 | ||
Fair Value, Measurements, Recurring [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 17,261 | [1],[2] | 15,766 | [1],[2] | |
Fair Value, Measurements, Recurring [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2,427 | [2] | 2,233 | [2] | |
Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 14,834 | [2] | 13,533 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 5,323 | [1],[2] | 5,368 | [1],[2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 767 | [2] | 831 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 4,556 | [2] | 4,537 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 8,461 | [1],[2] | 7,813 | [1],[2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,434 | [2] | 1,287 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 7,027 | [2] | 6,526 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 3,477 | [1],[2] | 2,585 | [1],[2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 226 | [2] | 115 | [2] | |
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 3,251 | [2] | 2,470 | [2] | |
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 11 | [2] | 51 | [2] | |
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 1 | [2] | |||
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 11 | [2] | 51 | [2] | |
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
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Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2],[3] | 0 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Assets [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 4 | [2],[3] | 7 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Assets [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2],[3] | 0 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Liabilities [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | -16 | [2],[3] | -134 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2],[3] | 0 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | -16 | [2],[3] | -134 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2],[3] | 0 | [2],[3] | |
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2 | [2] | |||
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 904 | [2] | 806 | [2] | |
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | |||
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | |||
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2 | [2] | |||
Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 904 | [2] | 806 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 449 | [2] | 299 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 2,684 | [2] | 2,305 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 0 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 339 | [2] | 295 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,355 | [2] | 1,266 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 110 | [2] | 4 | [2] | |
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 1,329 | [2] | 1,039 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 124 | [2] | 122 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 987 | [2] | 848 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 8 | [2] | 8 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 243 | [2] | 264 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 5 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 0 | [2] | 2 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | 116 | [2] | 109 | [2] | |
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | |||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||||
Defined Benefit Plan, Fair Value of Plan Assets | $744 | [2] | $582 | [2] | |
[1] | Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, 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. | ||||
[2] | See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. | ||||
[3] | Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, 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. |
Retirement_Benefits_Reconcilia
Retirement Benefits - Reconciliation of Level 3 Assets and Liabilities measured at Fair Value for Pension and Other Postretirement Benefit Plans (Details) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | ||
Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | $13,571 | $13,357 | ||
Purchases | 454 | 0 | ||
Fair value of net plan assets at end of year | 14,874 | 13,571 | ||
Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 2,238 | 2,135 | ||
Purchases | 0 | 0 | ||
Fair value of net plan assets at end of year | 2,430 | 2,238 | ||
Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Transfers into (out of) Level 3 | 56 | |||
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 2,470 | 2,415 | ||
Relating to assets still held at the reporting date | 279 | 292 | ||
Relating to assets sold during the period | 3 | -1 | ||
Purchases | 847 | 752 | ||
Sales | -60 | -167 | ||
Settlements | -301 | [1] | -198 | [1] |
Transfers into (out of) Level 3 | 13 | [2],[3] | -623 | [2] |
Fair value of net plan assets at end of year | 3,251 | 2,470 | ||
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | Constellation Energy Group Acquisition [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Transfers into (out of) Level 3 | 825 | |||
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 115 | 108 | ||
Relating to assets still held at the reporting date | 14 | 12 | ||
Purchases | 111 | 4 | ||
Sales | -13 | -1 | ||
Settlements | -1 | [1] | -4 | [1] |
Transfers into (out of) Level 3 | -4 | [2] | ||
Fair value of net plan assets at end of year | 226 | 115 | ||
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 1,039 | 1,235 | ||
Relating to assets still held at the reporting date | 77 | 143 | ||
Relating to assets sold during the period | 3 | 3 | ||
Purchases | 311 | 360 | ||
Sales | -38 | -76 | ||
Settlements | -33 | [1] | -3 | [1] |
Transfers into (out of) Level 3 | -30 | [2],[3] | -623 | [2] |
Fair value of net plan assets at end of year | 1,329 | 1,039 | ||
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 4 | 12 | ||
Relating to assets still held at the reporting date | 1 | 1 | ||
Purchases | 109 | 0 | ||
Sales | -4 | -1 | ||
Settlements | 0 | [1] | -4 | [1] |
Transfers into (out of) Level 3 | -4 | [2] | ||
Fair value of net plan assets at end of year | 110 | 4 | ||
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 806 | 754 | ||
Relating to assets still held at the reporting date | 112 | 86 | ||
Relating to assets sold during the period | 0 | 0 | ||
Purchases | 173 | 123 | ||
Sales | 0 | 0 | ||
Settlements | -203 | [1] | -157 | [1] |
Transfers into (out of) Level 3 | 16 | [2],[3] | 0 | [2] |
Fair value of net plan assets at end of year | 904 | 806 | ||
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 2 | 1 | ||
Relating to assets still held at the reporting date | 0 | 0 | ||
Purchases | 1 | 1 | ||
Sales | -2 | 0 | ||
Settlements | -1 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2] | ||
Fair value of net plan assets at end of year | 0 | 2 | ||
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 582 | 426 | ||
Relating to assets still held at the reporting date | 83 | 63 | ||
Relating to assets sold during the period | 0 | -4 | ||
Purchases | 136 | 226 | ||
Sales | -19 | -91 | ||
Settlements | -65 | [1] | -38 | [1] |
Transfers into (out of) Level 3 | 27 | [2],[3] | 0 | [2] |
Fair value of net plan assets at end of year | 744 | 582 | ||
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 109 | 95 | ||
Relating to assets still held at the reporting date | 13 | 11 | ||
Purchases | 1 | 3 | ||
Sales | -7 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2] | ||
Fair value of net plan assets at end of year | 116 | 109 | ||
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 41 | 0 | ||
Relating to assets still held at the reporting date | 7 | 0 | ||
Relating to assets sold during the period | 0 | 0 | ||
Purchases | 227 | 41 | ||
Sales | -3 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2],[3] | 0 | [2] |
Fair value of net plan assets at end of year | 272 | 41 | ||
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 0 | 0 | ||
Relating to assets still held at the reporting date | 0 | 0 | ||
Purchases | 0 | 0 | ||
Sales | 0 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2] | ||
Fair value of net plan assets at end of year | 0 | 0 | ||
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 2 | 0 | ||
Relating to assets still held at the reporting date | 0 | 0 | ||
Relating to assets sold during the period | 0 | 0 | ||
Purchases | 0 | 2 | ||
Sales | 0 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2],[3] | 0 | [2] |
Fair value of net plan assets at end of year | 2 | 2 | ||
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Fair value of net plan assets at beginning of year | 0 | 0 | ||
Relating to assets still held at the reporting date | 0 | 0 | ||
Purchases | 0 | 0 | ||
Sales | 0 | 0 | ||
Settlements | 0 | [1] | 0 | [1] |
Transfers into (out of) Level 3 | 0 | [2] | ||
Fair value of net plan assets at end of year | 0 | 0 | ||
Hedge Fund Investments [Member] | Fair Value, Inputs, Level 3 [Member] | ||||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | ||||
Transfers into (out of) Level 3 | $43 | $627 | ||
[1] | Represents cash settlements only. | |||
[2] | As of January 1, 2014 and January 1, 2013, 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, 2014 and 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 $43 million and $627 million in 2014 and 2013 respectively. | |||
[3] | In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million. |
Retirement_Benefits_Summary_of2
Retirement Benefits - Summary of Defined Contribution Savings Plan (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | $103 | $85 | $67 | |||
Exelon Generation Co L L C [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | 51 | 40 | 30 | |||
Commonwealth Edison Co [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | 26 | 22 | 19 | |||
PECO Energy Co [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | 8 | 8 | 7 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | 8 | [1] | 8 | [1] | 7 | [1] |
Business Services Company [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | 10 | [2] | 7 | [2] | 5 | [2] |
Constellation Energy Group LLC [Member] | ||||||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||||||
Savings plan matching contributions | $1 | |||||
[1] | BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012. | |||||
[2] | 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_Narrative_Details
Severance - Narrative (Details) (USD $) | 12 Months Ended | 3 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | |
Restructuring Cost and Reserve [Line Items] | ||||||
Severance costs | $124 | [1],[2] | ||||
Business Combination, Integration Related Costs | 19 | 28 | ||||
Payments | 24 | |||||
Constellation Energy Nuclear Group LLC [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance costs | 2 | |||||
Exelon Generation Co L L C [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance costs | 80 | [1] | 16 | |||
Business Combination, Integration Related Costs | 19 | |||||
Operating And Maintenance Expense [Member] | Exelon Generation Co L L C [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance costs | $3 | $2 | ||||
[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, 2012. | |||||
[2] | 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. |
Severance_Severance_Liabilitie
Severance - Severance Liabilities related to CENG (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | |
Restructuring Reserve [Roll Forward] | ||
Payments | ($24) | |
Severance [Member] | ||
Restructuring Reserve [Roll Forward] | ||
Beginning Balance | 2 | |
Severance charges | 3 | |
Payments | -11 | |
Ending Balance | 13 | |
Constellation Energy Group LLC [Member] | Severance [Member] | ||
Restructuring Reserve [Roll Forward] | ||
Severance charges | $19 | [1] |
[1] | Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information. |
Severance_Severance_Benefit_Co
Severance - Severance Benefit Costs associated with Job Reductions (Details) (USD $) | 12 Months Ended | 3 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2013 | |||
Restructuring Cost and Reserve [Line Items] | |||||||
Stock compensation | $7 | [1],[2] | |||||
Total severance benefits | 138 | [2],[3] | |||||
Severance costs | 124 | [1],[2] | |||||
Severance Costs [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Net regulatory assets | 35 | ||||||
Other Severance Charges [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance charges | 19 | [4] | 7 | [4] | 18 | [4] | |
Stock compensation | 7 | [1],[2] | |||||
Exelon Generation Co L L C [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Stock compensation | 4 | [1] | |||||
Total severance benefits | 88 | [3] | |||||
Severance costs | 80 | [1] | 16 | ||||
Exelon Generation Co L L C [Member] | Corporate, Non-Segment [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance costs | 46 | ||||||
Exelon Generation Co L L C [Member] | Other Severance Charges [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance charges | 14 | [4] | 5 | [4] | 16 | [4] | |
Stock compensation | 4 | [1] | |||||
Commonwealth Edison Co [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Stock compensation | 1 | [1],[2] | |||||
Total severance benefits | 16 | [2],[3] | |||||
Severance costs | 14 | [1],[2] | |||||
Commonwealth Edison Co [Member] | Corporate, Non-Segment [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance costs | 14 | ||||||
Commonwealth Edison Co [Member] | Severance Costs [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Net regulatory assets | 16 | ||||||
Commonwealth Edison Co [Member] | Other Severance Charges [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance charges | 2 | [4] | 1 | [4] | 2 | [4] | |
Stock compensation | 1 | [1],[2] | |||||
Baltimore Gas and Electric Company [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Stock compensation | 1 | [1],[2] | |||||
Total severance benefits | 19 | [2],[3] | |||||
Severance costs | 17 | [1],[2] | |||||
Baltimore Gas and Electric Company [Member] | Corporate, Non-Segment [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance costs | 7 | ||||||
Baltimore Gas and Electric Company [Member] | Severance Costs [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Net regulatory assets | 19 | ||||||
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance charges | 3 | [4] | 1 | [4] | 0 | [4] | |
Stock compensation | 1 | [1],[2] | |||||
PECO Energy Co [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Stock compensation | 0 | [1] | |||||
Total severance benefits | 7 | [3] | |||||
Severance costs | 7 | [1] | |||||
PECO Energy Co [Member] | Corporate, Non-Segment [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance costs | 7 | ||||||
PECO Energy Co [Member] | Other Severance Charges [Member] | |||||||
Restructuring Cost and Reserve [Line Items] | |||||||
Severance charges | 1 | [4] | 0 | [4] | 0 | [4] | |
Stock compensation | $0 | [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, 2012. | ||||||
[2] | 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. | ||||||
[3] | Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information. | ||||||
[4] | The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material |
Severance_Severance_Liabilitie1
Severance - Severance Liabilities Rollforward (Details) (USD $) | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||
Restructuring Cost and Reserve [Line Items] | |||||
Severance benefit obligation - beginning balance | $53 | $111 | |||
Stock compensation | 7 | [1],[2] | |||
Payments | -41 | -64 | |||
Severance benefit obligation - ending balance | 12 | 53 | 111 | ||
Severance [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance charges | 5 | [3] | |||
Stock Compensation Plan [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Stock compensation | 1 | ||||
Exelon Generation Co L L C [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance benefit obligation - beginning balance | 10 | 33 | |||
Stock compensation | 4 | [1] | |||
Payments | -7 | -24 | |||
Severance benefit obligation - ending balance | 3 | 10 | 33 | ||
Exelon Generation Co L L C [Member] | Severance [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance charges | 1 | [3] | |||
Exelon Generation Co L L C [Member] | Stock Compensation Plan [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Stock compensation | 0 | ||||
Commonwealth Edison Co [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance benefit obligation - beginning balance | 0 | 1 | |||
Stock compensation | 1 | [1],[2] | |||
Payments | 0 | -1 | |||
Severance benefit obligation - ending balance | 0 | 0 | 1 | ||
Commonwealth Edison Co [Member] | Severance [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance charges | 0 | [3] | |||
Commonwealth Edison Co [Member] | Stock Compensation Plan [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Stock compensation | 0 | ||||
PECO Energy Co [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance benefit obligation - beginning balance | 0 | 0 | |||
Stock compensation | 0 | [1] | |||
Payments | 0 | 0 | |||
Severance benefit obligation - ending balance | 0 | 0 | 0 | ||
PECO Energy Co [Member] | Severance [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance charges | 0 | [3] | |||
PECO Energy Co [Member] | Stock Compensation Plan [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Stock compensation | 0 | ||||
Baltimore Gas and Electric Company [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance benefit obligation - beginning balance | 6 | 11 | |||
Stock compensation | 1 | [1],[2] | |||
Payments | -4 | -5 | |||
Severance benefit obligation - ending balance | 2 | 6 | 11 | ||
Baltimore Gas and Electric Company [Member] | Severance [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Severance charges | 0 | [3] | |||
Baltimore Gas and Electric Company [Member] | Stock Compensation Plan [Member] | |||||
Restructuring Cost and Reserve [Line Items] | |||||
Stock compensation | $0 | ||||
[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, 2012. | ||||
[2] | 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. | ||||
[3] | 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, 2014 and December 31, 2013. |
Severance_Ongoing_Severance_Pl
Severance - Ongoing Severance Plans (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Other Severance Charges [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | $7 | [1] | $18 | [1] | $19 | [1] |
Business Service Company [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 2 | 0 | ||||
Severance [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 3 | |||||
Severance accrual | 3 | |||||
Exelon Generation Co L L C [Member] | Other Severance Charges [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 5 | [1] | 16 | [1] | 14 | [1] |
Exelon Generation Co L L C [Member] | Business Service Company [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 1 | |||||
Commonwealth Edison Co [Member] | Other Severance Charges [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 1 | [1] | 2 | [1] | 2 | [1] |
PECO Energy Co [Member] | Other Severance Charges [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | 0 | [1] | 0 | [1] | 1 | [1] |
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member] | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Severance charges | $1 | [1] | $0 | [1] | $3 | [1] |
[1] | The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material |
Preferred_and_Preference_Secur2
Preferred and Preference Securities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | 1-May-13 |
In Millions, except Share data, unless otherwise specified | |||
Preferred Stock [Member] | |||
Preferred Securities Additional Narrative Information [Line Items] | |||
Shares authorized | 100,000,000 | 100,000,000 | |
Commonwealth Edison Co [Member] | Preferred Stock [Member] | |||
Preferred Securities Additional Narrative Information [Line Items] | |||
Shares authorized | 850,000 | 850,000 | |
Commonwealth Edison Co [Member] | Cumulative Preferred Stock [Member] | |||
Preferred Securities Additional Narrative Information [Line Items] | |||
Shares authorized | 6,810,451 | 6,810,451 | |
PECO Energy Co [Member] | |||
Preferred Securities Additional Narrative Information [Line Items] | |||
Preferred securities | $87 | ||
Baltimore Gas and Electric Company [Member] | Preference Stock [Member] | |||
Preferred Securities Additional Narrative Information [Line Items] | |||
Shares authorized | 6,500,000 | 6,500,000 | |
Preferred stock, par value | 100 | 100 |
Preferred_and_Preference_Secur3
Preferred and Preference Securities - Summary of Preference Stock (Details) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | |
Class of Stock [Line Items] | |||
Shares outstanding | 1,900,000 | 1,900,000 | |
Dollar amount | $190 | $190 | |
Series 7.125% Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Dividend rate percentage | 7.13% | ||
Redemption price | $100 | [1] | |
Shares outstanding | 400,000 | 400,000 | |
Dollar amount | 40 | 40 | |
Series 6.97% Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Dividend rate percentage | 6.97% | ||
Redemption price | $100 | [1] | |
Shares outstanding | 500,000 | 500,000 | |
Dollar amount | 50 | 50 | |
Series 6.7% Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Dividend rate percentage | 6.70% | ||
Redemption price | $100 | [1] | |
Shares outstanding | 400,000 | 400,000 | |
Dollar amount | 40 | 40 | |
Series 6.99% Preferred Stock [Member] | |||
Class of Stock [Line Items] | |||
Dividend rate percentage | 6.99% | ||
Redemption price | $100 | [1] | |
Shares outstanding | 600,000 | 600,000 | |
Dollar amount | $60 | $60 | |
[1] | Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends. |
Schedule_of_Common_Stock_Autho
- Schedule of Common Stock Authorized and Outstanding (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Class of Stock [Line Items] | ||
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 859,833,343 | 857,290,484 |
Commonwealth Edison Co [Member] | ||
Class of Stock [Line Items] | ||
Par value | 12.5 | |
Common stock, shares authorized | 250,000,000 | |
Common stock, shares outstanding | 127,016,947 | 127,016,896 |
PECO Energy Co [Member] | ||
Class of Stock [Line Items] | ||
Common stock, shares authorized | 500,000,000 | |
Common stock, shares outstanding | 170,478,507 | 170,478,507 |
Baltimore Gas and Electric Company [Member] | ||
Class of Stock [Line Items] | ||
Common stock, shares authorized | 175,000,000 | |
Common stock, shares outstanding | 1,000 | 1,000 |
Common_Stock_Narrative_Details
Common Stock - Narrative (Details) (USD $) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Common Stock Narrative Information [Line Items] | |||||
Common stock shares reserved for warrant conversion | 24,511 | ||||
Equity offering | 57,500,000 | 57,500,000 | |||
Price per share (in usd per share) | $35 | $35 | |||
Underwriting discount | $60,000,000 | $35,000,000 | |||
Shares required to settle agreement | 4,000,000 | ||||
Junior subordinated notes | 1,150,000,000 | 1,150,000,000 | |||
Shares of junior subordinated notes | 23,000,000 | 23,000,000 | |||
Treasury stock, at cost | 2,327,000,000 | 2,327,000,000 | |||
Expiration period | 10 years | ||||
Obligations of outstanding restricted stock not settled | 85,000,000 | 77,000,000 | |||
Settlement of restricted stock | 43,000,000 | 28,000,000 | 25,000,000 | ||
Unrecognized compensation costs of nonvested restricted stock | 59,000,000 | ||||
Weighted average grant date fair value of performance shares (in usd per share) | 28.75 | 31.55 | 39.71 | ||
Settlement of performance shares | 27,000,000 | 26,000,000 | 23,000,000 | ||
Settlement of performance shares in cash | 13,000,000 | 12,000,000 | 3,000,000 | ||
Unrecognized compensation costs of performance based shares | 54,000,000 | ||||
Weighted-average period of recognition of unrecognized compensation costs of performance based shares | 1 year 7 months 6 days | ||||
2004 Repurchase Plan [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Common stock held as treasury stock | 35,000,000 | ||||
Treasury stock, at cost | 2,300,000,000 | ||||
Commonwealth Edison Co [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Warrants outstanding | 73,533 | 73,709 | |||
Common stock shares reserved for warrant conversion | 24,570 | ||||
Performance Shares [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Mix of awards | 67.00% | ||||
Percentage to be settled as common stock | 50.00% | ||||
Percentage to be settled as cash | 50.00% | ||||
Percentage to be settled as cash if ownership requirements are met | 100.00% | ||||
Weighted average grant date fair value (in usd per share) | $28.75 | ||||
Nonvested Stock Option [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Unrecognized compensation costs | 1,000,000 | ||||
Weighted-average period of recognition of unrecognized compensation costs | 1 year | ||||
Employee Stock Option [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Requisite service period | 4 years | ||||
Restricted Stock [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Mix of awards | 33.00% | ||||
Weighted-average period of recognition of unrecognized compensation costs | 2 years 1 month 6 days | ||||
Weighted average grant date fair value (in usd per share) | $28.71 | $31.06 | $39.94 | ||
Minimum [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Net proceeds at the forward price specified in agreements | 1,800,000,000 | 1,800,000,000 | |||
Minimum [Member] | Restricted Stock [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Requisite service period | 3 years | ||||
Maximum [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Net proceeds at the forward price specified in agreements | $1,900,000,000 | $1,900,000,000 | |||
Maximum [Member] | Restricted Stock [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Requisite service period | 5 years | ||||
LTIP [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Shares authorized | 16,000,000 | ||||
2013 Plan [Member] | Performance Shares [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Vesting period | 3 years | ||||
2012 Plan [Member] | Performance Shares [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Vesting period | 3 years | ||||
Performance period | 1 year | ||||
Performance Share Transition Award [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Percentage to be settled as common stock | 50.00% | ||||
Percentage to be settled as cash | 50.00% | ||||
Percentage to be settled as cash if ownership requirements are met | 100.00% | ||||
Performance Share Transition Award [Member] | Performance Shares [Member] | |||||
Common Stock Narrative Information [Line Items] | |||||
Vesting period | 1 year | ||||
Performance period | 2 years |
Common_Stock_Schedule_of_Stock
Common Stock - Schedule of Stock-based Compensation Expense (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Common Stock [Abstract] | |||
Performance share awards | $59 | $48 | $46 |
Restricted stock units | 61 | 61 | 50 |
Stock options | 2 | 3 | 15 |
Other stock-based awards | 5 | 6 | 4 |
Total stock-based compensation expense included in operating and maintenance expense | 127 | 118 | 115 |
Income tax benefit | -47 | -44 | -44 |
Total after-tax stock-based compensation expense | $80 | $74 | $71 |
Common_Stock_Schedule_of_PreTa
Common Stock - Schedule of Pre-Tax Stock-based Compensation Expense (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | $127 | $118 | $115 | [1] | ||
Exelon Generation Co L L C [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | 52 | 48 | 42 | [1] | ||
Commonwealth Edison Co [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | 7 | 9 | 11 | [1] | ||
PECO Energy Co [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | 3 | 5 | 5 | [1] | ||
Baltimore Gas and Electric Company [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | 5 | 6 | 5 | [1] | ||
Business Services Company [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | 60 | [2] | 50 | [2] | 52 | [1],[2] |
CENG [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Pre-tax stock-based compensation expense | $2 | |||||
[1] | 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 table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary above. | |||||
[2] | 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. |
Common_Stock_Components_of_Tax
Common Stock - Components of Tax Benefits from Stock-based Compensation (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Common Stock [Abstract] | |||
Stock options | $0 | $0 | $3 |
Restricted stock units | 17 | 11 | 11 |
Performance share awards | 11 | 11 | 7 |
Stock deferral plan | 0 | 1 | 0 |
Stock options | $0 | $0 | $2 |
Common_Stock_Assumptions_used_
Common Stock - Assumptions used in Calculating Fair Value of Options (Details) (USD $) | 12 Months Ended |
Dec. 31, 2012 | |
Common Stock [Abstract] | |
Dividend yield | 5.28% |
Expected volatility | 23.20% |
Risk-free interest rate | 1.30% |
Expected life (years) | 6 years 3 months |
Weighted average grant date fair value (per share) | $4.18 |
Common_Stock_Summary_of_Stock_
Common Stock - Summary of Stock Option Activity (Details) (Employee Stock Option [Member], USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
31-Dec-13 | 21,035,445 | ||
Options exercised | -291,805 | ||
Options forfeited | -8,886 | ||
Options expired | -1,903,787 | ||
31-Dec-14 | 18,830,967 | ||
Weighted Average Exercise Price (in usd per share) | $46.85 | $46.07 | |
Options Reinstated, Weighted Average Exercise Price (in usd per share) | $25.27 | ||
Options Forfeited, Weighted Average Exercise Price (in usd per share) | $55.78 | ||
Options Expired, Weighted Average Exercise Price (in usd per share) | $41.47 | ||
Shares Outstanding, Weighted Average Remaining Contractual Life | 4 years 1 month 10 days | ||
Shares Outstanding, Aggregate Intrinsic Value | $29 | ||
Exercisable at December 31, 2014 | 18,398,932 | [1] | |
Shares Exercisable, Weighted Average Exercise Price (in usd per share) | $47.01 | [1] | |
Shares Exercisable, Weighted Average Remaining Contractual Life | 4 years 15 days | [1] | |
Shares Exercisable, Aggregate Intrinsic Value | $29 | [1] | |
[1] | Includes stock options issued to retirement eligible employees. |
Common_Stock_Summary_of_Inform
Common Stock - Summary of Information of Stock Options Exercised (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Common Stock [Abstract] | ||||||
Aggregate value | $3 | [1] | $4 | [1] | $19 | [1] |
Cash received for exercise price | $7 | $19 | $47 | |||
[1] | Includes stock options issued to retirement eligible employees. |
Common_Stock_Summary_of_Nonves
Common Stock - Summary of Nonvested Stock Option Activity (Details) (Nonvested Stock Option [Member], USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Nonvested Stock Option [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward] | ||||
Nonvested at December 31, 2013 | 847,118 | [1] | ||
Vested | -406,197 | |||
Forfeited | -8,886 | |||
Nonvested at December 31, 2014 | 432,035 | [1] | ||
Nonvested, Weighted Average Exercise Price (in usd per share) | $39.91 | [1] | $40.22 | [1] |
Vested, Weighted Average Exercise Price (in usd per share) | $40.21 | |||
Forfeited, Weighted Average Exercise Price (in usd per share) | $55.78 | |||
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees | 746,140 | 1,348,913 | ||
[1] | Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. |
Common_Stock_Summary_of_Nonves1
Common Stock - Summary of Nonvested Restrict Stock Unit Activity (Details) (Restricted Stock [Member], USD $) | 12 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | ||||
Restricted Stock [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||||||
Nonvested at December 31, 2013 | 3,386,697 | [1] | |||||
Granted | 2,252,574 | ||||||
Vested | -1,216,016 | ||||||
Forfeited | -86,094 | ||||||
Undistributed vested awards | -578,943 | [2] | |||||
Nonvested at December 31, 2014 | 3,758,218 | [1] | 3,386,697 | [1] | |||
Nonvested, Weighted Average Exercise Price (in usd per share) | $34.10 | [1] | $31.27 | [1] | |||
Granted, Weighted Average Grant Date Fair Value (in usd per share) | $28.71 | $31.06 | $39.94 | ||||
Vested, Weighted Average Exercise Price (in usd per share) | $35.36 | ||||||
Forfeited, Weighted Average Exercise Price (in usd per share) | $31.99 | ||||||
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share) | $29.17 | [2] | |||||
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees | 975,116 | 931,628 | |||||
[1] | Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | ||||||
[2] | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014. |
Common_Stock_Summary_of_Nonves2
Common Stock - Summary of Nonvested Performance Share Awards Activity (Details) (Performance Shares [Member], USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Performance Shares [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | ||||
Nonvested at December 31, 2013 | 2,014,190 | [1] | ||
Granted | 1,712,085 | |||
Change in performance | 98,227 | |||
Vested | -497,714 | |||
Forfeited | -29,476 | |||
Undistributed vested awards | -601,215 | [2] | ||
Nonvested at December 31, 2014 | 2,696,097 | [1] | ||
Nonvested, Weighted Average Exercise Price (in usd per share) | $30.62 | [1] | $32.74 | [1] |
Granted, Weighted Average Grant Date Fair Value (in usd per share) | $28.75 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value | $31.85 | |||
Vested, Weighted Average Exercise Price (in usd per share) | $35.05 | |||
Forfeited, Weighted Average Exercise Price (in usd per share) | $30.16 | |||
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share) | $28.96 | [2] | ||
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees | 1,535,791 | 1,411,824 | ||
[1] | Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested. | |||
[2] | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014. |
Common_Stock_Balance_Sheet_Cla
Common Stock - Balance Sheet Classification of Obligations related to Outstanding Performance Share Awards Not Yet Settled (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | ||||
Common Stock [Abstract] | ||||
Current liabilities | $28 | [1] | $13 | [1] |
Deferred credits and other liabilities | 36 | [2] | 24 | [2] |
Common stock | 33 | 32 | ||
Total | $97 | $69 | ||
[1] | Represents the current liability related to performance share awards expected to be settled in cash. | |||
[2] | Represents the long-term liability related to performance share awards expected to be settled in cash. |
Earnings_Per_Share_and_Equity_2
Earnings Per Share and Equity - Schedule of Earnings per Share (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share [Abstract] | |||||||||||
Net income attributable to common shareholders | $1,623 | $1,719 | $1,160 | ||||||||
Weighted average common shares outstanding—basic | 861 | 861 | 860 | 858 | 856 | 857 | 856 | 855 | 860 | 856 | 816 |
Assumed exercise and/or distributions of stock-based awards | 4 | 4 | 3 | ||||||||
Weighted average common shares outstanding—diluted | 868 | 863 | 864 | 861 | 860 | 860 | 860 | 855 | 864 | 860 | 819 |
Earnings_Per_Share_and_Equity_3
Earnings Per Share and Equity - Narrative (Details) (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger) | 17,000,000 | 20,000,000 | 14,000,000 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 | |
Treasury stock, at cost | $2,327 | $2,327 | |
Pepco Holdings [Member] | |||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger) | 1,000,000 |
Changes_in_Accumulated_Other_C2
Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | ($2,040) | [1] | ($2,767) | [1] | ||
OCI before reclassifications | -528 | 791 | [1] | |||
Amounts reclassified from AOCI | -116 | -64 | [1],[2] | |||
Other comprehensive income (loss) | -644 | 727 | [1] | -317 | ||
Ending balance | -2,684 | -2,040 | [1] | -2,767 | [1] | |
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 120 | [1] | 368 | [1] | ||
OCI before reclassifications | -31 | 29 | [1] | |||
Amounts reclassified from AOCI | -117 | -277 | [1],[2] | |||
Other comprehensive income (loss) | -148 | -248 | [1] | |||
Ending balance | -28 | 120 | [1] | |||
Accumulated Net Unrealized Investment Gain (Loss) [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 2 | [1] | ||||
OCI before reclassifications | -1 | 2 | [1] | |||
Amounts reclassified from AOCI | 2 | |||||
Other comprehensive income (loss) | 1 | 2 | [1] | |||
Ending balance | 3 | 2 | [1] | |||
Accumulated Defined Benefit Plans Adjustment [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | -2,260 | [1] | -3,137 | [1] | ||
OCI before reclassifications | -498 | 669 | [1] | |||
Amounts reclassified from AOCI | 118 | 208 | [1],[2] | |||
Other comprehensive income (loss) | -380 | 877 | [1] | |||
Ending balance | -2,640 | -2,260 | [1] | |||
Accumulated Translation Adjustment [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | -10 | [1] | ||||
OCI before reclassifications | -9 | -10 | [1] | |||
Other comprehensive income (loss) | -9 | -10 | [1] | |||
Ending balance | -19 | -10 | [1] | |||
Accumulated Equity Investment [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 108 | [1] | 2 | [1] | ||
OCI before reclassifications | 11 | 101 | [1] | |||
Amounts reclassified from AOCI | -119 | 5 | [1],[2] | |||
Other comprehensive income (loss) | -108 | 106 | [1] | |||
Ending balance | 0 | 108 | [1] | |||
Exelon Generation Co L L C [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 214 | [1] | 513 | [1] | ||
OCI before reclassifications | -14 | 109 | [1] | |||
Amounts reclassified from AOCI | -236 | -408 | [1],[2] | |||
Other comprehensive income (loss) | -250 | -299 | [1] | -402 | ||
Ending balance | -36 | 214 | [1] | 513 | [1] | |
Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 114 | [1] | 512 | [1] | ||
OCI before reclassifications | -15 | 15 | [1] | |||
Amounts reclassified from AOCI | -117 | -413 | [1],[2] | |||
Other comprehensive income (loss) | -132 | -398 | [1] | |||
Ending balance | -18 | 114 | [1] | |||
Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 2 | [1] | 0 | [1] | ||
OCI before reclassifications | -1 | 2 | [1] | |||
Other comprehensive income (loss) | -1 | 2 | [1] | |||
Ending balance | 1 | 2 | [1] | |||
Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | -10 | [1] | ||||
OCI before reclassifications | -9 | -10 | [1] | |||
Other comprehensive income (loss) | -9 | -10 | [1] | |||
Ending balance | -19 | -10 | [1] | |||
Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 108 | [1] | 1 | [1] | ||
OCI before reclassifications | 11 | 102 | [1] | |||
Amounts reclassified from AOCI | -119 | 5 | [1],[2] | |||
Other comprehensive income (loss) | -108 | 107 | [1] | |||
Ending balance | 0 | 108 | [1] | |||
PECO Energy Co [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Beginning balance | 1 | [1] | 1 | [1] | ||
Other comprehensive income (loss) | 0 | 0 | 1 | |||
Ending balance | 1 | 1 | [1] | 1 | [1] | |
PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member] | ||||||
Movement in Accumulated Other Comprehensive Income [Roll Forward] | ||||||
Ending balance | $1 | $1 | [1] | $1 | [1] | |
[1] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. | |||||
[2] | See next tables for details about these reclassifications. |
Changes_in_Accumulated_Other_C3
Changes in Accumulated Other Comprehensive Income - Reclassifications out of Accumulated Other Comprehensive Income (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Revenues | $7,255 | $6,912 | $6,024 | $7,237 | $6,163 | $6,502 | $6,141 | $6,082 | $27,429 | [1] | $24,888 | [1] | $23,489 | [1] | ||
Interest expense | -610 | -896 | -575 | |||||||||||||
Prior service costs | 19 | 0 | -1 | |||||||||||||
Sale of equity method investment | 455 | 460 | 353 | |||||||||||||
Total income (loss) in equity method investments | -20 | 10 | -91 | |||||||||||||
Income before income taxes | 2,486 | 2,773 | 1,798 | |||||||||||||
Income tax benefit (expense) | -666 | -1,044 | -627 | |||||||||||||
Net income | 18 | [2] | 993 | 522 | 90 | 495 | 738 | 490 | -4 | [3] | 1,820 | 1,729 | 1,171 | |||
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Net income | 116 | [4] | 64 | [4] | ||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Net income | -2 | [4] | ||||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Revenues | -2 | [4] | ||||||||||||||
Income before income taxes | 195 | [4] | 461 | [4] | ||||||||||||
Income tax benefit (expense) | -78 | [4] | -184 | [4] | ||||||||||||
Net income | 117 | [4] | 277 | [4] | ||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Revenues | 195 | [4] | 464 | [4] | ||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Interest expense | -3 | [4] | ||||||||||||||
Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Sale of equity method investment | 5 | [4] | ||||||||||||||
Equity in losses of unconsolidated affiliates | 193 | [4] | ||||||||||||||
Total income (loss) in equity method investments | -8 | [4] | ||||||||||||||
Income before income taxes | -8 | [4] | ||||||||||||||
Income tax benefit (expense) | 3 | [4] | ||||||||||||||
Net income | -5 | [4] | ||||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Revenues | 4,802 | 4,412 | 3,789 | 4,390 | 3,772 | 4,255 | 4,070 | 3,533 | 17,393 | 15,630 | 14,437 | |||||
Interest expense | 50 | -2 | -55 | |||||||||||||
Sale of equity method investment | 406 | 355 | 246 | |||||||||||||
Total income (loss) in equity method investments | -20 | 10 | -91 | |||||||||||||
Income tax benefit (expense) | -207 | -615 | -500 | |||||||||||||
Net income | -91 | 771 | 340 | -185 | 269 | 490 | 330 | -18 | 1,019 | 1,060 | 558 | |||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Net income | 236 | [4] | 408 | [4] | ||||||||||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Income before income taxes | 195 | [4] | 683 | [4] | ||||||||||||
Income tax benefit (expense) | -78 | [4] | -270 | [4] | ||||||||||||
Net income | 117 | [4] | 413 | [4] | ||||||||||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Revenues | 195 | [4] | 683 | [4] | ||||||||||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Interest expense | 0 | [4] | ||||||||||||||
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Sale of equity method investment | 5 | [4] | ||||||||||||||
Equity in losses of unconsolidated affiliates | 193 | [4] | ||||||||||||||
Total income (loss) in equity method investments | -8 | [4] | ||||||||||||||
Income before income taxes | -8 | [4] | ||||||||||||||
Income tax benefit (expense) | 3 | [4] | ||||||||||||||
Net income | -5 | [4] | ||||||||||||||
Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Nuclear Decommissioning Attributable To Equity Method Investments [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Income before income taxes | 198 | [4] | ||||||||||||||
Income tax benefit (expense) | -79 | [4] | ||||||||||||||
Net income | 119 | [4] | ||||||||||||||
Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Nuclear Decommissioning Attributable To Equity Method Investments [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Income before income taxes | 198 | [4] | ||||||||||||||
Income tax benefit (expense) | -79 | [4] | ||||||||||||||
Net income | 119 | [4] | ||||||||||||||
Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Prior service costs | 46 | [4],[5] | -2 | [4],[5] | ||||||||||||
Actuarial gains/losses | -239 | [4],[5] | -339 | [4],[5] | ||||||||||||
Income before income taxes | -193 | [4] | -342 | [4] | ||||||||||||
Income tax benefit (expense) | 75 | [4] | 134 | [4] | ||||||||||||
Net income | -118 | [4] | -208 | [4] | ||||||||||||
Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member] | ||||||||||||||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items] | ||||||||||||||||
Actuarial gains/losses | ($1) | [4],[6] | ||||||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||||
[2] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||
[3] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||||
[4] | Amounts in parenthesis represent a decrease in net income. | |||||||||||||||
[5] | This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 16 — Retirement Benefits for additional details). | |||||||||||||||
[6] | Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense. |
Changes_in_Accumulated_Other_C4
Changes in Accumulated Other Comprehensive Income - Components of Accumulated Other Comprehensive Income (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Prior service costs | $19 | $0 | ($1) |
Actuarial loss reclassified to periodic cost, taxes | -93 | -133 | -110 |
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Transition (Asset) Obligation, Tax | -2 | ||
Pension and non-pension postretirement benefit plan valuation adjustment, taxes | 317 | -430 | 237 |
Change in unrealized gain (loss) on cash flow hedges, taxes | 96 | 166 | 68 |
Change in unrealized gain (loss) on equity investments taxes | 73 | -71 | -1 |
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax | 1 | ||
Other comprehensive income, income taxes | 412 | -468 | 192 |
Exelon Generation Co L L C [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Change in unrealized gain (loss) on cash flow hedges, taxes | 84 | 262 | 262 |
Change in unrealized gain (loss) on equity investments taxes | 73 | -72 | 1 |
Other comprehensive income, income taxes | $157 | $190 | $263 |
Commitments_and_Contingencies_2
Commitments and Contingencies - Narrative (Details) (USD $) | 0 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 3 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | 1 Months Ended | 12 Months Ended | 0 Months Ended | |||||||||||||
Jun. 05, 2013 | Jun. 30, 2013 | Dec. 31, 2014 | Dec. 31, 2012 | Apr. 12, 2012 | Feb. 28, 2012 | Jan. 31, 2013 | Oct. 31, 2007 | Jun. 30, 2014 | Dec. 31, 2013 | Jan. 31, 2005 | Nov. 19, 2013 | Jul. 11, 2011 | Sep. 30, 2014 | 31-May-06 | Dec. 31, 1999 | Jan. 22, 2015 | Jul. 26, 2013 | Dec. 27, 2013 | Dec. 12, 2014 | Dec. 22, 2014 | Mar. 31, 2014 | Dec. 31, 2003 | 30-May-12 | ||
Customer | Open_claim | Defendant | Defendant | Defendant | Customer | Principle_responsible_party | Principle_responsible_party | MW | MW | MW | MW | ||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Nuclear insurance liability limit per incident | $18,300,000 | ||||||||||||||||||||||||
Cost surcharge to Price-Anderson Act nuclear incident assessment | 5.00% | ||||||||||||||||||||||||
Guarantee obligations maximum exposure | 9,402,000,000 | ||||||||||||||||||||||||
Coal rail car lease proof of claims | 21,000,000 | ||||||||||||||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | 105,000,000 | ||||||||||||||||||||||||
Asbestos liability reserve | 100,000,000 | 90,000,000 | |||||||||||||||||||||||
Probable contingency (liability) | 22,000,000 | ||||||||||||||||||||||||
Open asbestos liability claims | 255 | ||||||||||||||||||||||||
Asbestos liability reserve related to anticipated claims | 78,000,000 | ||||||||||||||||||||||||
FERC civil penalty | 110,000,000 | ||||||||||||||||||||||||
FERC settlement recorded in operation and maintenance expense | 50,000,000 | ||||||||||||||||||||||||
Number of customers affected by a major storm | 34,559 | ||||||||||||||||||||||||
Rossville ash site [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Area of property | 32 | ||||||||||||||||||||||||
Cotter Corporation [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Number of defendants | 14 | 15 | |||||||||||||||||||||||
Nuclear Insurance Premiums [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Guarantee obligations maximum exposure | 3,014,000,000 | [1] | |||||||||||||||||||||||
Sithe Guarantee [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Guarantee obligations maximum exposure | 200,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Nuclear financial protection pool value | 375,000,000 | ||||||||||||||||||||||||
United States licensed nuclear reactors total | 104 | ||||||||||||||||||||||||
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses | 13,200,000,000 | ||||||||||||||||||||||||
Cost surcharge to Price-Anderson Act nuclear incident assessment | 12730000000.00% | ||||||||||||||||||||||||
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident | 19,000,000 | ||||||||||||||||||||||||
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident | 2,700,000,000 | ||||||||||||||||||||||||
Total retrospective premium obligation under insurance from a nuclear industry mutual insurance company | 319,000,000 | ||||||||||||||||||||||||
Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation | 3,200,000,000 | ||||||||||||||||||||||||
Cost of spent nuclear fuel disposal per kWh of net nuclear generation | 0.001 | ||||||||||||||||||||||||
Net nuclear fuel disposal fees | 49,000,000 | 136,000,000 | |||||||||||||||||||||||
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 | 2.00% | ||||||||||||||||||||||||
Capacity of energy construction project | 150 | ||||||||||||||||||||||||
Guarantee obligations maximum exposure | 6,384,000,000 | ||||||||||||||||||||||||
Consent decree penalty | 1,000,000 | ||||||||||||||||||||||||
Environmental loss contingencies | 13,000,000 | 14,000,000 | |||||||||||||||||||||||
Payments for operating leases | 10,000,000 | ||||||||||||||||||||||||
Increase (decrease) in the value of the asbestos liability reserve | 15,000,000 | 25,000,000 | |||||||||||||||||||||||
Open asbestos liability claims | 300 | ||||||||||||||||||||||||
FERC civil penalty | 135,000,000 | ||||||||||||||||||||||||
FERC settlement recorded in operation and maintenance expense | 195,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Cotter Corporation [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Total cost of remediation to be shared by PRPs | 50,000,000 | ||||||||||||||||||||||||
DOJ potential settlement | 90,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Rossville ash site [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Estimate of possible loss | 10,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Equity Method Investments [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Purchase obligations, due within two years | 38,000,000 | ||||||||||||||||||||||||
Unrecorded unconditional purchase obligation, due in next 12 months | 98,000,000 | ||||||||||||||||||||||||
Other unrecorded amounts | 20,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Perryman Construction [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Purchase obligations, due within two years | 39,000,000 | ||||||||||||||||||||||||
Capacity of energy construction project | 120 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Fourmile Wind Project [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Capacity of energy construction project | 40 | 40 | |||||||||||||||||||||||
Unrecorded unconditional purchase obligation, due in next 12 months | 2,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Combine-cycle Turbine Units [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Unrecorded unconditional purchase obligation, due in next 12 months | 1,000,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Fair Wind Project [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Capacity of energy construction project | 30 | 30 | |||||||||||||||||||||||
Unrecorded unconditional purchase obligation, due in next 12 months | 19,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Sendero Wind Project [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Capacity of energy construction project | 78 | ||||||||||||||||||||||||
Unrecorded unconditional purchase obligation, due in next 12 months | 56,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Beebe Construction [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Accrued environmental liabilities | 2,000,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Nuclear insurance liability limit per incident | 13,600,000,000 | ||||||||||||||||||||||||
Guarantee obligations maximum exposure | 3,014,000,000 | [2] | |||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Mutual Property Insurance Distribution To Members | 18,500,000 | ||||||||||||||||||||||||
Exelon Generation Co L L C [Member] | Sithe Guarantee [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Acquisition of interest in subsidiary | 50.00% | ||||||||||||||||||||||||
Sale of interest in subsidiary | 100.00% | ||||||||||||||||||||||||
Midwest Generation, LLC [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Environmental loss contingencies | 9,000,000 | ||||||||||||||||||||||||
Percentage agreed to reimburse related parties | 50.00% | ||||||||||||||||||||||||
Increase (decrease) in the value of the asbestos liability reserve | 6,000,000 | ||||||||||||||||||||||||
Midwest Generation's estimated environmental investigation and remediation costs | 53,000,000 | ||||||||||||||||||||||||
Commonwealth Edison Co [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Guarantee obligations maximum exposure | 222,000,000 | ||||||||||||||||||||||||
Total number of MGP sites | 42 | ||||||||||||||||||||||||
Sites approved for clean-up | 17 | ||||||||||||||||||||||||
Sites under study/remediation | 25 | ||||||||||||||||||||||||
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 possible defendants | 1,200,000 | ||||||||||||||||||||||||
Interest rate on long-term debt | 6.35% | [3] | |||||||||||||||||||||||
Commonwealth Edison Co [Member] | Minimum [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Value of damages sought | 500 | ||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Maximum [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Value of damages sought | 1,500 | ||||||||||||||||||||||||
Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Increase (decrease) in accrual for environmental loss contingencies | 26,000,000 | ||||||||||||||||||||||||
PECO Energy Co [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Guarantee obligations maximum exposure | 218,000,000 | ||||||||||||||||||||||||
Total number of MGP sites | 26 | ||||||||||||||||||||||||
Sites approved for clean-up | 16 | ||||||||||||||||||||||||
Sites under study/remediation | 10 | ||||||||||||||||||||||||
PECO Energy Co [Member] | Accrual For MGP Investigation And Remediation [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Increase (decrease) in accrual for environmental loss contingencies | 4,000,000 | ||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Guarantee obligations maximum exposure | 265,000,000 | ||||||||||||||||||||||||
Total number of MGP sites | 13 | ||||||||||||||||||||||||
Sites under study/remediation | 2 | ||||||||||||||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | 1,700,000 | ||||||||||||||||||||||||
Number of claimants | 486 | ||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Deferrable Interest Subordinated Debentures [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Interest rate on long-term debt | 6.20% | ||||||||||||||||||||||||
Baltimore Gas and Electric Company [Member] | Sixty-Eighth Street Dump [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Number of parties jointly and severally liable In environmental protection agency action | 19 | 19 | |||||||||||||||||||||||
Minimum estimated clean-up costs for all potentially responsible parties | 50,000,000 | ||||||||||||||||||||||||
Maximum estimated clean-up costs for all potentially responsible parties | 64,000,000 | ||||||||||||||||||||||||
Subsequent Event [Member] | |||||||||||||||||||||||||
Commitments and Contingencies [Line Items] | |||||||||||||||||||||||||
Settlement amount | $14,000,000 | ||||||||||||||||||||||||
[1] | 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. | ||||||||||||||||||||||||
[2] | 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, including CENG sites, 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. | ||||||||||||||||||||||||
[3] | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. |
Commitments_and_Contingencies_3
Commitments and Contingencies - Schedule of Government Agreement Settlements (Details) (Department of Energy [Member], Exelon Generation Co L L C [Member], USD $) | 9 Months Ended | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Department of Energy [Member] | Exelon Generation Co L L C [Member] | ||||||
Schedule of Government Agreements [Line Items] | ||||||
Spent Nuclear Fuel Storage Reimbursement | $33 | [1] | $836 | [1] | ||
Spent Nuclear Fuel Storage Reimbursement Net Co Owners | 30 | [1],[2] | 702 | [1],[2] | ||
DOE Receivable - Current | 82 | [3] | 82 | [3] | 71 | [3] |
DOE Receivable - Noncurrent | 7 | [4] | 7 | [4] | 0 | [4] |
Amounts owed to co-owners | ($5) | [3],[5] | ($5) | [3],[5] | ($18) | [3],[5] |
[1] | Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG. | |||||
[2] | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. | |||||
[3] | Recorded in Accounts receivable, other. | |||||
[4] | Recorded in Deferred debits and other assets, other | |||||
[5] | Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. |
Commitments_and_Contingencies_4
Commitments and Contingencies - Schedule of Purchases of Energy, Capacity and Transmission Rights (Details) (Exelon Generation Co L L C [Member], USD $) | Dec. 31, 2014 | |
In Millions, unless otherwise specified | ||
Capacity Offsets [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2015 | $132 | |
2016 | 133 | [1] |
2017 | 136 | |
2018 | 137 | |
2019 | 138 | |
Thereafter | 591 | |
Net Capacity Purchases [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2015 | 418 | [1] |
2016 | 283 | [1] |
2017 | 222 | [1] |
2018 | 112 | [1] |
2019 | 117 | [1] |
Thereafter | 279 | [1] |
Total | 1,431 | [1] |
Power Purchases [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2015 | 152 | [2] |
2016 | 228 | [2] |
2017 | 121 | [2] |
2018 | 29 | [2] |
2019 | 5 | [2] |
Thereafter | 1 | [2] |
Total | 536 | [2] |
Transmission Rights Purchases [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2015 | 20 | [3] |
2016 | 15 | [3] |
2017 | 15 | [3] |
2018 | 16 | [3] |
2019 | 16 | [3] |
Thereafter | 35 | [3] |
Total | 117 | [3] |
Total Unregulated Energy Commitments [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
2015 | 590 | |
2016 | 526 | |
2017 | 358 | |
2018 | 157 | |
2019 | 138 | |
Thereafter | 315 | |
Total | $2,084 | |
[1] | 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, 2014, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of December 31, 2014, capacity offsets were $132 million, $133 million, $136 million, $137 million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. | |
[2] | The table excludes renewable energy purchases that are contingent in nature. | |
[3] | Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts. |
Commitments_and_Contingencies_5
Commitments and Contingencies - Schedule of Energy Supply Procurement, Curtailment Services, REC and AEC Purchase Commitments (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | |
Commonwealth Edison Co [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Term of contract | 20 years | |
Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 620 | [1] |
2015 | 329 | [1] |
2016 | 151 | [1] |
2017 | 140 | [1] |
2018 | 0 | [1] |
2019 | 0 | [1] |
Thereafter | 0 | [1] |
Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 1,517 | [2] |
2015 | 75 | [2] |
2016 | 76 | [2] |
2017 | 77 | [2] |
2018 | 78 | [2] |
2019 | 84 | [2] |
Thereafter | 1,127 | [2] |
PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 609 | [2] |
2015 | 527 | [3] |
2016 | 82 | [3] |
2017 | 0 | [3] |
2018 | 0 | [3] |
2019 | 0 | [3] |
Thereafter | 0 | [3] |
PECO Energy Co [Member] | Alternative Energy Credits [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 13 | [4] |
2015 | 2 | [4] |
2016 | 2 | [4] |
2017 | 2 | [4] |
2018 | 2 | [4] |
2019 | 2 | [4] |
Thereafter | 3 | [4] |
Baltimore Gas and Electric Company [Member] | DSP Program Electric Procurement Contracts [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 1,315 | [5] |
2015 | 779 | [5] |
2016 | 448 | [5] |
2017 | 88 | [5] |
2018 | 0 | [5] |
2019 | 0 | [5] |
Thereafter | 0 | [5] |
Baltimore Gas and Electric Company [Member] | Curtailment Services [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 115 | [6] |
2015 | 40 | [6] |
2016 | 34 | [6] |
2017 | 29 | [6] |
2018 | 12 | [6] |
2019 | 0 | [6] |
Thereafter | 0 | [6] |
[1] | ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. | |
[2] | Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. | |
[3] | PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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. | |
[4] | 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. | |
[5] | BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information. | |
[6] | 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. |
Commitments_and_Contingencies_6
Commitments and Contingencies - Schedule of Fuel Purchase Obligations (Details) (Public Utilities, Inventory, Fuel [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Exelon Generation Co L L C [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Total | $8,981 |
2015 | 1,404 |
2016 | 1,119 |
2017 | 1,124 |
2018 | 1,001 |
2019 | 888 |
Thereafter | 3,445 |
PECO Energy Co [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Total | 428 |
2015 | 146 |
2016 | 103 |
2017 | 60 |
2018 | 34 |
2019 | 14 |
Thereafter | 71 |
Baltimore Gas and Electric Company [Member] | |
Unrecorded Unconditional Purchase Obligation [Line Items] | |
Total | 611 |
2015 | 111 |
2016 | 82 |
2017 | 67 |
2018 | 57 |
2019 | 54 |
Thereafter | $240 |
Commitments_and_Contingencies_7
Commitments and Contingencies - Schedule of Other Purchase Obligations (Details) (Other Purchase Obligations [Member], USD $) | Dec. 31, 2014 | |
In Millions, unless otherwise specified | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | $894 | |
2015 | 336 | |
2016 | 258 | |
2017 | 150 | |
2018 | 36 | |
2019 | 30 | |
Thereafter | 84 | |
Exelon Generation Co L L C [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 396 | [1],[2] |
2015 | 163 | [1],[2] |
2016 | 67 | [1],[2] |
2017 | 42 | [1],[2] |
2018 | 30 | [1],[2] |
2019 | 24 | [1],[2] |
Thereafter | 70 | [1],[2] |
Commonwealth Edison Co [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 148 | [3] |
2015 | 63 | [3] |
2016 | 77 | [3] |
2017 | 1 | [3] |
2018 | 1 | [3] |
2019 | 1 | [3] |
Thereafter | 5 | [3] |
PECO Energy Co [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 7 | [3] |
2015 | 3 | [3] |
2016 | 4 | [3] |
2017 | 0 | [3] |
2018 | 0 | [3] |
2019 | 0 | [3] |
Thereafter | 0 | [3] |
Baltimore Gas and Electric Company [Member] | ||
Unrecorded Unconditional Purchase Obligation [Line Items] | ||
Total | 343 | [3] |
2015 | 107 | [3] |
2016 | 110 | [3] |
2017 | 107 | [3] |
2018 | 5 | [3] |
2019 | 5 | [3] |
Thereafter | $9 | [3] |
[1] | Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information. | |
[2] | Purchase obligations include commitments related to assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information. | |
[3] | Purchase obligations include commitments related to smart meter installation. See Note 3 — Regulatory Matters for additional information. |
Commitments_and_Contingencies_8
Commitments and Contingencies - Schedule of Commercial Commitments (Details) (USD $) | Dec. 31, 2014 | |
Guarantor Obligations [Line Items] | ||
Total | $9,402,000,000 | |
2015 | 5,448,000,000 | |
2016 | 107,000,000 | |
2017 | 29,000,000 | |
2018 | 21,000,000 | |
2019 | 22,000,000 | |
2020 and beyond | 3,775,000,000 | |
Percentage ownership of common stock | 100.00% | |
Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 1,233,000,000 | [1] |
2015 | 1,151,000,000 | [1] |
2016 | 77,000,000 | [1] |
2017 | 5,000,000 | [1] |
2018 | 0 | [1] |
2019 | 0 | [1] |
2020 and beyond | 0 | [1] |
Surety Bond [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 596,000,000 | [2] |
2015 | 545,000,000 | [2] |
2016 | 10,000,000 | [2] |
2017 | 4,000,000 | [2] |
2018 | 1,000,000 | [2] |
2019 | 2,000,000 | [2] |
2020 and beyond | 34,000,000 | [2] |
Performance Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 1,239,000,000 | [3] |
2015 | 472,000,000 | [2] |
2016 | 20,000,000 | [2] |
2017 | 20,000,000 | [2] |
2018 | 20,000,000 | [2] |
2019 | 20,000,000 | [2] |
2020 and beyond | 687,000,000 | [2] |
Energy Contract Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 3,220,000,000 | [4] |
2015 | 3,220,000,000 | [4] |
2016 | 0 | [4] |
2017 | 0 | [4] |
2018 | 0 | [4] |
2019 | 0 | [4] |
2020 and beyond | 0 | [4] |
Estimated total assumed for commercial transaction obligations | 3,200,000,000 | |
Property Lease Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 40,000,000 | [5] |
2015 | 0 | [5] |
2016 | 0 | [5] |
2017 | 0 | [5] |
2018 | 0 | [5] |
2019 | 0 | [5] |
2020 and beyond | 40,000,000 | [5] |
Nuclear Insurance Premiums [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 3,014,000,000 | [6] |
2015 | 0 | [6] |
2016 | 0 | [6] |
2017 | 0 | [6] |
2018 | 0 | [6] |
2019 | 0 | [6] |
2020 and beyond | 3,014,000,000 | [6] |
Underwriters Discount [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 60,000,000 | [7] |
2015 | 60,000,000 | [7] |
2016 | 0 | [7] |
2017 | 0 | [7] |
2018 | 0 | [7] |
2019 | 0 | [7] |
2020 and beyond | 0 | [7] |
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | ||
Guarantor Obligations [Line Items] | ||
Estimated net exposure for commercial transaction obligations | 600,000,000 | |
Baltimore Gas and Electric Company [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 265,000,000 | |
2015 | 15,000,000 | |
2016 | 0 | |
2017 | 0 | |
2018 | 0 | |
2019 | 0 | |
2020 and beyond | 250,000,000 | |
Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 1,000,000 | [8] |
2015 | 1,000,000 | [8] |
2016 | 0 | [8] |
2017 | 0 | [8] |
2018 | 0 | [8] |
2019 | 0 | [8] |
2020 and beyond | 0 | [8] |
Baltimore Gas and Electric Company [Member] | Surety Bond [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 11,000,000 | [9] |
2015 | 11,000,000 | [9] |
2016 | 0 | [9] |
2017 | 0 | [9] |
2018 | 0 | [9] |
2019 | 0 | [9] |
2020 and beyond | 0 | [9] |
Baltimore Gas and Electric Company [Member] | Performance Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 253,000,000 | [10] |
2015 | 3,000,000 | [10] |
2016 | 0 | [10] |
2017 | 0 | [10] |
2018 | 0 | [10] |
2019 | 0 | [10] |
2020 and beyond | 250,000,000 | [10] |
Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 250,000,000 | |
PECO Energy Co [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 218,000,000 | |
2015 | 40,000,000 | |
2016 | 0 | |
2017 | 0 | |
2018 | 0 | |
2019 | 0 | |
2020 and beyond | 178,000,000 | |
PECO Energy Co [Member] | Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 22,000,000 | [11] |
2015 | 22,000,000 | [11] |
2016 | 0 | [11] |
2017 | 0 | [11] |
2018 | 0 | [11] |
2019 | 0 | [11] |
2020 and beyond | 0 | [11] |
PECO Energy Co [Member] | Surety Bond [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 18,000,000 | [2] |
2015 | 18,000,000 | [2] |
2016 | 0 | [2] |
2017 | 0 | [2] |
2018 | 0 | [2] |
2019 | 0 | [2] |
2020 and beyond | 0 | [2] |
PECO Energy Co [Member] | Performance Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 178,000,000 | [12] |
2015 | 0 | [12] |
2016 | 0 | [12] |
2017 | 0 | [12] |
2018 | 0 | [12] |
2019 | 0 | [12] |
2020 and beyond | 178,000,000 | [12] |
PECO Energy Co [Member] | Trust Preferred Securities [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 178,000,000 | |
Commonwealth Edison Co [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 222,000,000 | |
2015 | 20,000,000 | |
2016 | 0 | |
2017 | 0 | |
2018 | 0 | |
2019 | 0 | |
2020 and beyond | 202,000,000 | |
Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 17,000,000 | [13] |
2015 | 17,000,000 | [13] |
2016 | 0 | [13] |
2017 | 0 | [13] |
2018 | 0 | [13] |
2019 | 0 | [13] |
2020 and beyond | 0 | [13] |
Commonwealth Edison Co [Member] | Surety Bond [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 5,000,000 | [2] |
2015 | 3,000,000 | [2] |
2016 | 0 | [2] |
2017 | 0 | [2] |
2018 | 0 | [2] |
2019 | 0 | [2] |
2020 and beyond | 2,000,000 | [2] |
Commonwealth Edison Co [Member] | Performance Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 200,000,000 | [14] |
2015 | 0 | [14] |
2016 | 0 | [14] |
2017 | 0 | [14] |
2018 | 0 | [14] |
2019 | 0 | [14] |
2020 and beyond | 200,000,000 | [14] |
Commonwealth Edison Co [Member] | Trust Preferred Securities [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 200,000,000 | |
Exelon Generation Co L L C [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 6,384,000,000 | |
2015 | 3,137,000,000 | |
2016 | 99,000,000 | |
2017 | 25,000,000 | |
2018 | 20,000,000 | |
2019 | 20,000,000 | |
2020 and beyond | 3,083,000,000 | |
Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 1,187,000,000 | [15] |
2015 | 1,106,000,000 | [15] |
2016 | 76,000,000 | [15] |
2017 | 5,000,000 | [15] |
2018 | 0 | [15] |
2019 | 0 | [15] |
2020 and beyond | 0 | [15] |
Exelon Generation Co L L C [Member] | Surety Bond [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 481,000,000 | |
2015 | 468,000,000 | |
2016 | 3,000,000 | |
2017 | 0 | |
2018 | 0 | |
2019 | 0 | |
2020 and beyond | 10,000,000 | |
Exelon Generation Co L L C [Member] | Performance Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 458,000,000 | [16] |
2015 | 319,000,000 | [16] |
2016 | 20,000,000 | [16] |
2017 | 20,000,000 | [16] |
2018 | 20,000,000 | [16] |
2019 | 20,000,000 | [16] |
2020 and beyond | 59,000,000 | [16] |
Exelon Generation Co L L C [Member] | Energy Contract Guarantee [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 1,244,000,000 | [17] |
2015 | 1,244,000,000 | [17] |
2016 | 0 | [17] |
2017 | 0 | [17] |
2018 | 0 | [17] |
2019 | 0 | [17] |
2020 and beyond | 0 | [17] |
Estimated total assumed for commercial transaction obligations | 1,200,000,000 | |
Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member] | ||
Guarantor Obligations [Line Items] | ||
Total | 3,014,000,000 | [18] |
2015 | 0 | [18] |
2016 | 0 | [18] |
2017 | 0 | [18] |
2018 | 0 | [18] |
2019 | 0 | [18] |
2020 and beyond | 3,014,000,000 | [18] |
Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member] | ||
Guarantor Obligations [Line Items] | ||
Estimated net exposure for commercial transaction obligations | $400,000,000 | |
Commonwealth Edison Three [Member] | Commonwealth Edison Co [Member] | ||
Guarantor Obligations [Line Items] | ||
Percentage ownership of common stock | 100.00% | |
PECO Trust III and IV [Member] | PECO Energy Co [Member] | ||
Guarantor Obligations [Line Items] | ||
Percentage ownership of common stock | 100.00% | |
[1] | 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. | |
[2] | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. | |
[3] | Performance guarantees—Guarantees issued to ensure performance under specific contracts. Additionally includes $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. | |
[4] | Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.2 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 $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 market prices. | |
[5] | Lease guarantees—Guarantees issued to ensure payments on building leases. | |
[6] | 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. | |
[7] | Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering. | |
[8] | Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |
[9] | Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds. | |
[10] | Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE. | |
[11] | Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |
[12] | 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. | |
[13] | Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties. | |
[14] | Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd. | |
[15] | Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. | |
[16] | Performance guarantees—Guarantees issued to ensure performance under specific contracts. | |
[17] | Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 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. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 market prices. | |
[18] | 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, including CENG sites, 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. |
Commitments_and_Contingencies_9
Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) (Equity Method Investments [Member], Exelon Generation Co L L C [Member], USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
Equity Method Investments [Member] | Exelon Generation Co L L C [Member] | |
Guarantor Obligations [Line Items] | |
2015 | $98 |
2016 | 38 |
2017 | 20 |
2018 | 11 |
Total | $167 |
Recovered_Sheet4
Commitments and Contingencies - Schedule of Minimum Future Operating Lease Payments (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | |
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | $99 | |
2016 | 102 | |
2017 | 102 | |
2018 | 86 | |
2019 | 70 | |
Remaining years | 699 | |
Total minimum future lease payments | 1,158 | [1] |
Exelon Generation Co L L C [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | 51 | [2] |
2016 | 57 | [2] |
2017 | 63 | [2] |
2018 | 57 | [2] |
2019 | 43 | [2] |
Remaining years | 628 | [2] |
Total minimum future lease payments | 899 | [1],[2] |
Exelon Generation Co L L C [Member] | Baltimore Headquarters [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | 0 | |
2016 | 5 | |
2017 | 12 | |
2018 | 13 | |
2019 | 13 | |
Remaining years | 285 | |
Commonwealth Edison Co [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | 14 | [3] |
2016 | 13 | [3] |
2017 | 8 | [3] |
2018 | 4 | [3] |
2019 | 4 | [3] |
Remaining years | 2 | [3] |
Total minimum future lease payments | 45 | [3] |
Commonwealth Edison Co [Member] | Real Estate Leases and Railroad Licenses [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
Total minimum future lease payments | 2 | |
PECO Energy Co [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | 3 | [3] |
2016 | 3 | [3] |
2017 | 3 | [3] |
2018 | 3 | [3] |
2019 | 2 | [3] |
Remaining years | 0 | [3] |
Total minimum future lease payments | 14 | [3] |
PECO Energy Co [Member] | Real Estate Leases and Railroad Licenses [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
Total minimum future lease payments | 3 | |
Baltimore Gas and Electric Company [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
2015 | 13 | [3],[4] |
2016 | 11 | [3],[4] |
2017 | 10 | [3],[4] |
2018 | 9 | [3],[4] |
2019 | 7 | [3],[4] |
Remaining years | 27 | [3],[4] |
Total minimum future lease payments | 77 | [3],[4] |
Baltimore Gas and Electric Company [Member] | Baltimore Headquarters [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
Total minimum future lease payments | 328 | |
Term of lease | 20 years | |
Baltimore Gas and Electric Company [Member] | Real Estate Leases and Railroad Licenses [Member] | ||
Operating Leases Future Minimum Payments Due [Line Items] | ||
Total minimum future lease payments | $2 | |
[1] | Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment. | |
[2] | The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million . | |
[3] | 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 2015—2019, was $2 million, $3 million, and $2 million respectively. | |
[4] | Includes all future lease payments on a 99 year real estate lease that expires in 2106. |
Recovered_Sheet5
Commitments and Contingencies - Schedule of Future Rental Expense under Operating Leases (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Operating Leases Future Minimum Payments Due [Line Items] | ||||||
Lease and rental expense | $865 | $806 | $930 | |||
Exelon Generation Co L L C [Member] | ||||||
Operating Leases Future Minimum Payments Due [Line Items] | ||||||
Lease and rental expense | 806 | [1] | 744 | [1] | 872 | [1] |
Long Term Contract For Purchase Of Electric Power Capacity | 755 | 694 | 801 | |||
Commonwealth Edison Co [Member] | ||||||
Operating Leases Future Minimum Payments Due [Line Items] | ||||||
Lease and rental expense | 15 | 15 | 18 | |||
PECO Energy Co [Member] | ||||||
Operating Leases Future Minimum Payments Due [Line Items] | ||||||
Lease and rental expense | 14 | 21 | 27 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Operating Leases Future Minimum Payments Due [Line Items] | ||||||
Lease and rental expense | $12 | $11 | $12 | |||
[1] | 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 $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively. |
Recovered_Sheet6
Commitments and Contingencies - Schedule of Environmental Liabilities (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, unless otherwise specified | ||
Total Accrual For Environmental Loss Contingencies [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | $347 | $338 |
Accrual For MGP Investigation And Remediation [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 277 | 273 |
Exelon Generation Co L L C [Member] | Total Accrual For Environmental Loss Contingencies [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 63 | 56 |
Exelon Generation Co L L C [Member] | Accrual For MGP Investigation And Remediation [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 0 | 0 |
Commonwealth Edison Co [Member] | Total Accrual For Environmental Loss Contingencies [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 238 | 234 |
Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 235 | 229 |
PECO Energy Co [Member] | Total Accrual For Environmental Loss Contingencies [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 45 | 47 |
PECO Energy Co [Member] | Accrual For MGP Investigation And Remediation [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 42 | 44 |
Baltimore Gas and Electric Company [Member] | Total Accrual For Environmental Loss Contingencies [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | 1 | 1 |
Baltimore Gas and Electric Company [Member] | Accrual For MGP Investigation And Remediation [Member] | ||
Accrual For Environmental Loss Contingencies [Line Items] | ||
Accrued environmental liabilities | $0 | $0 |
Supplemental_Financial_Informa2
Supplemental Financial Information - Summary of Taxes other than Income (Details) (USD $) | 10 Months Ended | 12 Months Ended | ||||||
In Millions, unless otherwise specified | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Supplemental Financial Information Tables [Line Items] | ||||||||
Utility Taxes | $456 | [1] | $449 | [1] | $463 | [1] | ||
Property | 396 | 302 | 227 | |||||
Payroll | 200 | 159 | 131 | |||||
Other | 102 | 185 | 198 | |||||
Total taxes other than income | 1,154 | 1,095 | 1,019 | |||||
Exelon Generation Co L L C [Member] | ||||||||
Supplemental Financial Information Tables [Line Items] | ||||||||
Utility Taxes | 89 | [1] | 79 | [1] | 82 | [1] | ||
Property | 240 | 205 | 189 | |||||
Payroll | 118 | 89 | 78 | |||||
Other | 18 | 16 | 20 | |||||
Total taxes other than income | 465 | 389 | 369 | |||||
Commonwealth Edison Co [Member] | ||||||||
Supplemental Financial Information Tables [Line Items] | ||||||||
Utility Taxes | 238 | [1] | 241 | [1] | 239 | [1] | ||
Property | 25 | 24 | 22 | |||||
Payroll | 28 | 27 | 26 | |||||
Other | 2 | 7 | 8 | |||||
Total taxes other than income | 293 | 299 | 295 | |||||
PECO Energy Co [Member] | ||||||||
Supplemental Financial Information Tables [Line Items] | ||||||||
Utility Taxes | 128 | [1] | 129 | [1] | 141 | [1] | ||
Property | 15 | 14 | 13 | |||||
Payroll | 14 | 13 | 12 | |||||
Other | 2 | 2 | -4 | |||||
Total taxes other than income | 159 | 158 | 162 | |||||
Baltimore Gas and Electric Company [Member] | ||||||||
Supplemental Financial Information Tables [Line Items] | ||||||||
Utility Taxes | 59 | [1] | 86 | [1] | 82 | [1] | 75 | [1] |
Property | 114 | 112 | 111 | |||||
Payroll | 18 | 15 | 18 | |||||
Other | 3 | 4 | 4 | |||||
Total taxes other than income | $221 | $213 | $208 | |||||
[1] | 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. |
Supplemental_Financial_Informa3
Supplemental Financial Information - Summary of Other Income (Expense) (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Supplemental Financial Information Tables [Line Items] | ||||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | $216 | [1] | $256 | [1] | $189 | [1] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 159 | [1] | 77 | [1] | 102 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 180 | [1] | 406 | [1] | 386 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 134 | [1] | 146 | [1] | 105 | [1] |
Net unrealized income (losses) on pledged assets | 29 | [1] | 7 | [1] | 73 | [1] |
Regulatory offset to decommissioning trust fund-related activities | -358 | [1],[2] | -546 | [1],[2] | -530 | [1],[2] |
Total decommissioning-related activities | 360 | 346 | 325 | |||
Investment income | 1 | 8 | 20 | |||
Long-term lease income | 24 | 28 | 29 | |||
Interest income related to uncertain income tax positions | 40 | 24 | 15 | |||
AFUDC—Equity | 21 | 22 | 17 | |||
Credit facility termination fees | -85 | |||||
Other | 9 | 32 | 32 | |||
Other, net | 455 | 460 | 353 | |||
Exelon Generation Co L L C [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 216 | [1] | 256 | [1] | 189 | [1] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 159 | [1] | 77 | [1] | 102 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 180 | [1] | 406 | [1] | 386 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 134 | [1] | 146 | [1] | 105 | [1] |
Net unrealized income (losses) on pledged assets | 29 | [1] | 7 | [1] | 73 | [1] |
Regulatory offset to decommissioning trust fund-related activities | -358 | [1],[2] | -546 | [1],[2] | -530 | [1],[2] |
Total decommissioning-related activities | 360 | 346 | 325 | |||
Investment income | 1 | -1 | 3 | |||
Long-term lease income | 0 | 0 | 0 | |||
Interest income related to uncertain income tax positions | 54 | 4 | 2 | |||
AFUDC—Equity | 0 | 0 | 0 | |||
Credit facility termination fees | -85 | |||||
Other | -9 | 6 | 1 | |||
Other, net | 406 | 355 | 246 | |||
Commonwealth Edison Co [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on pledged assets | 0 | [1] | 0 | [1] | 0 | [1] |
Regulatory offset to decommissioning trust fund-related activities | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] |
Total decommissioning-related activities | 0 | 0 | 0 | |||
Investment income | 0 | 0 | 1 | |||
Long-term lease income | 0 | 0 | 0 | |||
Interest income related to uncertain income tax positions | 0 | 0 | 20 | |||
AFUDC—Equity | 3 | 11 | 6 | |||
Credit facility termination fees | 0 | |||||
Other | 14 | 15 | 12 | |||
Other, net | 17 | 26 | 39 | |||
Other Income | 17 | |||||
PECO Energy Co [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on pledged assets | 0 | [1] | 0 | [1] | 0 | [1] |
Regulatory offset to decommissioning trust fund-related activities | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] |
Total decommissioning-related activities | 0 | 0 | 0 | |||
Investment income | -1 | -1 | 2 | |||
Long-term lease income | 0 | 0 | 0 | |||
Interest income related to uncertain income tax positions | 0 | 0 | 0 | |||
AFUDC—Equity | 6 | 4 | 4 | |||
Credit facility termination fees | 0 | |||||
Other | 2 | 3 | 2 | |||
Other, net | 7 | 6 | 8 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Net realized income on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement | 0 | [1] | 0 | [1] | 0 | [1] |
Net unrealized income (losses) on pledged assets | 0 | [1] | 0 | [1] | 0 | [1] |
Regulatory offset to decommissioning trust fund-related activities | 0 | [1],[2] | 0 | [1],[2] | 0 | [1],[2] |
Total decommissioning-related activities | 0 | 0 | 0 | |||
Investment income | 7 | [3] | 9 | [3] | 11 | [3] |
Long-term lease income | 0 | 0 | 0 | |||
Interest income related to uncertain income tax positions | 0 | 0 | 0 | |||
AFUDC—Equity | 12 | 7 | 10 | |||
Credit facility termination fees | 0 | |||||
Other | -1 | 1 | 2 | |||
Other, net | $18 | $17 | $23 | |||
[1] | Includes investment income and realized gains and losses on sales of investments of the trust funds. | |||||
[2] | 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. | |||||
[3] | 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_Financial_Informa4
Supplemental Financial Information - Summary of Depreciation, Amortization, Accretion and Depletion (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Supplemental Financial Information Tables [Line Items] | ||||||
Property, plant and equipment | $2,080 | $1,893 | $1,712 | |||
Regulatory assets | 191 | 212 | 129 | |||
Amortization of intangible assets, net | 44 | 48 | 40 | |||
Amortization of Intangible Assets | 179 | [1] | 478 | [1] | 1,150 | [1] |
Nuclear fuel | 1,073 | [2] | 921 | [2] | 848 | [2] |
ARO accretion | 345 | [3] | 275 | [3] | 240 | [3] |
Total depreciation, amortization, accretion and depletion | 3,868 | 3,779 | 4,079 | |||
Exelon Generation Co L L C [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Property, plant and equipment | 922 | 813 | 733 | |||
Regulatory assets | 0 | 0 | 0 | |||
Amortization of intangible assets, net | 44 | 43 | 35 | |||
Amortization of Intangible Assets | 179 | [1] | 550 | [1] | 1,145 | [1] |
Nuclear fuel | 1,073 | [2] | 921 | [2] | 848 | [2] |
ARO accretion | 345 | [3] | 275 | [3] | 240 | [3] |
Total depreciation, amortization, accretion and depletion | 2,519 | 2,559 | 2,966 | |||
Commonwealth Edison Company [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Energy Contract Amortization | 0 | [4] | ||||
Commonwealth Edison Co [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Property, plant and equipment | 588 | 545 | 525 | |||
Regulatory assets | 99 | 119 | 80 | |||
Amortization of intangible assets, net | 0 | 5 | 5 | |||
Amortization of Intangible Assets | 7 | 7 | 7 | |||
Energy Contract Amortization | 0 | [4] | 0 | [4] | ||
Nuclear fuel | 0 | [2] | 0 | [2] | 0 | [2] |
ARO accretion | 0 | [3] | 0 | [3] | 0 | [3] |
Total depreciation, amortization, accretion and depletion | 687 | 669 | 610 | |||
PECO Energy Co [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Property, plant and equipment | 227 | 219 | 207 | |||
Regulatory assets | 9 | 9 | 10 | |||
Amortization of intangible assets, net | 0 | 0 | 0 | |||
Amortization of Intangible Assets | 0 | [4] | 0 | [4] | 0 | [4] |
Nuclear fuel | 0 | [2] | 0 | [2] | 0 | [2] |
ARO accretion | 0 | [3] | 0 | [3] | 0 | [3] |
Total depreciation, amortization, accretion and depletion | 236 | 228 | 217 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Property, plant and equipment | 288 | 264 | 245 | |||
Regulatory assets | 83 | 84 | 53 | |||
Amortization of intangible assets, net | 0 | 0 | 0 | |||
Amortization of Intangible Assets | 0 | [4] | 0 | [4] | 0 | [4] |
Nuclear fuel | 0 | [2] | 0 | [2] | 0 | [2] |
ARO accretion | 0 | [3] | 0 | [3] | 0 | [3] |
Total depreciation, amortization, accretion and depletion | 371 | 348 | 298 | |||
Unamortized Energy Contracts [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Amortization of Intangible Assets | 135 | [5],[6] | 430 | [5],[6] | 1,110 | [5],[6] |
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member] | ||||||
Supplemental Financial Information Tables [Line Items] | ||||||
Amortization of Intangible Assets | $135 | [5],[6] | $507 | [5],[6] | $1,110 | [4] |
[1] | At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income | |||||
[2] | Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | |||||
[3] | Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | |||||
[4] | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | |||||
[5] | Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively. | |||||
[6] | 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. |
Supplemental_Financial_Informa5
Supplemental Financial Information - Supplemental Cash Flow Information (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Supplemental Cash Flow Information [Line Items] | ||||||
Interest (net of amount capitalized) | $940 | $866 | $761 | |||
Income taxes (net of refunds) | 314 | 112 | -171 | |||
Pension and non-pension postretirement benefit costs | 560 | 825 | 820 | |||
Income (Loss) from Equity Method Investments | 20 | -10 | 91 | |||
Provision for uncollectible accounts | 156 | 101 | 164 | |||
Provision for excess and obsolete inventory | 5 | 9 | 6 | |||
Stock-based compensation costs | 91 | 120 | 94 | |||
Other decommissioning related-activity | -132 | [1] | -169 | [1] | -145 | [1] |
Energy-related options | 122 | [2] | 104 | [2] | 160 | [2] |
Amortization of regulatory asset related to debt costs | 11 | 12 | 18 | |||
Amortization of rate stabilization deferral | 65 | 66 | 57 | |||
Amortization of debt fair value adjustment | -23 | -34 | -34 | |||
Merger-related commitments | 44 | 141 | [3] | |||
Discrete impacts from EIMA | 53 | [4] | -271 | [4] | -96 | [5] |
Amortization of debt costs | 53 | 18 | 19 | |||
Lower of cost or market inventory adjustment | 29 | |||||
Other | -2 | -53 | -30 | |||
Total other non-cash operating activities | 1,054 | 718 | 1,364 | |||
Under/over-recovered energy and transmission costs | 47 | 12 | 71 | |||
Other regulatory assets and liabilities | -167 | -64 | -404 | |||
Increase (Decrease) in Deposits | -241 | [6] | ||||
Other current assets | 7 | -165 | 213 | |||
Other noncurrent assets and liabilities | -204 | 322 | -248 | |||
Total changes in other assets and liabilities | -558 | 102 | -368 | |||
Change in ARC | 72 | -128 | 781 | |||
Change in capital expenditures not paid | 220 | -38 | 160 | |||
Consolidated VIE dividend to noncontrolling | 421 | 63 | ||||
Fair value of net assets recorded upon CENG consolidation (f) | -3,400 | [7] | ||||
Issuance of equity units | 131 | [8] | ||||
Other Cost and Expense, Operating | 8,568 | 7,270 | 7,961 | |||
Antelope Valle [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Change in capital expenditures not paid | 170 | 55 | 127 | |||
Indemnification Agreement [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Energy-related options | 70 | [9] | ||||
Indemnification of like-kind exchange position | 0 | [10] | 0 | [11] | ||
Exelon Generation Co L L C [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Interest (net of amount capitalized) | 322 | 291 | 286 | |||
Income taxes (net of refunds) | 227 | -18 | 175 | |||
Pension and non-pension postretirement benefit costs | 249 | 345 | 341 | |||
Income (Loss) from Equity Method Investments | 20 | -10 | 91 | |||
Provision for uncollectible accounts | 14 | 10 | 22 | |||
Provision for excess and obsolete inventory | 5 | 9 | 6 | |||
Stock-based compensation costs | 0 | 0 | 0 | |||
Other decommissioning related-activity | -132 | [1] | -169 | [1] | -145 | [1] |
Energy-related options | 122 | [2] | 104 | [2] | 160 | [2] |
Amortization of regulatory asset related to debt costs | 0 | 0 | 0 | |||
Amortization of rate stabilization deferral | 0 | 0 | 0 | |||
Amortization of debt fair value adjustment | -23 | -34 | -34 | |||
Merger-related commitments | 44 | 32 | [3] | |||
Discrete impacts from EIMA | 0 | [4] | 0 | [4] | 0 | [5] |
Amortization of debt costs | 12 | 10 | 11 | |||
Lower of cost or market inventory adjustment | 29 | |||||
Other | 6 | 5 | 0 | |||
Total other non-cash operating activities | 346 | 270 | 518 | |||
Under/over-recovered energy and transmission costs | 0 | 0 | 0 | |||
Other regulatory assets and liabilities | 0 | 0 | 0 | |||
Increase (Decrease) in Deposits | -241 | [6] | ||||
Other current assets | 81 | -151 | -30 | |||
Other noncurrent assets and liabilities | -89 | 15 | -98 | |||
Total changes in other assets and liabilities | -249 | -136 | -128 | |||
Change in ARC | 72 | -128 | 781 | |||
Change in capital expenditures not paid | -61 | [12] | -107 | [13] | 103 | [14] |
Consolidated VIE dividend to noncontrolling | -1,548 | 63 | ||||
Fair value of net assets recorded upon CENG consolidation (f) | -3,400 | [7] | ||||
Issuance of equity units | 0 | [8] | ||||
Other Cost and Expense, Operating | 4,943 | 3,960 | 4,398 | |||
Exelon Generation Co L L C [Member] | Indemnification Agreement [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Energy-related options | 70 | [9] | ||||
Indemnification of like-kind exchange position | 0 | [10] | 0 | [11] | ||
Commonwealth Edison Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Interest (net of amount capitalized) | 292 | 283 | 288 | |||
Income taxes (net of refunds) | -6 | 33 | -42 | |||
Pension and non-pension postretirement benefit costs | 162 | 308 | 282 | |||
Income (Loss) from Equity Method Investments | 0 | 0 | ||||
Provision for uncollectible accounts | 26 | -15 | 42 | |||
Provision for excess and obsolete inventory | 0 | 0 | 1 | |||
Stock-based compensation costs | 0 | 0 | 0 | |||
Other decommissioning related-activity | 0 | [1] | 0 | [1] | 0 | [1] |
Energy-related options | 0 | [2] | 0 | [2] | 0 | [2] |
Amortization of regulatory asset related to debt costs | 8 | 9 | 13 | |||
Amortization of rate stabilization deferral | 0 | 0 | 0 | |||
Amortization of debt fair value adjustment | 0 | 0 | 0 | |||
Merger-related commitments | 0 | 0 | [3] | |||
Discrete impacts from EIMA | 53 | [4] | -271 | [4] | -96 | [5] |
Amortization of debt costs | 4 | 1 | 5 | |||
Lower of cost or market inventory adjustment | 0 | |||||
Other | 2 | -4 | 5 | |||
Total other non-cash operating activities | 255 | 28 | 252 | |||
Under/over-recovered energy and transmission costs | 36 | -35 | 28 | |||
Other regulatory assets and liabilities | -13 | -43 | -68 | |||
Increase (Decrease) in Deposits | 0 | [6] | ||||
Other current assets | -10 | 51 | 33 | |||
Other noncurrent assets and liabilities | 32 | 268 | [15] | -95 | ||
Total changes in other assets and liabilities | 45 | 241 | -102 | |||
Change in ARC | 0 | 0 | 2 | |||
Change in capital expenditures not paid | 78 | -8 | 15 | |||
Fair value of net assets recorded upon CENG consolidation (f) | 0 | [7] | ||||
Issuance of equity units | 0 | [8] | ||||
Indemnification of like-kind exchange position | 273 | 0 | 0 | |||
Other Cost and Expense, Operating | 1,263 | 1,211 | 1,182 | |||
Commonwealth Edison Co [Member] | Indemnification Agreement [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Energy-related options | 0 | [9] | ||||
Indemnification of like-kind exchange position | 5 | [10] | 176 | [11] | ||
PECO Energy Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Interest (net of amount capitalized) | 94 | 95 | 113 | |||
Income taxes (net of refunds) | 85 | 70 | -64 | |||
Pension and non-pension postretirement benefit costs | 36 | 43 | 50 | |||
Income (Loss) from Equity Method Investments | 0 | 0 | 0 | |||
Provision for uncollectible accounts | 52 | 61 | 60 | |||
Provision for excess and obsolete inventory | 0 | 0 | 0 | |||
Stock-based compensation costs | 0 | 0 | 0 | |||
Other decommissioning related-activity | 0 | [1] | 0 | [1] | 0 | [1] |
Energy-related options | 0 | [2] | 0 | [2] | 0 | [2] |
Amortization of regulatory asset related to debt costs | 3 | 3 | 3 | |||
Amortization of rate stabilization deferral | 0 | 0 | 0 | |||
Amortization of debt fair value adjustment | 0 | 0 | 0 | |||
Merger-related commitments | 0 | 0 | [3] | |||
Discrete impacts from EIMA | 0 | [4] | 0 | [4] | 0 | [5] |
Amortization of debt costs | 2 | 2 | 3 | |||
Lower of cost or market inventory adjustment | 0 | |||||
Other | -1 | -1 | 9 | |||
Total other non-cash operating activities | 92 | 108 | 125 | |||
Under/over-recovered energy and transmission costs | 0 | 9 | 20 | |||
Other regulatory assets and liabilities | -16 | -16 | 18 | |||
Increase (Decrease) in Deposits | 0 | [6] | ||||
Other current assets | -2 | 13 | -12 | |||
Other noncurrent assets and liabilities | 1 | -12 | -10 | |||
Total changes in other assets and liabilities | -17 | -6 | 16 | |||
Change in ARC | 0 | 0 | 0 | |||
Change in capital expenditures not paid | 0 | 13 | 26 | |||
Fair value of net assets recorded upon CENG consolidation (f) | 0 | [7] | ||||
Issuance of equity units | 0 | [8] | ||||
Indemnification of like-kind exchange position | 24 | 27 | 9 | |||
Other Cost and Expense, Operating | 767 | 647 | 698 | |||
PECO Energy Co [Member] | Indemnification Agreement [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Energy-related options | 0 | [9] | ||||
Indemnification of like-kind exchange position | 0 | [10] | 0 | [11] | ||
Baltimore Gas and Electric Company [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Interest (net of amount capitalized) | 111 | 130 | 136 | |||
Income taxes (net of refunds) | -21 | 42 | -112 | |||
Pension and non-pension postretirement benefit costs | 64 | 56 | 57 | |||
Income (Loss) from Equity Method Investments | 0 | 0 | 0 | |||
Provision for uncollectible accounts | 64 | 44 | 44 | |||
Provision for excess and obsolete inventory | 0 | 0 | 0 | |||
Stock-based compensation costs | 0 | 0 | 0 | |||
Other decommissioning related-activity | 0 | [1] | 0 | [1] | 0 | [1] |
Energy-related options | 0 | [2] | 0 | [2] | 0 | [2] |
Amortization of regulatory asset related to debt costs | 0 | 0 | 2 | |||
Amortization of rate stabilization deferral | 65 | 66 | 67 | |||
Amortization of debt fair value adjustment | 0 | 0 | 0 | |||
Merger-related commitments | 0 | 27 | [3] | |||
Discrete impacts from EIMA | 0 | [4] | 0 | [4] | 0 | [5] |
Amortization of debt costs | 2 | 2 | 2 | |||
Lower of cost or market inventory adjustment | 0 | |||||
Other | -15 | -15 | -6 | |||
Total other non-cash operating activities | 180 | 153 | 193 | |||
Under/over-recovered energy and transmission costs | 11 | 38 | 26 | |||
Other regulatory assets and liabilities | -121 | -71 | -112 | |||
Increase (Decrease) in Deposits | 0 | [6] | ||||
Other current assets | -44 | -8 | -7 | |||
Other noncurrent assets and liabilities | -9 | -23 | 8 | |||
Total changes in other assets and liabilities | -163 | -64 | -85 | |||
Change in ARC | 0 | 4 | 0 | |||
Change in capital expenditures not paid | 25 | -48 | -4 | |||
Fair value of net assets recorded upon CENG consolidation (f) | 0 | [7] | ||||
Issuance of equity units | 0 | [8] | ||||
Indemnification of like-kind exchange position | 0 | 0 | 66 | |||
Other Cost and Expense, Operating | 614 | 551 | 622 | |||
Baltimore Gas and Electric Company [Member] | Indemnification Agreement [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Energy-related options | 0 | [9] | ||||
Indemnification of like-kind exchange position | 0 | [10] | 0 | [11] | ||
Exelon Consolidations [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Income (Loss) from Equity Method Investments | 22 | |||||
Total changes in other assets and liabilities | 105 | |||||
Severance [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Other Cost and Expense, Operating | 99 | |||||
Severance [Member] | Exelon Generation Co L L C [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Other Cost and Expense, Operating | 34 | |||||
Severance [Member] | Commonwealth Edison Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Other Cost and Expense, Operating | 0 | |||||
Severance [Member] | PECO Energy Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Other Cost and Expense, Operating | 0 | |||||
Severance [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Other Cost and Expense, Operating | 0 | |||||
Constellation Energy Group Acquisition [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Consolidated VIE dividend to noncontrolling | 63 | 7,365 | ||||
Constellation Energy Group Acquisition [Member] | Exelon Generation Co L L C [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Consolidated VIE dividend to noncontrolling | 63 | 5,264 | ||||
Constellation Energy Group Acquisition [Member] | Commonwealth Edison Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Consolidated VIE dividend to noncontrolling | 0 | 0 | ||||
Constellation Energy Group Acquisition [Member] | PECO Energy Co [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Consolidated VIE dividend to noncontrolling | 0 | 0 | ||||
Constellation Energy Group Acquisition [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Supplemental Cash Flow Information [Line Items] | ||||||
Consolidated VIE dividend to noncontrolling | $0 | $0 | ||||
[1] | 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. | |||||
[2] | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. | |||||
[3] | Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments. | |||||
[4] | 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. | |||||
[5] | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters. | |||||
[6] | Relates primarily to cash deposits made to ISO's/RTO's. | |||||
[7] | See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information. | |||||
[8] | Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information. | |||||
[9] | Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018. | |||||
[10] | See Note 14 — Income Taxes for discussion of the like-kind exchange tax position. | |||||
[11] | See Note 14 — Income Taxes for discussion of the like-kind exchanged tax position. | |||||
[12] | Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley. | |||||
[13] | Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley. | |||||
[14] | Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley. | |||||
[15] | 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. |
Supplemental_Financial_Informa6
Supplemental Financial Information - Narrative (Details) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Supplemental Financial Information Tables [Line Items] | ||
Amount included in capital expenditures | $74 | |
Smart Grid Grant Reimbursements | 95 | |
PECO Energy Co [Member] | ||
Supplemental Financial Information Tables [Line Items] | ||
Amount included in capital expenditures | 2 | 27 |
Smart Grid Grant Reimbursements | 5 | 37 |
Baltimore Gas and Electric Company [Member] | ||
Supplemental Financial Information Tables [Line Items] | ||
Amount included in capital expenditures | 47 | |
Smart Grid Grant Reimbursements | $58 |
Supplemental_Financial_Informa7
Supplemental Financial Information - Supplemental Balance Sheet Information (Details) (USD $) | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | ||
In Millions, unless otherwise specified | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | $0 | $1,925 | |||
Total equity method investments | 50 | 2,295 | |||
Net investment in leases | 361 | 698 | |||
Total investments | 544 | 3,112 | |||
Compensation-related accruals | 832 | 683 | |||
Taxes accrued | 305 | 285 | 315 | ||
Interest accrued | 240 | 234 | |||
Severance accrued | 49 | 66 | |||
Other accrued expenses | 113 | 335 | |||
Total accrued expenses | 1,539 | 1,633 | |||
Antelope Valle [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Other accrued expenses | 19 | 228 | |||
Financing Trusts [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 22 | [1] | 22 | [1] | |
Bloom Energy [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 13 | ||||
Net Power [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 9 | ||||
Other Equity Method Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 1 | 2 | |||
Sunnyside [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 5 | ||||
Keystone Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 32 | ||||
Conemaugh Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 21 | ||||
CENG [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 1,925 | ||||
Safe Harbor [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 285 | ||||
Malacha [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 8 | ||||
Trust for Benefit of Employees [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 85 | [2] | 90 | [2] | |
Other Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 42 | [3] | 22 | [3] | |
Exelon Generation Co L L C [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | 1,925 | |||
Total equity method investments | 28 | 2,273 | |||
Net investment in leases | 7 | 7 | |||
Total investments | 104 | 2,325 | |||
Compensation-related accruals | 447 | 337 | |||
Taxes accrued | 248 | 212 | |||
Interest accrued | 66 | 72 | |||
Severance accrued | 33 | 31 | |||
Other accrued expenses | 92 | 324 | |||
Total accrued expenses | 886 | 976 | |||
Exelon Generation Co L L C [Member] | Financing Trusts [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | [1] | 0 | [1] | |
Exelon Generation Co L L C [Member] | Bloom Energy [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 13 | ||||
Exelon Generation Co L L C [Member] | Net Power [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 9 | ||||
Exelon Generation Co L L C [Member] | Other Equity Method Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 1 | 2 | |||
Exelon Generation Co L L C [Member] | Sunnyside [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 5 | ||||
Exelon Generation Co L L C [Member] | Keystone Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 32 | ||||
Exelon Generation Co L L C [Member] | Conemaugh Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 21 | ||||
Exelon Generation Co L L C [Member] | CENG [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 1,925 | ||||
Exelon Generation Co L L C [Member] | Safe Harbor [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 285 | ||||
Exelon Generation Co L L C [Member] | Malacha [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 8 | ||||
Exelon Generation Co L L C [Member] | Trust for Benefit of Employees [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 27 | [2] | 23 | [2] | |
Exelon Generation Co L L C [Member] | Other Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 42 | [3] | 22 | [3] | |
Commonwealth Edison Co [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Total equity method investments | 6 | 6 | |||
Net investment in leases | 0 | 0 | |||
Total investments | 6 | 11 | |||
Compensation-related accruals | 153 | 135 | |||
Taxes accrued | 59 | 62 | |||
Interest accrued | 102 | 95 | |||
Severance accrued | 2 | 3 | |||
Other accrued expenses | 15 | 12 | |||
Total accrued expenses | 331 | 307 | |||
Commonwealth Edison Co [Member] | Financing Trusts [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 6 | [1] | 6 | [1] | |
Commonwealth Edison Co [Member] | Bloom Energy [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Net Power [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Other Equity Method Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | 0 | |||
Commonwealth Edison Co [Member] | Keystone Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Conemaugh Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | CENG [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Safe Harbor [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Malacha [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Commonwealth Edison Co [Member] | Trust for Benefit of Employees [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 0 | [2] | 5 | [2] | |
Commonwealth Edison Co [Member] | Other Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 0 | [3] | 0 | [3] | |
PECO Energy Co [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Total equity method investments | 8 | 8 | |||
Net investment in leases | 0 | 0 | |||
Total investments | 31 | 31 | |||
Compensation-related accruals | 50 | 47 | |||
Taxes accrued | 3 | 24 | |||
Interest accrued | 33 | 32 | |||
Severance accrued | 1 | 1 | |||
Other accrued expenses | 4 | 2 | |||
Total accrued expenses | 91 | 106 | |||
PECO Energy Co [Member] | Financing Trusts [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 8 | [1] | 8 | [1] | |
PECO Energy Co [Member] | Bloom Energy [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Net Power [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Other Equity Method Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | 0 | |||
PECO Energy Co [Member] | Sunnyside [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Keystone Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Conemaugh Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | CENG [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Safe Harbor [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Malacha [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
PECO Energy Co [Member] | Trust for Benefit of Employees [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 23 | [2] | 23 | [2] | |
PECO Energy Co [Member] | Other Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 0 | [3] | 0 | [3] | |
Baltimore Gas and Electric Company [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Total equity method investments | 8 | 8 | |||
Net investment in leases | 0 | 0 | |||
Total investments | 12 | 13 | |||
Compensation-related accruals | 58 | 55 | |||
Taxes accrued | 42 | 16 | |||
Interest accrued | 29 | 29 | |||
Severance accrued | 2 | 4 | |||
Other accrued expenses | 0 | 7 | |||
Total accrued expenses | 131 | 111 | |||
Baltimore Gas and Electric Company [Member] | Financing Trusts [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 8 | [1] | 8 | [1] | |
Baltimore Gas and Electric Company [Member] | Bloom Energy [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Net Power [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Other Equity Method Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | 0 | |||
Baltimore Gas and Electric Company [Member] | Sunnyside [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Keystone Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Conemaugh Fuels [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | CENG [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Safe Harbor [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Malacha [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Equity Method Investments | 0 | ||||
Baltimore Gas and Electric Company [Member] | Trust for Benefit of Employees [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 4 | [2] | 5 | [2] | |
Baltimore Gas and Electric Company [Member] | Other Investments [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Employee benefit trusts and investments | 0 | [3] | 0 | [3] | |
Exelon Consolidations [Member] | |||||
Supplemental Balance Sheet Information [Line Items] | |||||
Net investment in leases | $367 | $705 | |||
[1] | Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information. | ||||
[2] | The Registrants’ investments in these marketable securities are recorded at fair market value. | ||||
[3] | Includes cost method and available-for-sale investments. |
Segment_Information_Narrative_
Segment Information - Narrative (Details) | 12 Months Ended |
Dec. 31, 2014 | |
Reportable_segment | |
Segment Reporting Information [Line Items] | |
Number of reportable segments | 9 |
Exelon Generation Co L L C [Member] | |
Segment Reporting Information [Line Items] | |
Number of reportable segments | 6 |
Segment_Information_Analysis_a
Segment Information - Analysis and Reconciliation to Consolidated Financial Statements (Details) (USD $) | 3 Months Ended | 10 Months Ended | 12 Months Ended | ||||||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | $7,255 | $6,912 | $6,024 | $7,237 | $6,163 | $6,502 | $6,141 | $6,082 | $27,429 | [1] | $24,888 | [1] | $23,489 | [1] | |||||
Operating revenues from affiliates | 23 | 70 | 48 | ||||||||||||||||
Depreciation and amortization | 2,314 | 2,153 | 1,881 | ||||||||||||||||
Operating Expenses | 25,039 | [1] | 21,242 | [1] | 21,018 | [1] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | -20 | 10 | -91 | ||||||||||||||||
Interest expense, net | 1,065 | 1,356 | 928 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 2,486 | 2,773 | 1,798 | ||||||||||||||||
Income taxes | 666 | 1,044 | 627 | ||||||||||||||||
Net income | 18 | [2] | 993 | 522 | 90 | 495 | 738 | 490 | -4 | [3] | 1,820 | 1,729 | 1,171 | ||||||
Capital expenditures | 6,077 | 5,395 | 5,789 | ||||||||||||||||
Assets | 86,814 | [4] | 79,924 | [4] | 86,814 | [4] | 79,924 | [4] | |||||||||||
Utility taxes | 456 | [5] | 449 | [5] | 463 | [5] | |||||||||||||
PECO Energy Co Affiliate [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 1 | [6] | 10 | [6] | 6 | [6] | |||||||||||||
Generation Midwest [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 4,475 | 4,270 | 4,848 | ||||||||||||||||
Operating Segments [Member] | Exelon Generation Co L L C [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 17,393 | [1],[7] | 15,630 | [1],[7] | 14,437 | [1],[7] | |||||||||||||
Depreciation and amortization | 967 | [7] | 856 | [7] | 768 | [7] | |||||||||||||
Operating Expenses | 16,923 | [1],[7] | 13,976 | [1],[7] | 13,226 | [1],[7] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | -20 | [7] | 10 | [7] | -91 | [7] | |||||||||||||
Interest expense, net | 356 | [7] | 357 | [7] | 301 | [7] | |||||||||||||
Income (loss) from continuing operations before income taxes | 1,226 | [7] | 1,675 | [7] | 1,058 | [7] | |||||||||||||
Income taxes | 207 | [7] | 615 | [7] | 500 | [7] | |||||||||||||
Net income | 1,019 | [7] | 1,060 | [7] | 558 | [7] | |||||||||||||
Capital expenditures | 3,012 | [7] | 2,752 | [7] | 3,554 | [7] | |||||||||||||
Assets | 45,348 | [7] | 41,232 | [7] | 45,348 | [7] | 41,232 | [7] | |||||||||||
Operating Segments [Member] | Commonwealth Edison Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 4,564 | [1] | 4,464 | [1] | 5,443 | [1] | |||||||||||||
Depreciation and amortization | 687 | 669 | 610 | ||||||||||||||||
Operating Expenses | 3,586 | [1] | 3,510 | [1] | 4,557 | [1] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 0 | 0 | 0 | ||||||||||||||||
Interest expense, net | 321 | 579 | 307 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 676 | 401 | 618 | ||||||||||||||||
Income taxes | 268 | 152 | 239 | ||||||||||||||||
Net income | 408 | 249 | 379 | ||||||||||||||||
Capital expenditures | 1,689 | 1,433 | 1,246 | ||||||||||||||||
Assets | 25,392 | 24,118 | 25,392 | 24,118 | |||||||||||||||
Operating Segments [Member] | PECO Energy Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 3,094 | [1] | 3,100 | [1] | 3,186 | [1] | |||||||||||||
Depreciation and amortization | 236 | 228 | 217 | ||||||||||||||||
Operating Expenses | 2,522 | [1] | 2,434 | [1] | 2,563 | [1] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 0 | 0 | 0 | ||||||||||||||||
Interest expense, net | 113 | 115 | 123 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 466 | 557 | 508 | ||||||||||||||||
Income taxes | 114 | 162 | 127 | ||||||||||||||||
Net income | 352 | 395 | 381 | ||||||||||||||||
Capital expenditures | 661 | 537 | 422 | ||||||||||||||||
Assets | 9,943 | 9,617 | 9,943 | 9,617 | |||||||||||||||
Operating Segments [Member] | Baltimore Gas and Electric Company [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 3,165 | [1],[8] | 3,065 | [1],[8] | 2,091 | [1],[8] | |||||||||||||
Depreciation and amortization | 371 | [8] | 348 | [8] | 238 | [8] | |||||||||||||
Operating Expenses | 2,726 | [1],[8] | 2,616 | [1],[8] | 2,053 | [1],[8] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 0 | [8] | 0 | [8] | 0 | [8] | |||||||||||||
Interest expense, net | 106 | [8] | 122 | [8] | 111 | [8] | |||||||||||||
Income (loss) from continuing operations before income taxes | 351 | [8] | 344 | [8] | -54 | [8] | |||||||||||||
Income taxes | 140 | [8] | 134 | [8] | -23 | [8] | |||||||||||||
Net income | 211 | [8] | 210 | [8] | -31 | [8] | |||||||||||||
Capital expenditures | 620 | [8] | 587 | [8] | 500 | [8] | |||||||||||||
Assets | 8,078 | [8] | 7,861 | [8] | 8,078 | [8] | 7,861 | [8] | |||||||||||
Operating Segments [Member] | Generation Midwest [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 4,467 | [9] | 4,280 | [9] | 4,824 | [9] | |||||||||||||
Income (loss) from continuing operations before income taxes | 7 | ||||||||||||||||||
Other Segments [Member] | Corporate and Other [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 1,285 | [1],[10] | 1,241 | [1],[10] | 1,396 | [1],[10] | |||||||||||||
Depreciation and amortization | 53 | [10] | 52 | [10] | 48 | [10] | |||||||||||||
Operating Expenses | 1,353 | [1],[10] | 1,324 | [1],[10] | 1,662 | [1],[10] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 0 | [10] | 0 | [10] | 0 | [10] | |||||||||||||
Interest expense, net | 169 | [10] | 183 | [10] | 86 | [10] | |||||||||||||
Income (loss) from continuing operations before income taxes | -227 | [10] | -191 | [10] | -325 | [10] | |||||||||||||
Income taxes | -63 | [10] | -20 | [10] | -215 | [10] | |||||||||||||
Net income | -164 | [10] | -171 | [10] | -110 | [10] | |||||||||||||
Capital expenditures | 95 | [10] | 86 | [10] | 67 | [10] | |||||||||||||
Assets | 9,794 | [10] | 8,317 | [10] | 9,794 | [10] | 8,317 | [10] | |||||||||||
Intersegment Eliminations [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | -2,072 | [1] | -2,612 | [1] | -3,064 | [1] | |||||||||||||
Operating revenues from affiliates | 6 | [11] | 14 | [11] | 6 | [11] | |||||||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||||||||||
Operating Expenses | -2,071 | [1] | -2,618 | [1] | -3,043 | [1] | |||||||||||||
Equity in earnings (losses) of unconsolidated affiliates | 0 | 0 | 0 | ||||||||||||||||
Interest expense, net | 0 | 0 | 0 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | -6 | -13 | -7 | ||||||||||||||||
Income taxes | 0 | 1 | -1 | ||||||||||||||||
Net income | -6 | -14 | -6 | ||||||||||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||||||||||
Assets | -11,741 | -11,221 | -11,741 | -11,221 | |||||||||||||||
Intersegment Eliminations [Member] | Exelon Generation Co L L C [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 762 | [11],[7] | 1,367 | [11],[7] | 1,660 | [11],[7] | |||||||||||||
Intersegment Eliminations [Member] | Commonwealth Edison Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 4 | [11] | 3 | [11] | 2 | [11] | |||||||||||||
Intersegment Eliminations [Member] | PECO Energy Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 2 | [11] | 1 | [11] | 3 | [11] | |||||||||||||
Intersegment Eliminations [Member] | Baltimore Gas and Electric Company [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 25 | [11],[8] | 13 | [11],[8] | 9 | [11],[8] | |||||||||||||
Intersegment Eliminations [Member] | Corporate and Other [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 1,280 | [10],[11] | 1,237 | [10],[11] | 1,381 | [10],[11] | |||||||||||||
Intersegment Eliminations [Member] | Generation Midwest [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | 8 | -10 | 24 | ||||||||||||||||
Intersegment Eliminations [Member] | Segment Elimination [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Operating revenues from affiliates | -2,067 | [11] | -2,607 | [11] | -3,049 | [11] | |||||||||||||
Exelon Generation Co L L C [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 4,802 | 4,412 | 3,789 | 4,390 | 3,772 | 4,255 | 4,070 | 3,533 | 17,393 | 15,630 | 14,437 | ||||||||
Operating revenues from affiliates | 779 | 1,423 | 1,702 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 1,226 | 1,675 | 1,058 | ||||||||||||||||
Income taxes | 207 | 615 | 500 | ||||||||||||||||
Net income | -91 | 771 | 340 | -185 | 269 | 490 | 330 | -18 | 1,019 | 1,060 | 558 | ||||||||
Assets | 45,348 | [12] | 41,232 | [12] | 45,348 | [12] | 41,232 | [12] | |||||||||||
Utility taxes | 89 | [5] | 79 | [5] | 82 | [5] | |||||||||||||
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 198 | [13] | |||||||||||||||||
Operating revenues from affiliates | 405 | [13] | 543 | [13] | |||||||||||||||
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 387 | [14] | |||||||||||||||||
Operating revenues from affiliates | 455 | [14] | 322 | [14] | |||||||||||||||
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 176 | [15] | |||||||||||||||||
Operating revenues from affiliates | 506 | [15] | 795 | [15] | |||||||||||||||
Exelon Generation Co L L C [Member] | Generation Midwest [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 7 | ||||||||||||||||||
Commonwealth Edison Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 1,079 | 1,222 | 1,128 | 1,134 | 1,068 | 1,156 | 1,080 | 1,160 | 4,564 | 4,464 | 5,443 | ||||||||
Operating revenues from affiliates | 4 | 3 | 2 | ||||||||||||||||
Income taxes | 268 | 152 | 239 | ||||||||||||||||
Net income | 73 | 126 | 111 | 98 | 109 | 126 | 96 | -81 | 408 | 249 | 379 | ||||||||
Assets | 25,392 | 24,118 | 25,392 | 24,118 | |||||||||||||||
Utility taxes | 238 | [5] | 241 | [5] | 239 | [5] | |||||||||||||
PECO Energy Co [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 750 | 693 | 656 | 993 | 805 | 728 | 672 | 895 | 3,094 | 3,100 | 3,186 | ||||||||
Operating revenues from affiliates | 2 | 1 | 3 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 466 | 557 | 508 | ||||||||||||||||
Income taxes | 114 | 162 | 127 | ||||||||||||||||
Net income | 98 | 81 | 84 | 89 | 102 | 92 | 72 | 121 | 352 | 395 | 381 | ||||||||
Assets | 9,943 | 9,617 | 9,943 | 9,617 | |||||||||||||||
Utility taxes | 128 | [5] | 129 | [5] | 141 | [5] | |||||||||||||
Baltimore Gas and Electric Company [Member] | |||||||||||||||||||
Segment Reporting Information [Line Items] | |||||||||||||||||||
Revenues | 761 | 697 | 653 | 1,054 | 794 | 737 | 653 | 880 | 3,165 | 3,065 | 2,735 | ||||||||
Operating revenues from affiliates | 25 | 13 | 10 | ||||||||||||||||
Income (loss) from continuing operations before income taxes | 351 | 344 | 11 | ||||||||||||||||
Income taxes | 140 | 134 | 7 | ||||||||||||||||
Net income | 52 | 46 | 16 | 85 | 47 | 50 | 22 | 77 | 211 | 210 | 4 | ||||||||
Assets | 8,078 | [16] | 7,861 | [16] | 8,078 | [16] | 7,861 | [16] | |||||||||||
Utility taxes | $59 | [5] | $86 | [5] | $82 | [5] | $75 | [5] | |||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | ||||||||||||||||||
[2] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||
[3] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||
[4] | Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. | ||||||||||||||||||
[5] | 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. | ||||||||||||||||||
[6] | The intersegment profit associated with the 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 Statement of Operations. See Note 3—Regulatory Matters for additional information. | ||||||||||||||||||
[7] | Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million 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, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million 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. | ||||||||||||||||||
[8] | Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014. | ||||||||||||||||||
[9] | Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | ||||||||||||||||||
[10] | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. | ||||||||||||||||||
[11] | 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 and Comprehensive Income. | ||||||||||||||||||
[12] | Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities. | ||||||||||||||||||
[13] | 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. | ||||||||||||||||||
[14] | 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. | ||||||||||||||||||
[15] | 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. | ||||||||||||||||||
[16] | BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities. |
Segment_Information_Generation
Segment Information - Generation Total Revenues (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | $7,255 | $6,912 | $6,024 | $7,237 | $6,163 | $6,502 | $6,141 | $6,082 | $27,429 | [1] | $24,888 | [1] | $23,489 | [1] |
Revenue from Related Parties | 23 | 70 | 48 | |||||||||||
Amortization of intangible assets related to commodity contracts | 289 | 767 | 1,505 | |||||||||||
Generation Mid Atlantic [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 5,259 | 5,204 | 5,038 | |||||||||||
Generation Midwest [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 4,475 | 4,270 | 4,848 | |||||||||||
Generation New England [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 1,422 | 1,237 | 1,093 | |||||||||||
Generation New York [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 843 | 714 | 557 | |||||||||||
Generation ERCOT [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 935 | 1,216 | 1,367 | |||||||||||
Generation Other Regions [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 1,309 | [2] | 968 | [2] | 833 | [2] | ||||||||
Generation Reportable Segments Total [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 14,243 | 13,609 | 13,736 | |||||||||||
Generation All Other Segments [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 3,150 | [3] | 2,021 | [3] | 701 | [3] | ||||||||
Generation Total Consolidated Group [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 17,393 | 15,630 | 14,437 | |||||||||||
Operating Segments [Member] | Generation Mid Atlantic [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 5,265 | [4] | 5,182 | [4] | 5,082 | [4] | ||||||||
Operating Segments [Member] | Generation Midwest [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 4,467 | [4] | 4,280 | [4] | 4,824 | [4] | ||||||||
Operating Segments [Member] | Generation New England [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 1,417 | [4] | 1,245 | [4] | 1,048 | [4] | ||||||||
Operating Segments [Member] | Generation New York [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 843 | [4] | 735 | [4] | 582 | [4] | ||||||||
Operating Segments [Member] | Generation ERCOT [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 938 | [4] | 1,222 | [4] | 1,365 | [4] | ||||||||
Operating Segments [Member] | Generation Other Regions [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 1,319 | [2],[4] | 946 | [2],[4] | 755 | [2],[4] | ||||||||
Operating Segments [Member] | Generation Reportable Segments Total [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 14,249 | [4] | 13,610 | [4] | 13,656 | [4] | ||||||||
Operating Segments [Member] | Generation All Other Segments [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 3,144 | [3],[4] | 2,020 | [3],[4] | 781 | [3],[4] | ||||||||
Operating Segments [Member] | Generation Total Consolidated Group [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | 17,393 | [4] | 15,630 | [4] | 14,437 | [4] | ||||||||
Intersegment Eliminations [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenues | -2,072 | [1] | -2,612 | [1] | -3,064 | [1] | ||||||||
Revenue from Related Parties | 6 | [5] | 14 | [5] | 6 | [5] | ||||||||
Intersegment Eliminations [Member] | Generation Mid Atlantic [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | -6 | 22 | -44 | |||||||||||
Intersegment Eliminations [Member] | Generation Midwest [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | 8 | -10 | 24 | |||||||||||
Intersegment Eliminations [Member] | Generation New England [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | 5 | -8 | 45 | |||||||||||
Intersegment Eliminations [Member] | Generation New York [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | 0 | -21 | -25 | |||||||||||
Intersegment Eliminations [Member] | Generation ERCOT [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | -3 | -6 | 2 | |||||||||||
Intersegment Eliminations [Member] | Generation Other Regions [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | -10 | [2] | 22 | [2] | 78 | [2] | ||||||||
Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | -6 | -1 | 80 | |||||||||||
Intersegment Eliminations [Member] | Generation All Other Segments [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | 6 | [3] | 1 | [3] | -80 | [3] | ||||||||
Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member] | ||||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||||
Revenue from Related Parties | $0 | $0 | $0 | |||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||
[2] | Other regions include the South, West and Canada, which are not considered individually significant. | |||||||||||||
[3] | 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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues. | |||||||||||||
[4] | Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE. | |||||||||||||
[5] | 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 and Comprehensive Income. |
Segment_Information_Generation1
Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Segment Reporting Information [Line Items] | ||||||
Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel | $124 | $488 | $1,098 | |||
Generation Mid Atlantic [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 3,417 | 3,270 | 3,433 | |||
Generation Midwest [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 2,594 | 2,586 | 2,998 | |||
Generation New England [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 351 | 185 | 196 | |||
Generation New York [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 483 | -4 | 76 | |||
Generation ERCOT [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 317 | 436 | 405 | |||
Generation Other Regions [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 327 | [1] | 201 | [1] | 131 | [1] |
Generation Reportable Segments Total [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 7,489 | 6,674 | 7,239 | |||
Generation All Other Segments [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | -21 | [2] | 759 | [2] | 137 | [2] |
Generation Total Consolidated Group [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense, Total | 7,468 | 7,433 | 7,376 | |||
Operating Segments [Member] | Generation Mid Atlantic [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 3,466 | [3] | 3,273 | [3] | 3,477 | [3] |
Operating Segments [Member] | Generation Midwest [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 2,580 | [3] | 2,585 | [3] | 2,974 | [3] |
Operating Segments [Member] | Generation New England [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 432 | [3] | 217 | [3] | 151 | [3] |
Operating Segments [Member] | Generation New York [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 457 | [3] | 14 | [3] | 101 | [3] |
Operating Segments [Member] | Generation ERCOT [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 573 | [3] | 604 | [3] | 403 | [3] |
Operating Segments [Member] | Generation Other Regions [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 611 | [1],[3] | 334 | [1],[3] | 53 | [1],[3] |
Operating Segments [Member] | Generation Reportable Segments Total [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 8,119 | [3] | 7,027 | [3] | 7,159 | [3] |
Operating Segments [Member] | Generation All Other Segments [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | -651 | [2],[3] | 406 | [2],[3] | 217 | [2],[3] |
Operating Segments [Member] | Generation Total Consolidated Group [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from external customers | 7,468 | [3] | 7,433 | [3] | 7,376 | [3] |
Intersegment Eliminations [Member] | Generation Mid Atlantic [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -49 | -3 | -44 | |||
Intersegment Eliminations [Member] | Generation Midwest [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 14 | 1 | 24 | |||
Intersegment Eliminations [Member] | Generation New England [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -81 | -32 | 45 | |||
Intersegment Eliminations [Member] | Generation New York [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 26 | -18 | -25 | |||
Intersegment Eliminations [Member] | Generation ERCOT [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -256 | -168 | 2 | |||
Intersegment Eliminations [Member] | Generation Other Regions [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -284 | [1] | -133 | [1] | 78 | [1] |
Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | -630 | -353 | 80 | |||
Intersegment Eliminations [Member] | Generation All Other Segments [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | 630 | [2] | 353 | [2] | -80 | [2] |
Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member] | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity | $0 | $0 | $0 | |||
[1] | Other regions include the South, West and Canada, which are not considered individually significant. | |||||
[2] | 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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense. | |||||
[3] | Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE. |
Related_Party_Transactions_Rel
Related Party Transactions - Related Party Transactions included in Consolidated Income Statement (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 01, 2014 | Mar. 11, 2012 | |||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | $23 | $70 | $48 | |||||||||||||
Revenues | 7,255 | 6,912 | 6,024 | 7,237 | 6,163 | 6,502 | 6,141 | 6,082 | 27,429 | [1] | 24,888 | [1] | 23,489 | [1] | ||
Purchase power and fuel from affiliates | 531 | 1,256 | 1,036 | |||||||||||||
Total interest expense to affiliates, net | 41 | 41 | 37 | |||||||||||||
Total income (loss) in equity method investments | -20 | 10 | -91 | |||||||||||||
Cash dividends paid to parent | 1,065 | 1,249 | 1,716 | |||||||||||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | |||||||||||||||
Purchase of nuclear output of CENG | 50.01% | |||||||||||||||
Purchase of nuclear output by EDF | 49.99% | |||||||||||||||
PECO Energy Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 1 | [2] | 10 | [2] | 6 | [2] | ||||||||||
Constellation Energy Nuclear Group Llc Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 17 | [3] | 56 | [3] | 42 | [3] | ||||||||||
Purchase power and fuel from affiliates | 282 | [4] | 992 | [4] | 793 | [4] | ||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 5 | 4 | 0 | |||||||||||||
Keystone Fuels LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 138 | [5] | 144 | [5] | 119 | [5] | ||||||||||
Conemaugh Fuels LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 99 | [5] | 98 | [5] | 101 | [5] | ||||||||||
SafeHarborWaterPowerCorp [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 12 | [5] | 22 | [5] | 23 | [5] | ||||||||||
ComEd Financing Three Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 13 | 13 | 13 | |||||||||||||
PECO Trust Three Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 6 | 6 | 6 | |||||||||||||
PECO Trust Four Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 6 | 6 | 6 | |||||||||||||
BGE Capital Trust II [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 16 | [6] | 16 | [6] | 12 | [6] | ||||||||||
CENG Equity Investment Income Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total income (loss) in equity method investments | -19 | [7] | 9 | [7] | -99 | [7] | ||||||||||
Other Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total income (loss) in equity method investments | -1 | 1 | 8 | |||||||||||||
Exelon Generation Co L L C [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 779 | 1,423 | 1,702 | |||||||||||||
Revenues | 4,802 | 4,412 | 3,789 | 4,390 | 3,772 | 4,255 | 4,070 | 3,533 | 17,393 | 15,630 | 14,437 | |||||
Purchase power and fuel from affiliates | 557 | 1,270 | 1,044 | |||||||||||||
Operating and maintenance from affiliates | 623 | 574 | 630 | |||||||||||||
Total interest expense to affiliates, net | 53 | 59 | 75 | |||||||||||||
Total income (loss) in equity method investments | -20 | 10 | -91 | |||||||||||||
Cash distribution paid to member | 645 | 625 | 1,626 | |||||||||||||
Contribution from member | 53 | 26 | 48 | |||||||||||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | 85.00% | ||||||||||||||
Purchase of nuclear output by EDF | 49.99% | |||||||||||||||
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 506 | [8] | 795 | [8] | ||||||||||||
Revenues | 176 | [8] | ||||||||||||||
Purchase power and fuel from affiliates | 1 | 1 | 0 | |||||||||||||
Operating and maintenance from affiliates | 3 | [9] | 2 | [9] | 2 | [9] | ||||||||||
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 405 | [10] | 543 | [10] | ||||||||||||
Revenues | 198 | [10] | ||||||||||||||
Operating and maintenance from affiliates | 2 | [9] | 1 | [9] | 3 | [9] | ||||||||||
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 455 | [11] | 322 | [11] | ||||||||||||
Revenues | 387 | [11] | ||||||||||||||
Purchase power and fuel from affiliates | 25 | 13 | 8 | |||||||||||||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 17 | [3] | 56 | [3] | 42 | [3] | ||||||||||
Purchase power and fuel from affiliates | 282 | [4] | 992 | [4] | 793 | [4] | ||||||||||
Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 1 | 1 | 0 | |||||||||||||
Operating and maintenance from affiliates | 618 | [12] | 571 | [12] | 625 | [12] | ||||||||||
Capitalized Costs | 91 | [13] | 93 | [13] | 80 | [13] | ||||||||||
Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 53 | 59 | 75 | |||||||||||||
Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 138 | [5] | 144 | [5] | 119 | [5] | ||||||||||
Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 99 | [5] | 98 | [5] | 101 | [5] | ||||||||||
Exelon Generation Co L L C [Member] | SafeHarborWaterPowerCorp [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Purchase power and fuel from affiliates | 12 | 22 | 23 | |||||||||||||
Exelon Generation Co L L C [Member] | CENG Equity Investment Income Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total income (loss) in equity method investments | -19 | [14] | 9 | [14] | -99 | [14] | ||||||||||
Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total income (loss) in equity method investments | -1 | 1 | 8 | |||||||||||||
Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total income (loss) in equity method investments | -20 | |||||||||||||||
Commonwealth Edison Co [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 4 | 3 | 2 | |||||||||||||
Revenues | 1,079 | 1,222 | 1,128 | 1,134 | 1,068 | 1,156 | 1,080 | 1,160 | 4,564 | 4,464 | 5,443 | |||||
Operating and maintenance from affiliates | 166 | 157 | 163 | |||||||||||||
Total interest expense to affiliates, net | 13 | 13 | 13 | |||||||||||||
Total income (loss) in equity method investments | 0 | 0 | ||||||||||||||
Cash dividends paid to parent | 307 | 220 | 105 | |||||||||||||
Non-cash contribution to equity | 273 | 0 | 11 | |||||||||||||
Contributions from parent | 273 | 0 | 0 | |||||||||||||
Amortization of energy contract assets and liabilities | 0 | [15] | 0 | [15] | ||||||||||||
Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 4 | 3 | 2 | |||||||||||||
Purchase power and fuel from affiliates | 176 | [16] | 512 | [16] | 789 | [16] | ||||||||||
Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating and maintenance from affiliates | 166 | [13] | 157 | [13] | 163 | [13] | ||||||||||
Capitalized Costs | 77 | [13] | 69 | [13] | 92 | [13] | ||||||||||
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 13 | 13 | 13 | |||||||||||||
Baltimore Gas and Electric Company [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 25 | 13 | 10 | |||||||||||||
Revenues | 761 | 697 | 653 | 1,054 | 794 | 737 | 653 | 880 | 3,165 | 3,065 | 2,735 | |||||
Operating and maintenance from affiliates | 103 | 83 | 106 | |||||||||||||
Total interest expense to affiliates, net | 16 | 16 | 16 | 4 | ||||||||||||
Total income (loss) in equity method investments | 0 | 0 | 0 | |||||||||||||
Contributions from parent | 0 | 0 | 66 | |||||||||||||
Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 25 | [17] | 13 | [17] | 10 | [17] | ||||||||||
Purchase power and fuel from affiliates | 382 | [18] | 452 | [18] | 396 | [18] | ||||||||||
Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating and maintenance from affiliates | 103 | [19] | 83 | [19] | 106 | [19] | ||||||||||
Capitalized Costs | 19 | [19] | 15 | [19] | 21 | [19] | ||||||||||
Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 16 | 16 | 16 | |||||||||||||
PECO Energy Co [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 2 | 1 | 3 | |||||||||||||
Revenues | 750 | 693 | 656 | 993 | 805 | 728 | 672 | 895 | 3,094 | 3,100 | 3,186 | |||||
Operating and maintenance from affiliates | 99 | 101 | 111 | |||||||||||||
Total interest expense to affiliates, net | 12 | 12 | 12 | |||||||||||||
Total income (loss) in equity method investments | 0 | 0 | 0 | |||||||||||||
Cash dividends paid to parent | 320 | 332 | 343 | |||||||||||||
Contributions from parent | 24 | 27 | 9 | |||||||||||||
PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating revenues from affiliates | 2 | [20] | 1 | [20] | 3 | [20] | ||||||||||
Purchase power and fuel from affiliates | 194 | [21] | 392 | [21] | 533 | [21] | ||||||||||
Operating and maintenance from affiliates | 3 | 3 | 4 | |||||||||||||
PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Operating and maintenance from affiliates | 96 | [22] | 98 | [22] | 107 | [22] | ||||||||||
Capitalized Costs | 39 | [22] | 46 | [22] | 54 | [22] | ||||||||||
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | 6 | 6 | 6 | |||||||||||||
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member] | ||||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||||
Total interest expense to affiliates, net | $6 | $6 | $6 | |||||||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | |||||||||||||||
[2] | The intersegment profit associated with the 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 Statement of Operations. See Note 3—Regulatory Matters for additional information. | |||||||||||||||
[3] | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||||||
[4] | CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||||||
[5] | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | |||||||||||||||
[6] | The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. | |||||||||||||||
[7] | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC | |||||||||||||||
[8] | 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. | |||||||||||||||
[9] | 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. | |||||||||||||||
[10] | 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. | |||||||||||||||
[11] | 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. | |||||||||||||||
[12] | 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. | |||||||||||||||
[13] | 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. | |||||||||||||||
[14] | Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | |||||||||||||||
[15] | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | |||||||||||||||
[16] | 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, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information. | |||||||||||||||
[17] | BGE provides energy to Generation for Generation’s own use. | |||||||||||||||
[18] | 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. | |||||||||||||||
[19] | 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. | |||||||||||||||
[20] | PECO provides energy to Generation for Generation’s own use. | |||||||||||||||
[21] | 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. | |||||||||||||||
[22] | 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. |
Related_Party_Transactions_Rel1
Related Party Transactions - Related Party Transactions included in Consolidated Balance Sheet (Details) (USD $) | 12 Months Ended | 0 Months Ended | 12 Months Ended | ||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Apr. 01, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | ($8) | ($116) | |||||
Long-term debt to financing trusts | 648 | 648 | |||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | ||||||
Purchase of nuclear output of CENG | 50.01% | ||||||
Purchase of nuclear output by EDF | 49.99% | ||||||
CENG Equity Investment Income Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 0 | [1] | 3 | [1] | |||
ComEd Financing Three Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -4 | -4 | |||||
Long-term debt to financing trusts | 206 | 206 | |||||
PECO Trust Three Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -1 | -1 | |||||
Long-term debt to financing trusts | 81 | 81 | |||||
PECO Trust Four Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Long-term debt to financing trusts | 103 | 103 | |||||
BGE Capital Trust II [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -3 | -4 | |||||
Long-term debt to financing trusts | 258 | 258 | |||||
Constellation Energy Nuclear Group Llc Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 0 | [1] | 3 | [1] | |||
Total payables to affiliates (current) | 0 | [2] | -85 | [2] | |||
Keystone Fuels LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | [3] | -12 | [3] | |||
Conemaugh Fuels LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | [3] | -9 | [3] | |||
Other Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | -1 | |||||
Exelon Generation Co L L C [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 113 | 108 | |||||
Total payables to affiliates (current) | -107 | -181 | |||||
Total payables to affiliates (noncurrent) | 2,880 | 2,740 | |||||
Required purchases of power from CENG's nuclear plants not sold to third parties | 85.00% | 85.00% | |||||
Purchase of nuclear output by EDF | 49.99% | ||||||
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 43 | [4] | 38 | [4] | |||
Total payables to affiliates (current) | -12 | 0 | |||||
Total payables to affiliates (noncurrent) | 2,389 | [5] | 2,293 | [5] | |||
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | [2] | -85 | [2] | |||
Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | [3] | -12 | [3] | |||
Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | 0 | [3] | -9 | [3] | |||
Exelon Generation Co L L C [Member] | Other Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 1 | 2 | |||||
Total payables to affiliates (current) | 0 | -2 | |||||
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 29 | [6] | 38 | [6] | |||
Total payables to affiliates (noncurrent) | 490 | [5] | 447 | [5] | |||
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 40 | [7] | 27 | [7] | |||
Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -12 | [8] | -7 | [8] | |||
Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -83 | [9] | -66 | [9] | |||
Total payables to affiliates (noncurrent) | 1 | [9] | 0 | [9] | |||
Baltimore Gas and Electric Company [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -66 | -55 | |||||
Prepaid voluntary employee beneficiary association trust | 1 | [10] | 1 | [10] | |||
Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -3 | -4 | |||||
Long-term debt to financing trusts | 258 | 258 | |||||
Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -1 | -3 | |||||
Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -40 | [11] | -27 | [11] | |||
Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -5 | [10] | -1 | [10] | |||
Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -17 | [12] | -20 | [12] | |||
PECO Energy Co [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 3 | 3 | |||||
Total receivable from affiliates (noncurrent) | 490 | 447 | |||||
Total payables to affiliates (current) | -52 | -58 | |||||
Long-term debt to financing trusts | 184 | 184 | |||||
Prepaid voluntary employee beneficiary association trust | 3 | [13] | 3 | [13] | |||
PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivable from affiliates (noncurrent) | 2 | 0 | |||||
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
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 Transaction [Line Items] | |||||||
Long-term debt to financing trusts | 103 | 103 | |||||
PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivable from affiliates (noncurrent) | 1 | 3 | |||||
PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivable from affiliates (noncurrent) | 490 | [14] | 447 | [14] | |||
Total payables to affiliates (current) | -29 | [15] | -38 | [15] | |||
PECO Energy Co [Member] | Exelon Corporation Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -2 | -2 | |||||
PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -20 | [16] | -17 | [16] | |||
Commonwealth Edison Co [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 14 | 3 | |||||
Total receivable from affiliates (noncurrent) | 2,571 | 2,469 | |||||
Total payables to affiliates (current) | -84 | -83 | |||||
Prepaid voluntary employee beneficiary association trust | 13 | [17] | 13 | [17] | |||
Energy Contract Amortization | 0 | [18] | 0 | [18] | |||
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -4 | -4 | |||||
Long-term debt to financing trusts | 206 | 206 | |||||
Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 2 | 3 | |||||
Commonwealth Edison Co [Member] | Other Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivable from affiliates (noncurrent) | 182 | [19] | 176 | [19] | |||
Total payables to affiliates (current) | 0 | -2 | |||||
Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -2 | 0 | |||||
Commonwealth Edison Co [Member] | Baltimore Gas And Electric Company Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivables from affiliates (current) | 12 | 0 | |||||
Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total receivable from affiliates (noncurrent) | 2,389 | [20] | 2,293 | [20] | |||
Total payables to affiliates (current) | -43 | [21] | -38 | [21] | |||
Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | -3 | -9 | |||||
Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member] | |||||||
Related Party Transaction [Line Items] | |||||||
Total payables to affiliates (current) | ($32) | [22] | ($30) | [22] | |||
[1] | Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an 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. On April 1, 2014, Generation and CENG entered into 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | ||||||
[2] | CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing 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 (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC. | ||||||
[3] | During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information. | ||||||
[4] | 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. | ||||||
[5] | 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 | ||||||
[6] | 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. | ||||||
[7] | 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. | ||||||
[8] | The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation. | ||||||
[9] | 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. | ||||||
[10] | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’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. | ||||||
[11] | 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. | ||||||
[12] | 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. | ||||||
[13] | The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. 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. | ||||||
[14] | 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. | ||||||
[15] | 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. | ||||||
[16] | 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. | ||||||
[17] | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. 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. | ||||||
[18] | Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. | ||||||
[19] | Represents indemnification from Exelon Corporate related to the like-kind exchange transaction. | ||||||
[20] | 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. | ||||||
[21] | 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, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information. | ||||||
[22] | 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. |
Quarterly_Data_Unaudited_Quart
Quarterly Data (Unaudited) - Quarterly Operating Results (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||||||||||
Operating Revenues | $7,255 | $6,912 | $6,024 | $7,237 | $6,163 | $6,502 | $6,141 | $6,082 | $27,429 | [1] | $24,888 | [1] | $23,489 | [1] | |||||
Operating Income | 348 | 1,739 | [2] | 842 | [2] | 168 | [2] | ||||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 18 | [3] | 993 | 522 | 90 | 495 | 738 | 490 | -4 | [4] | 1,820 | 1,729 | 1,171 | ||||||
Reclassifications to Operating Income (Loss) | 339 | 13 | 5 | ||||||||||||||||
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | 265 | ||||||||||||||||||
Exelon Generation Co L L C [Member] | |||||||||||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||||||||||
Operating Revenues | 4,802 | 4,412 | 3,789 | 4,390 | 3,772 | 4,255 | 4,070 | 3,533 | 17,393 | 15,630 | 14,437 | ||||||||
Operating Income | -105 | 1,225 | [5] | 441 | [5] | -384 | [5] | 405 | |||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | -91 | 771 | 340 | -185 | 269 | 490 | 330 | -18 | 1,019 | 1,060 | 558 | ||||||||
Reclassifications to Operating Income (Loss) | 338 | 12 | 5 | 8 | 5 | ||||||||||||||
Commonwealth Edison Co [Member] | |||||||||||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||||||||||
Operating Revenues | 1,079 | 1,222 | 1,128 | 1,134 | 1,068 | 1,156 | 1,080 | 1,160 | 4,564 | 4,464 | 5,443 | ||||||||
Operating Income | 196 | 288 | [6] | 259 | [6] | 238 | 236 | 278 | 232 | 209 | |||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 73 | 126 | 111 | 98 | 109 | 126 | 96 | -81 | 408 | 249 | 379 | ||||||||
Reclassifications to Operating Income (Loss) | 1 | 1 | |||||||||||||||||
Unrecognized Tax Benefits, Interest on Income Taxes Accrued | 170 | ||||||||||||||||||
PECO Energy Co [Member] | |||||||||||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||||||||||
Operating Revenues | 750 | 693 | 656 | 993 | 805 | 728 | 672 | 895 | 3,094 | 3,100 | 3,186 | ||||||||
Operating Income | 156 | 133 | 134 | 149 | 168 | 155 | 138 | 203 | |||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | 98 | 81 | 84 | 89 | 102 | 92 | 72 | 121 | 352 | 395 | 381 | ||||||||
Baltimore Gas and Electric Company [Member] | |||||||||||||||||||
Selected Quarterly Financial Information [Line Items] | |||||||||||||||||||
Operating Revenues | 761 | 697 | 653 | 1,054 | 794 | 737 | 653 | 880 | 3,165 | 3,065 | 2,735 | ||||||||
Operating Income | 113 | 102 | 55 | 169 | 101 | 114 | 69 | 163 | |||||||||||
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest | $52 | $46 | $16 | $85 | $47 | $50 | $22 | $77 | $211 | $210 | $4 | ||||||||
[1] | For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively. | ||||||||||||||||||
[2] | In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock. | ||||||||||||||||||
[3] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||
[4] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | ||||||||||||||||||
[5] | In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest. | ||||||||||||||||||
[6] | In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income. |
Quarterly_Data_Unaudited_Quart1
Quarterly Data (Unaudited) - Quarterly Per Share Information (Details) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Quarterly Financial Data [Abstract] | |||||||||||
Weighted average common shares outstanding—basic | 861 | 861 | 860 | 858 | 856 | 857 | 856 | 855 | 860 | 856 | 816 |
Earnings Per Share, Basic | $0.02 | $1.15 | $0.61 | $0.10 | $0.60 | $0.86 | $0.57 | ($0.01) | |||
Weighted average common shares outstanding—diluted | 868 | 863 | 864 | 861 | 860 | 860 | 860 | 855 | 864 | 860 | 819 |
Earnings Per Share, Diluted | $0.02 | $1.15 | $0.60 | $0.10 | $0.59 | $0.86 | $0.57 | ($0.01) | $1.88 | $2 | $1.42 |
Quarterly_Data_Unaudited_Quart2
Quarterly Data (Unaudited) - Quarterly Composite Common Stock Prices and Dividends (Details) (USD $) | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 |
Quarterly Financial Data [Abstract] | ||||||||
High price | $38.93 | $36.26 | $37.73 | $33.94 | $30.59 | $32.42 | $37.80 | $34.56 |
Low price | $33.07 | $30.66 | $33.11 | $26.45 | $26.64 | $29.42 | $29.84 | $29.10 |
Close | $37.08 | $34.09 | $36.48 | $33.56 | $27.39 | $29.64 | $30.88 | $34.48 |
Dividends | $0.31 | $0.31 | $0.31 | $0.31 | $0.31 | $0.31 | $0.31 | $0.53 |
Schedule_I_Condensed_Financial1
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Operations and Other Comprehensive Income (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||||||||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Operating Expenses [Abstract] | ||||||||||||||
Operating and maintenance | $8,568 | $7,270 | $7,961 | |||||||||||
Total operating expenses | 25,039 | 21,242 | 21,018 | |||||||||||
Operating Income (Loss) | 3,096 | 3,669 | 2,373 | |||||||||||
Other income and (deductions) | ||||||||||||||
Interest expense, net | -1,024 | -1,315 | -891 | |||||||||||
Equity in (losses) earnings of unconsolidated affiliates | -20 | 10 | -91 | |||||||||||
Other, net | 455 | 460 | 353 | |||||||||||
Total other income and (deductions) | -610 | -896 | -575 | |||||||||||
Income before income taxes | 2,486 | 2,773 | 1,798 | |||||||||||
Income taxes | 666 | 1,044 | 627 | |||||||||||
Net income | 18 | [1] | 993 | 522 | 90 | 495 | 738 | 490 | -4 | [2] | 1,820 | 1,729 | 1,171 | |
Pension and non-pension postretirement benefit plans: | ||||||||||||||
Prior service benefit reclassified to periodic benefit cost, net of tax | 30 | 0 | -1 | |||||||||||
Actuarial loss reclassified to periodic cost, net of tax | 147 | 208 | 168 | |||||||||||
Transition obligation reclassified to periodic cost, net of tax | 0 | 0 | 2 | |||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax | -497 | 669 | -371 | |||||||||||
Unrealized gain (loss) on cash flow hedges, net of taxes | -148 | -248 | -120 | |||||||||||
Unrealized gain (loss) on marketable securities, net of taxes | 1 | 2 | 2 | |||||||||||
Unrealized gain (loss) on equity investments, net of taxes | 8 | 106 | 1 | |||||||||||
Unrealized gain (loss) on foreign currency translation, net of taxes | -9 | -10 | 0 | |||||||||||
Reversal of CENG equity method AOCI, net of taxes | -116 | 0 | 0 | |||||||||||
Other comprehensive income (loss) | -644 | 727 | [3] | -317 | ||||||||||
Comprehensive income | 1,176 | 2,456 | 854 | |||||||||||
Exelon Corporate [Member] | ||||||||||||||
Operating Expenses [Abstract] | ||||||||||||||
Operating and maintenance | 9 | 9 | 201 | |||||||||||
Operating and maintenance from affiliates | 38 | 34 | 72 | |||||||||||
Other | 3 | 12 | 6 | |||||||||||
Total operating expenses | 50 | 55 | 279 | |||||||||||
Operating Income (Loss) | -50 | -55 | -279 | |||||||||||
Other income and (deductions) | ||||||||||||||
Interest expense, net | -237 | -116 | -153 | |||||||||||
Equity in (losses) earnings of unconsolidated affiliates | 1,779 | 1,903 | 1,278 | |||||||||||
Interest income from affiliates, net | 53 | 36 | 75 | |||||||||||
Other, net | -2 | -78 | 7 | |||||||||||
Total other income and (deductions) | 1,593 | 1,745 | 1,207 | |||||||||||
Income before income taxes | 1,543 | 1,690 | 928 | |||||||||||
Income taxes | -80 | -29 | -232 | |||||||||||
Net income | 1,623 | 1,719 | 1,160 | |||||||||||
Pension and non-pension postretirement benefit plans: | ||||||||||||||
Prior service benefit reclassified to periodic benefit cost, net of tax | 30 | 0 | -1 | |||||||||||
Actuarial loss reclassified to periodic cost, net of tax | 147 | 208 | 168 | |||||||||||
Transition obligation reclassified to periodic cost, net of tax | 0 | 0 | 2 | |||||||||||
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax | -497 | 669 | -371 | |||||||||||
Unrealized gain (loss) on cash flow hedges, net of taxes | -148 | -248 | -120 | |||||||||||
Unrealized gain (loss) on marketable securities, net of taxes | 1 | 2 | 2 | |||||||||||
Unrealized gain (loss) on equity investments, net of taxes | 8 | 106 | 1 | |||||||||||
Unrealized gain (loss) on foreign currency translation, net of taxes | -9 | -10 | 0 | |||||||||||
Reversal of CENG equity method AOCI, net of taxes | -116 | 0 | 0 | |||||||||||
Other comprehensive income (loss) | -644 | 727 | -317 | |||||||||||
Comprehensive income | $979 | $2,446 | $843 | |||||||||||
[1] | Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||
[2] | Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. | |||||||||||||
[3] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Schedule_I_Condensed_Financial2
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Cash Flows (Details) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Net cash flows provided by operating activities | $4,457 | $6,343 | $6,131 |
Cash flows from investing activities | |||
Proceeds from termination of direct financing lease investment | 335 | 0 | 0 |
Capital expenditures | -6,077 | -5,395 | -5,789 |
Cash and restricted cash acquired from Constellation | 140 | 0 | 964 |
Change in restricted cash | -104 | -43 | -34 |
Other investing activities | -88 | 112 | 136 |
Net cash flows used in investing activities | -4,599 | -5,394 | -4,576 |
Cash flows from financing activities | |||
Changes in short-term borrowings | 122 | 332 | -197 |
Issuance of long-term debt | 3,463 | 2,055 | 2,027 |
Retirement of long-term debt | -1,545 | -1,589 | -1,145 |
Dividends paid on common stock | -1,065 | -1,249 | -1,716 |
Proceeds from employee stock plans | 35 | 47 | 72 |
Other financing activities | -178 | -119 | -111 |
Net cash flows provided by (used in) financing activities | 411 | -826 | -1,085 |
Increase in cash and cash equivalents | 269 | 123 | 470 |
Cash and cash equivalents at beginning of period | 1,609 | 1,486 | 1,016 |
Cash and cash equivalents at end of period | 1,878 | 1,609 | 1,486 |
Exelon Corporate [Member] | |||
Net cash flows provided by operating activities | 806 | 1,053 | 2,131 |
Cash flows from investing activities | |||
Proceeds from termination of direct financing lease investment | 335 | 0 | 0 |
Changes in Exelon intercompany money pool | -83 | -60 | 0 |
Note receivable from affiliates | 0 | 484 | 0 |
Capital expenditures | 1 | 0 | -30 |
Cash and restricted cash acquired from Constellation | 0 | 0 | 679 |
Change in restricted cash | 0 | 38 | -38 |
Investment in affiliates | -70 | -38 | -67 |
Other investing activities | -126 | 15 | 0 |
Net cash flows used in investing activities | 57 | 439 | 544 |
Cash flows from financing activities | |||
Changes in Exelon intercompany money pool | 0 | 0 | -703 |
Changes in short-term borrowings | 0 | 10 | -161 |
Issuance of long-term debt | 1,150 | 0 | 0 |
Retirement of long-term debt | -23 | -450 | -77 |
Dividends paid on common stock | -1,065 | -1,249 | -1,716 |
Proceeds from employee stock plans | 35 | 47 | 73 |
Other financing activities | -84 | -6 | 30 |
Net cash flows provided by (used in) financing activities | 13 | -1,648 | -2,554 |
Increase in cash and cash equivalents | 876 | -156 | 121 |
Cash and cash equivalents at beginning of period | 3 | 159 | 38 |
Cash and cash equivalents at end of period | $879 | $3 | $159 |
Schedule_I_Condensed_Financial3
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
In Millions, unless otherwise specified | |||||||
Current assets | |||||||
Cash and cash equivalents | $1,878 | $1,609 | $1,486 | $1,016 | |||
Accounts receivable, net | |||||||
Other | 1,227 | 1,175 | |||||
Deferred income taxes | 244 | 573 | |||||
Regulatory assets | 847 | 760 | |||||
Other | 865 | 652 | |||||
Total current assets | 12,097 | 10,137 | |||||
Property, plant and equipment, net | 52,087 | 47,330 | |||||
Deferred debits and other assets | |||||||
Regulatory assets | 6,076 | 5,910 | |||||
Other | 1,160 | 964 | |||||
Total deferred debits and other assets | 22,630 | 22,457 | |||||
Total assets | 86,814 | [1] | 79,924 | [1] | |||
Current liabilities | |||||||
Long-term debt due within one year | 1,802 | 1,509 | |||||
Accounts payable | 3,048 | 2,484 | |||||
Unamortized energy contract liabilities | 238 | 261 | |||||
Accrued expenses | 1,539 | 1,633 | |||||
Deferred income taxes | 0 | 40 | |||||
Regulatory liabilities | 310 | 327 | |||||
Other | 1,123 | 858 | |||||
Total current liabilities | 8,762 | 7,728 | |||||
Long-term debt | 19,362 | 17,623 | |||||
Deferred credits and other liabilities | |||||||
Regulatory liabilities | 4,550 | 4,388 | |||||
Pension obligations | 3,366 | 1,876 | |||||
Non-pension postretirement benefit obligations | 1,742 | 2,190 | |||||
Other | 2,147 | 2,540 | |||||
Total deferred credits and other liabilities | 33,909 | 30,985 | |||||
Total liabilities | 62,681 | [1] | 56,984 | [1] | |||
Shareholders’ equity | |||||||
Common stock | 16,709 | 16,741 | |||||
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013) | -2,327 | -2,327 | |||||
Retained earnings | 10,910 | 10,358 | |||||
Accumulated other comprehensive loss, net | -2,684 | -2,040 | [2] | -2,767 | [2] | ||
Total shareholders’ equity | 22,608 | 22,732 | |||||
BGE preference stock not subject to mandatory redemption | 193 | 193 | |||||
Total liabilities and shareholders’ equity | 86,814 | 79,924 | |||||
Exelon Corporate [Member] | |||||||
Current assets | |||||||
Cash and cash equivalents | 879 | 3 | 159 | 38 | |||
Accounts receivable, net | |||||||
Other | 209 | 72 | |||||
Accounts receivable from affiliates | 24 | 22 | |||||
Deferred income taxes | 20 | 27 | |||||
Receivables from affiliates | 818 | 179 | |||||
Regulatory assets | 254 | 233 | |||||
Other | 22 | 1 | |||||
Total current assets | 2,226 | 537 | |||||
Property, plant and equipment, net | 54 | 57 | |||||
Deferred debits and other assets | |||||||
Regulatory assets | 3,186 | 3,005 | |||||
Investments in affiliates | 26,670 | 26,390 | |||||
Deferred income taxes | 2,187 | 1,890 | |||||
Receivable from affiliates | 943 | 1,522 | |||||
Other | 172 | 17 | |||||
Total deferred debits and other assets | 33,158 | 32,824 | |||||
Total assets | 35,438 | 33,418 | |||||
Current liabilities | |||||||
Long-term debt due within one year | 1,409 | 10 | |||||
Accounts payable | 2 | 43 | |||||
Unamortized energy contract liabilities | 0 | 12 | |||||
Accrued expenses | 25 | 106 | |||||
Deferred income taxes | 60 | 26 | |||||
Regulatory liabilities | 51 | 2 | |||||
Other | 75 | 54 | |||||
Total current liabilities | 1,622 | 253 | |||||
Long-term debt | 2,841 | 3,033 | |||||
Payables to affiliates | 182 | 176 | |||||
Deferred credits and other liabilities | |||||||
Regulatory liabilities | 37 | 43 | |||||
Pension obligations | 7,638 | 6,444 | |||||
Non-pension postretirement benefit obligations | 16 | 393 | |||||
Deferred income taxes | 93 | 70 | |||||
Other | 398 | 271 | |||||
Total deferred credits and other liabilities | 8,182 | 7,221 | |||||
Total liabilities | 12,827 | 10,683 | |||||
Commitments and Contingencies | |||||||
Shareholders’ equity | |||||||
Common stock | 16,709 | 16,741 | |||||
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013) | -2,327 | -2,327 | |||||
Retained earnings | 10,910 | 10,358 | |||||
Accumulated other comprehensive loss, net | -2,684 | -2,040 | |||||
Total shareholders’ equity | 22,608 | 22,732 | |||||
BGE preference stock not subject to mandatory redemption | 3 | 3 | |||||
Total liabilities and shareholders’ equity | $35,438 | $33,418 | |||||
[1] | Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities. | ||||||
[2] | All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income. |
Schedule_I_Condensed_Financial4
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet - Phantom (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 859,833,343 | 857,290,484 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
Exelon Corporate [Member] | ||
Common stock, par value | $0 | $0 |
Common stock, shares authorized | 2,000,000,000 | 2,000,000,000 |
Common stock, shares outstanding | 860,000,000 | 857,000,000 |
Treasury Stock, Shares held | 35,000,000 | 35,000,000 |
Schedule_I_Condensed_Financial5
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Basis of Presentation - Narrative (Details) (Exelon Corporate [Member]) | Dec. 31, 2014 |
Exelon Generation Co L L C [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 100.00% |
Commonwealth Edison Co [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 99.00% |
Baltimore Gas and Electric Company [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 100.00% |
Baltimore Gas and Electric Company [Member] | Preferred Stock [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 0.00% |
PECO Energy Co [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 100.00% |
PECO Energy Co [Member] | Preferred Stock [Member] | |
Schedule of Equity Method Investments [Line Items] | |
Ownership percentage (more than 99% for ComEd) | 0.00% |
Schedule_I_Condensed_Financial6
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Narrative (Details) (USD $) | Dec. 31, 2014 | 30-May-14 | ||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Capacity Available for Trade Purchases | $6,771,000,000 | [1] | ||
Exelon Corporate [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Capacity Available for Trade Purchases | 494,000,000 | [1] | ||
Revolving Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Maximum Program Size | 8,500,000,000 | [2] | ||
Revolving Credit Facility [Member] | Exelon Corporate [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Maximum Program Size | $500,000,000 | [2] | $500,000,000 | [3],[4] |
[1] | Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program. | |||
[2] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below | |||
[3] | Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below. | |||
[4] | aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size. |
Schedule_I_Condensed_Financial7
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Outstanding Long-term Debt (Details) (USD $) | 12 Months Ended | ||||
Dec. 31, 2014 | Jun. 30, 2014 | Dec. 31, 2013 | |||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | $20,756,000,000 | $18,760,000,000 | |||
Unamortized debt discount and premium, net | -37,000,000 | -19,000,000 | |||
Long-term debt | 19,362,000,000 | 17,623,000,000 | |||
Junior Subordinated Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 1,150,000,000 | 1,150,000,000 | 0 | ||
Maximum interest rate on long-term debt | 6.50% | ||||
Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 7,071,000,000 | 7,571,000,000 | |||
Minimum interest rate on long-term debt | 2.00% | ||||
Maximum interest rate on long-term debt | 7.60% | ||||
Exelon Corporate [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 3,808,000,000 | 2,658,000,000 | |||
Unamortized debt discount and premium, net | 1,000,000 | 2,000,000 | |||
Fair value adjustment | 441,000,000 | 383,000,000 | |||
Long-term debt due within one year | -1,409,000,000 | -10,000,000 | |||
Long-term debt | 2,841,000,000 | 3,033,000,000 | |||
Exelon Corporate [Member] | Junior Subordinated Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Long-term Debt, Gross | 1,150,000,000 | 0 | |||
Maximum interest rate on long-term debt | 6.50% | ||||
Exelon Corporate [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Unsecured Long Term Debt | $2,658,000,000 | [1] | $2,658,000,000 | [1] | |
Minimum interest rate on long-term debt | 4.90% | [1] | |||
Maximum interest rate on long-term debt | 7.60% | [1] | |||
[1] | {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246RTczRDE1N0YxNENENzFBMzYxQjc2MDU5RUNERTM1RjkM} |
Schedule_I_Condensed_Financial8
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Debt Maturities (Details) (USD $) | Dec. 31, 2014 | Jun. 30, 2014 | |
Debt Instrument [Line Items] | |||
2015 | $1,739,000,000 | ||
2016 | 1,269,000,000 | ||
2017 | 2,400,000,000 | ||
2018 | 1,415,000,000 | ||
2019 | 982,000,000 | ||
Thereafter | 13,599,000,000 | [1] | |
Total | 21,404,000,000 | 131,000,000 | |
Exelon Corporate [Member] | |||
Debt Instrument [Line Items] | |||
2015 | 1,350,000,000 | ||
2016 | 0 | ||
2017 | 1,150,000,000 | ||
2018 | 0 | ||
2019 | 0 | ||
Thereafter | 1,308,000,000 | ||
Total | $3,808,000,000 | ||
[1] | Includes $648 million due to ComEd, PECO and BGE financing trusts. |
Schedule_I_Condensed_Financial9
Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Related Party Transactions - Summary of Related Party Transactions (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | ($20) | $10 | ($91) | |||
Exelon Corporate [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Operating and maintenance from affiliates | 38 | 34 | 72 | |||
Interest income from affiliates, net | 53 | 36 | 75 | |||
Total income (loss) in equity method investments | 1,779 | 1,903 | 1,278 | |||
Cash contributions received from affiliates | 1,370 | 1,175 | 2,074 | |||
Accounts receivable from affiliates | 24 | 22 | ||||
Receivables from affiliates | 818 | 179 | ||||
Investments in affiliates | 26,670 | 26,390 | ||||
Total receivable from affiliates (noncurrent) | 943 | 1,522 | ||||
Total payables to affiliates (noncurrent) | 182 | 176 | ||||
Exelon Corporate [Member] | Business Services Company [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Operating and maintenance from affiliates | 38 | [1] | 34 | [1] | 72 | [1] |
Accounts receivable from affiliates | 2 | [1] | 3 | [1] | ||
Receivables from affiliates | 262 | [1] | 179 | [1] | ||
Investments in affiliates | 193 | [1] | 201 | [1] | ||
Exelon Corporate [Member] | Exelon Energy Delivery Company LLC [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | 958 | [2] | 834 | [2] | 713 | [2] |
Investments in affiliates | 13,590 | [2] | 12,956 | [2] | ||
Exelon Corporate [Member] | Exelon Ventures Company LLC [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | 926 | [3] | 1,076 | [3] | 564 | [3] |
Investments in affiliates | 0 | [3] | 12,750 | [3] | ||
Exelon Corporate [Member] | UII LLC [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | -6 | -2 | 25 | |||
Investments in affiliates | 130 | 470 | ||||
Exelon Corporate [Member] | Exelon Transmission Company LLC [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | -7 | -5 | -3 | |||
Investments in affiliates | 1 | 3 | ||||
Exelon Corporate [Member] | ExelonEnterprise [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | -1 | 0 | 0 | |||
Investments in affiliates | 23 | 0 | ||||
Exelon Corporate [Member] | Exelon Generation Consolidated [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | -91 | 0 | 0 | |||
Receivables from affiliates | 556 | 0 | ||||
Investments in affiliates | 12,720 | 0 | ||||
Exelon Corporate [Member] | Exelon Consolidations [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Total income (loss) in equity method investments | 0 | [4] | 0 | [4] | -21 | [4] |
Investments in affiliates | 4 | 0 | ||||
Exelon Corporate [Member] | Exelon Generation Co L L C [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts receivable from affiliates | 12 | 7 | ||||
Total receivable from affiliates (noncurrent) | 943 | 1,522 | ||||
Exelon Corporate [Member] | Commonwealth Edison Co [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts receivable from affiliates | 3 | 9 | ||||
Total payables to affiliates (noncurrent) | 182 | 176 | ||||
Exelon Corporate [Member] | PECO Energy Co [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts receivable from affiliates | 2 | 2 | ||||
Exelon Corporate [Member] | Baltimore Gas and Electric Company [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Accounts receivable from affiliates | 5 | 1 | ||||
Exelon Corporate [Member] | VEBA [Member] | ||||||
Related Party Transaction [Line Items] | ||||||
Investments in affiliates | $9 | $10 | ||||
[1] | Exelon Corporate 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. | |||||
[2] | Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE. | |||||
[3] | Exelon Ventures Company, LLC primarily consisted of Generation | |||||
[4] | Equity in earnings of investments for Exelon Consolidations represents the intercompany income component that offsets the corresponding intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate. |
Schedule_II_Valuation_and_Qual1
Schedule II - Valuation and Qualifying Accounts (Details) (USD $) | 12 Months Ended | |||||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Allowance for Uncollectible Accounts [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | $272 | [1] | $293 | [1] | $199 | [1] |
Charged to Costs and Expenses | 175 | [1] | 121 | [1] | 144 | [1] |
Charged to Other Accounts | 69 | [1] | 37 | [1],[2] | 136 | [1],[2],[3] |
Deductions | 205 | [1],[4] | 179 | [1],[4] | 186 | [1],[4] |
Balance at End of Period | 311 | [1] | 272 | [1] | 293 | [1] |
Deferred Tax Valuation Allowance [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 13 | 36 | 10 | |||
Charged to Costs and Expenses | 0 | 1 | 18 | |||
Charged to Other Accounts | 37 | 0 | 18 | [3] | ||
Deductions | 0 | 24 | 10 | |||
Balance at End of Period | 50 | 13 | 36 | |||
Reserve for Obsolete Materials [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 58 | 53 | 60 | |||
Charged to Costs and Expenses | 5 | 17 | 2 | |||
Charged to Other Accounts | 34 | 0 | 2 | [3] | ||
Deductions | 2 | 12 | 11 | |||
Balance at End of Period | 95 | 58 | 53 | |||
Exelon Generation Co L L C [Member] | Allowance for Uncollectible Accounts [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 57 | 84 | 29 | |||
Charged to Costs and Expenses | 14 | -16 | 0 | |||
Charged to Other Accounts | 8 | 0 | 66 | [1] | ||
Deductions | 19 | 11 | 11 | |||
Balance at End of Period | 60 | 57 | 84 | |||
Exelon Generation Co L L C [Member] | Deferred Tax Valuation Allowance [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 11 | 35 | 0 | |||
Charged to Costs and Expenses | 0 | 1 | 17 | |||
Charged to Other Accounts | 37 | 0 | 18 | [1] | ||
Deductions | 0 | 25 | 0 | |||
Balance at End of Period | 48 | 11 | 35 | |||
Exelon Generation Co L L C [Member] | Reserve for Obsolete Materials [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 55 | 50 | 59 | |||
Charged to Costs and Expenses | 5 | 16 | 0 | |||
Charged to Other Accounts | 32 | 0 | 2 | [1] | ||
Deductions | -1 | 11 | 11 | |||
Balance at End of Period | 93 | 55 | 50 | |||
Commonwealth Edison Co [Member] | Allowance for Uncollectible Accounts [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 62 | 70 | 78 | |||
Charged to Costs and Expenses | 45 | 33 | 42 | |||
Charged to Other Accounts | 33 | [5] | 29 | [5] | 26 | [5] |
Deductions | 56 | [4] | 70 | [4] | 76 | [4] |
Balance at End of Period | 84 | 62 | 70 | |||
Commonwealth Edison Co [Member] | Reserve for Obsolete Materials [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 2 | 2 | 1 | |||
Charged to Costs and Expenses | 0 | 1 | 1 | |||
Charged to Other Accounts | 2 | 0 | 0 | |||
Deductions | 2 | 1 | 0 | |||
Balance at End of Period | 2 | 2 | 2 | |||
PECO Energy Co [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Noncurrent portion of uncollectible installment plan receivables | 8 | 9 | 8 | |||
PECO Energy Co [Member] | Allowance for Uncollectible Accounts [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 107 | [1] | 99 | [1] | 92 | [1] |
Charged to Costs and Expenses | 52 | [1] | 61 | [1] | 60 | [1] |
Charged to Other Accounts | 11 | [1],[6] | 7 | [1],[6] | 8 | [1],[6] |
Deductions | 70 | [1],[4] | 60 | [1],[4] | 61 | [1],[4] |
Balance at End of Period | 100 | [1] | 107 | [1] | 99 | [1] |
PECO Energy Co [Member] | Reserve for Obsolete Materials [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 1 | 1 | 1 | |||
Charged to Costs and Expenses | 0 | 0 | 0 | |||
Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 0 | 0 | 0 | |||
Balance at End of Period | 1 | 1 | 1 | |||
Baltimore Gas and Electric Company [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Charged to Costs and Expenses | 19 | |||||
Baltimore Gas and Electric Company [Member] | Allowance for Uncollectible Accounts [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 46 | 40 | 38 | |||
Charged to Costs and Expenses | 64 | 43 | 45 | |||
Charged to Other Accounts | 17 | [6] | 1 | 0 | ||
Deductions | 60 | [4] | 38 | [4] | 43 | [4] |
Balance at End of Period | 67 | 46 | 40 | |||
Baltimore Gas and Electric Company [Member] | Deferred Tax Valuation Allowance [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 1 | 1 | 0 | |||
Charged to Costs and Expenses | 0 | 0 | 1 | |||
Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 0 | 0 | 0 | |||
Balance at End of Period | 1 | 1 | 1 | |||
Baltimore Gas and Electric Company [Member] | Reserve for Obsolete Materials [Member] | ||||||
Movement in Valuation Allowances and Reserves [Roll Forward] | ||||||
Balance at Beginning of Period | 1 | 1 | 0 | |||
Charged to Costs and Expenses | 0 | 0 | 1 | |||
Charged to Other Accounts | 0 | 0 | 0 | |||
Deductions | 1 | 0 | 0 | |||
Balance at End of Period | $0 | $1 | $1 | |||
[1] | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively. | |||||
[2] | Includes charges for late payments and non-service receivables. | |||||
[3] | Primarily represents the addition of Constellation’s and BGE’s results as of March 12, 2012, the date of the merger. | |||||
[4] | Write-off of individual accounts receivable. | |||||
[5] | Primarily charges for late payments and non-service receivables. | |||||
[6] | Primarily charges for late payments. |
Uncategorized_Items
Uncategorized Items | |||||||
[us-gaap_StockholdersEquity] | -1,000,000 | 1,588,000,000 | 5,003,000,000 | 2,086,000,000 | -1,639,000,000 | 2,379,000,000 | 559,000,000 |